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C2-10
C2-10
Zellstoff Celgar Evidence Submission Internal Document
1 Zellstoff Celgar Pulp Mill Introduction .................................................................................. 1
1.1 Zellstoff Celgar Pulp Mill History.................................................................................. 3
2 Summary of BC Hydro Subsidy and Load Displacement Transactions................................. 4
3 Electricity Intensity Analysis:................................................................................................. 6
4 Zellstoff Celgar Pulp Mill Electricity Use:............................................................................. 9
4.1 Discussion of Mill Load: .............................................................................................. 10
4.2 Zellstoff Celgar Pulp Mill Generation: ......................................................................... 10
5 BC Pulp and Paper Electricity Use: ...................................................................................... 12
5.1 BC Pulp and Paper Electricity Cost: ............................................................................. 13
6 History of Biomass Generation in BC: ................................................................................. 14
7 Kraft Pulp Mill – Fibre/Fuel Use Overview ......................................................................... 17
7.1 Allocation of Fuel/Fibre................................................................................................ 18
7.2 Allocation of Losses ..................................................................................................... 19
7.3 Allocation of Fibre/Fuel Cost ....................................................................................... 20
7.4 Fibre/Fuel Cost.............................................................................................................. 21
7.4.1 Fuel Cost for Black Liquor Electricity Generation:.............................................. 21
7.4.2 Additional Allocated Fuel Costs for Black Liquor Electricity Generation: ......... 23
7.4.3 Black Liquor Electricity Generation Costs: .......................................................... 23
1 Zellstoff Celgar Pulp Mill Introduction The Celgar pulp mill located in Castlegar BC completed an 800 million dollar rebuild in 1993. The original Celgar mill was built in 1959 and had a 3.5 MW capacity electric turbine. This turbine failed in 1993. In 1994, an incremental 52 MW turbine was installed and became operational. During construction in 1993 and in 1994, the Celgar mill did not receive any financial subsidies from BC Hydro or FortisBC in respect of the installation of its generating assets. Nor did Celgar enter into any contractual obligations to use its incremental generation to supply its industrial load requirements. Since 1991, the Pulp and Paper Industry in BC has experienced an average capital return well below the 12% that is required to stimulate reinvestment. As a result, Zellstoff Celgar’s predecessor company filed for bankruptcy in 1998. It operated in bankruptcy for 7 years until it was purchased by Zellstoff Celgar, a subsidiary of Mercer International Inc. (“Mercer”) in 2005. Following the acquisition of the Celgar pulp mill assets from the bankruptcy trustee, Mercer has made/committed to strategic capital investments totaling 95 million dollars. Such investments have focused, to a large extent, on increasing energy production. In addition to capital expenditures Mercer has focused on developing operational best practices at Zellstoff Celgar to ensure that all assets within the mill generate appropriate returns on capital. Following a review of its cost and revenue centers, Zellstoff Celgar determined that its large existing energy generating assets had been generating negative returns. Mercer believes that the lack of revenue generation from Zellstoff Celgar’s capital intensive generating assets played a significant part in its predecessor’s 1998 bankruptcy and subsequent asset devaluation. In today's competitive environment, Zellstoff Celgar considers it necessary to maximize its revenue generation from all sources, including its energy generation assets. Since 1990 there have been 7 incremental biomass power plants installed in BC greater than 17MW in capacity (the “New Facilities”). Having regard to fuel, capital and operating costs, 6 of these installations have received either outright cash subsidies or power purchase agreements from BC Hydro at rates significantly higher than BC Hydro’s embedded cost. The only New Facility (of which Mercer is aware) that did not receive subsidies or a favourable power purchase agreement from BC Hydro was Zellstoff Celgar’s 52 MW turbine (see Part 2 hereof). Since Mercer’s acquisition Zellstoff Celgar has had discussions with both BC Hydro and FortisBC with a view to creating a level playing field between Zellstoff Celgar and its BC pulp mill competitors. From these discussions, Zellstoff Celgar quickly determined that:
1. The (Power Smart) generation subsidies were not available to Zellstoff Celgar as Zellstoff Celgar was not a customer of BC Hydro.
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2. The FortisBC (Power Sense) subsidies were different in nature to those provided by BC Hydro, focusing on demand side management rather than generation. Zellstoff Celgar requested a Power Sense grant from FortisBC to help pay for some of the 28 million dollars in upgrades that Mercer initially made, that resulted in an approximate 60 GWh levelized increase in generation output in 2007. Such request was declined, though Zellstoff Celgar did receive a small Power Sense rebate for installing some high efficiency motors.
3. FortisBC industrial power rates are significantly higher than the industrial power
rates BC Hydro charges its industrial customers.
4. While some of the FortisBC tariffs may be similar to BC Hydro’s tariffs, FortisBC operates within its own jurisdiction, and different rules exist that both disadvantage and, in certain circumstances, may benefit Zellstoff Celgar when compared to BC Hydro service area customers.
Approximately two years ago Zellstoff Celgar determined that it wished to focus on the opportunities, rather than the disadvantages, of operating in the FortisBC service area versus the BC Hydro service area. One such opportunity was identified whereby Zellstoff Celgar would purchase all of its mill load electricity requirements from FortisBC and sell all of its existing generator output to third parties. Zellstoff Celgar, on an annual basis, would buy all of its industrial load requirements on the same basis as any large mine, other pulp mill or data center that does not have its own generation capacity. Zellstoff Celgar would then sell all of its existing green biomass generation to a third party buyer allowing Zellstoff Celgar to generate appropriate revenue levels to cover the fuel, capital and operating costs of its (unsubsidized) turbine. Zellstoff Celgar reviewed the existing regulatory framework and determined that its plans fit within current rules, policies and rates and embarked upon its energy generation expansion project. Subsequently, Zellstoff Celgar was met with BC Hydro’s attempt to block Zellstoff Celgar from implementing its energy plan on the premise that BC Hydro customers are not able to freely export their self-generation, while purchasing their load requirements. BC Hydro asserts such position even though a significant number of its large industrial customers have been provided dispensation from such restrictions pursuant to load displacement arrangements that are not available to Zellstoff Celgar. In Zellstoff Celgar’s view, BC Hydro should not be allowed to indirectly govern and restrict the operations of FortisBC’s customers, particularly as such customers have not been provided access to the corollary subsidies and arrangements that BC Hydro has made available to its own customers. Zellstoff Celgar believes that BC Hydro’s discriminatory treatment places Zellstoff Celgar’s mill at a competitive disadvantage, while subsidizing BC Hydro’s industrial power customers.
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1.1 Zellstoff Celgar Pulp Mill History 1959 A subsidiary of the Celanese Corporation of America completes construction of the
Celgar pulp mill which was the first inland sulphate pulp mill in British Columbia. The Celgar pulp mill was equipped with a 3.5 MW turbine.
1979 BC Timber, part of the BC Resources Investment Corporation (BC Government), buys
the Celgar mill. 1986 Consolidated Bathurst buys the Celgar mill. 1987 Consolidated Bathurst forms a joint venture with the Chinese International Trust and
Investment Corp (CITIC) with respect to the Celgar mill. 1989 The joint venture decides to rebuild the Celgar mill. 1989 Stone Container Corp. acquires Consolidated Bathurst. 1993 The Celgar pulp mill rebuild was completed in 1993 at a cost of $800 million CAD which
included a $750 million CAD loan from the Royal Bank of Canada and National Westminster.
1993 Celgar’s original 3.5 MW turbine fails and is permanently decommissioned. 1994 Celgar’s new incremental 52MW turbine becomes commercially operational. 1998 Stone Container Corp. stated that while the mill modernization greatly improved the
operating efficiency of the mill, persistently poor market conditions for pulp have prevented the mill from reducing its outstanding debt and caused it to incur continued operating losses. Stone container informed its lenders on July 15th 1998 that it will no longer cover any of the mill’s cash shortfalls and that the Celgar mill will be unable to service its debt to lenders and as a result, will enter bankruptcy protection. The Royal Bank of Canada appointed KMPG to serve as Celgar’s receiver and the decision was made to operate the mill until such time as a buyer was found.
2005 In February 2005, Mercer buys the Celgar mill from receiver. Mercer subsequently
announced a $28 million CAD capital investment program in Zellstoff Celgar aimed at increasing pulp/energy production and reducing operating costs. Zellstoff Celgar was declined a Power Sense incentive from FortisBC for the increased generation associated with its capital investment as load displacement generation was ineligible under FortisBC’s program.
2006 In November of 2006 the capital upgrades made by Mercer were completed and Zellstoff
Celgar focused on best practices and optimizing production which continues today.
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2007 Zellstoff Celgar began discussions with FortisBC on becoming a full load customer as the mill was planning to sell all of its biomass generation to a third party.
2008 Mercer announced it was making a $55 million CAD investment in Zellstoff Celgar
which included the addition of a 48 MW condensing turbine. The investment will capitalize on excess energy produced at the Zellstoff Celgar mill, increase biomass energy production and reduce heat energy used in the mill. The increased electricity generation from this project was planned to be sold to a third party located in either BC, Alberta or the U.S. Mercer also announced a $12 million CAD upgrade to it wood chipping plant at the Zellstoff Celgar mill. In the summer of 2008, Zellstoff Celgar signed an agreement with FortisBC whereby Zellstoff Celgar would become a full load, high load factor customer and FortisBC would provide wheeling services to the BCTC interconnect to allow Zellstoff Celgar to sell all of its generation to a third party.
To date, in addition to its initial investment, Mercer has made or committed to over $95 million CAD in strategic capital upgrades at the Zellstoff Celgar mill.
2 Summary of BC Hydro Subsidy and Load Displacement Transactions
The following describes transactions entered into between BC Hydro and its customers over the past 19-year period in which BC Hydro provided subsidies or entered into load displacement arrangements with its customers supported by Heritage Power. The following summary is based upon the information and belief of Brian Merwin, Director of Strategic Initiatives of Mercer International Inc., parent company of Zellstoff Celgar, supported, in part, by public filings.
1. The Load Displacement Agreements outlined below effectively allow the respective BC Hydro customers to purchase power from BC Hydro to service their load requirements and sell all generation into the market, in some cases after expiry of an initial term. Despite Order G38-01 BC Hydro may still provide embedded cost service to such customers as such Order only provides that BC Hydro is not obligated to do so.
2. Between 1989 to present, BC Hydro has entered into Power Purchase or Load
Displacement Agreements with the following owners of new incremental 17 MW (plus) turbines:
3. A 45 MW turbine was installed at the Skookumchuk Pulp Mill, owned by Tembec Inc.,
in 2001. BC Hydro purchases the first 11 MW of generation capacity generated by the turbine at rates significantly above BC Hydro’s embedded cost for power, which effectively exempts this mill from self-supplying its load first, as it is able to purchase power from BC Hydro to meet its entire mill load.
4. A 20 MW turbine was installed by Tolko Industries Ltd. (“Tolko”) at its Armstrong mill
site. Tolko supplies the biomass boiler with wood residue from its adjacent operation and the boiler supplies low pressure steam to the adjacent mill. BC Hydro has a 20 MW
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Power Purchase Agreement with Tolko to purchase power at rates significantly higher than BC Hydro’s embedded cost of power, while at the same time allowing Tolko’s adjacent milling operations to purchase all of its mill load from BC Hydro at BC Hydro’s Industrial Power Rates.
5. A 30 MW turbine was installed at the Kamloops pulp mill by Domtar Corp. (“Domtar”)
in 2005. Domtar received a financial contribution from BC Hydro of $20 million dollars to self-supply the first 20MW of this turbine's capacity to meet mill load for a period of 10 years. After the initial 10 year period, the Kamloops pulp mill is free to sell this generation to the market and revert to purchasing the 20 MW annual generation from BC Hydro to service its load requirements. If the Kamloops facility generates greater than 20MW on its turbines in a given year, it is entitled to sell up to 10MW per hour into the market while purchasing electricity from BC Hydro.
6. A 49 MW turbine was installed at the Prince George pulp mill, owned by Canfor Pulp
Limited Partnership (“Canfor”), in 2006. BC Hydro provided Canfor with a 50 million dollar cash payment in return for agreeing to self-generate up to 390GWhrs per year from such generator to off-set BC Hydro power purchases for a term of 15 years. During such term, if Canfor generates greater than 390 GWhrs, it is free to sell such generation to the market while it is purchasing power from BC Hydro. At the end of the 15 year term Canfor is entitled to revert to purchasing the 390GWhrs from BC Hydro and will then be free to sell the output of its 49MW turbine into the market place.
7. Howe Sound Pulp and Paper Ltd. (“Howe Sound”) installed an 86 MW turbine. BC
Hydro provided a $108 million dollar interest free loan to the Howe Sound for this turbine’s installation in exchange for Howe Sound self-supplying all of this capacity to meet mill load.
8. A 65 MW EPCOR Biomass power plant in Williams Lake was built in 1993. BC Hydro
has entered into a 25 year contract to purchase biomass electricity from the EPCOR power plant at rates substantially higher than embedded costs of power.
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3 Electricity Intensity Analysis:
In British Columbia the Pulp and Paper industry processes and consumes approximately 28 million m3 of wood fibre per year when all pulp and paper mills are operating. All pulp and paper mills on Vancouver Island, the Lower Mainland, Kamloops and Castlegar purchase their wood fibre in business to business transactions from third parties at market prices. The remaining pulp and paper mills owned by Tembec, Canfor and West Fraser are integrated and acquire the majority of their wood fibre from related entities. The fibre resource in the province available to supply the pulp and paper industry is limited such that significant volumes of chips are imported from Washington, Montana and Idaho. As there is a finite volume of wood to process into pulp and paper, it is imperative to understand relative electricity intensity used in converting wood into pulp and paper.
In BC Hydro’s response to Zellstoff Celgar’s IR #1.3.7, BC Hydro provided the following: 2007 estimated mill Load of all BC Hydro Pulp and Paper Customers was 12,781,752 MWh; and 2007 actual Hydro sales to BC Hydro Pulp and Paper Customers was 8,682,752 MWh; and
In 2007 Zellstoff Celgar had a mill load of 349,275 MWh with 22,560 MWh of electricity purchases from its utility FortisBC.
In 2007 Zellstoff Celgar fiber use was 2,633,000 m3.
Intensity of Electricity Usage (Hydro Customers):2007 Units
Fibre Use - All of BC Pulp & Paper Industry 28,000,000 m3
Less: Fibre Use - Celgar Pulp Mill (2,633,000) m3
Fibre Used by BC Hydro P&P Customers 25,367,000 m3
Mill Load of BC Hydro P&P Customers 12,781,752 MWh
Total Electricity Used per m3 of Wood Consumed (BC Hydro P&P Customers)
0.504 MWh/m3
BC Hydro electricity sales to P&P Customers 8,682,752 MWhBC Hydro Electricity Used per m3 of Wood Consumed (BC Hydro P&P Customers)
0.342 MWh/m3
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Intensity of Electricity Usage (Celgar Pulp Mill):2007 Units
Fibre Use - Celgar Pulp Mill 2,633,000 m3
Mill Load of the Celgar Pulp Mill 349,275 MWhTotal Electricity Used per m3 of Wood Consumed (Celgar Pulp Mill)
0.133 MWh/m3
FortisBC Electricity Sales to Celgar 22,560 MWh
FortisBC Energy Used per m3 of Wood Consumed (Celgar Pulp Mill)
0.009 MWh/m3
Intensity of FortisBC Electricity Usage if Celgar's Entire Mill Load is Purchased from FortisBC 0.133 MWh/m3
Based on the above analysis, BC Hydro’s pulp and paper customers consume an average of 0.342 MWh of electricity for every cubic metre of wood fibre that they convert into pulp and paper. If Zellstoff Celgar required the same level of electricity intensity as BC Hydro’s pulp and paper customers, the Zellstoff Celgar pulp mill would need to purchase over 900 GWh per year of electricity based on the volume of wood it consumes. Based on its 2007 production levels, Zellstoff Celgar would only require 349 GWh per year if it purchased all of its electrical requirements from FortisBC, which translates into an energy intensity level of 0.133 MWh/m3. On an electricity intensity basis the electricity Zellstoff Celgar wishes to purchase from FortisBC is 61% lower than what BC Hydro’s average pulp and paper customer requires.
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Contrasting the Intensity of Celgar's Electricity Consumption to that of BC Hydro Pulp and Paper Customers
0.504
0.342
0.009
0.504
0.342
0.133
-
0.100
0.200
0.300
0.400
0.500
0.600
BCH P&P- Total
Electricity
BCH P&P- BC
HydroElectricity
Celgar -FortisBCElectricity
BCH P&P- Total
Electricity
BCH P&P- BC
HydroElectricity
Celgar -FortisBCElectricity
Inte
nsity
of E
lect
rical
Usa
ge
(MW
h us
ed /
m3 o
f woo
d co
nsum
ed)
Current Situation Proposed SituationCelgar as Full Load FortisBC Customer
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4 Zellstoff Celgar Pulp Mill Electricity Use: The following is a summary of Zellstoff Celgar’s electricity use for the period between 1990 and 2007.
Celgar Historic Data:
TG # 1 Output
TG # 2 Output
Annual Purchases from Fortis
Power Sales
Celgar Annual Mill Load
Natural Gas for Steam
ProductionPulp
Production (MWh/yr) (MWh/yr) (MWh/yr) (MWh/yr) (MWh/yr) (GJ/yr) (Tonnes/yr)
1990 15,949 - 114,161 - 130,110 713,923 174,235 1991 13,890 - 122,320 - 136,210 708,154 151,695 1992 10,583 - 129,746 - 140,329 1,926,553 132,570 1993 5,866 31 190,905 - 196,802 2,342,843 183,335 1994 - 236,253 98,256 - 334,509 2,187,618 356,654 1995 - 308,810 22,303 20,100 311,013 2,272,132 374,054 1996 - 287,352 28,599 25,597 290,354 2,182,835 352,173 1997 - 251,348 57,712 12,250 296,810 2,084,008 381,576 1998 - 231,310 28,306 10,985 248,631 1,859,556 295,647 1999 - 301,600 19,824 22,470 298,954 2,071,780 396,096 2000 - 278,780 31,878 17,892 292,766 3,799,135 410,414 2001 - 190,507 88,704 4,384 274,827 1,360,898 352,263 2002 - 223,970 93,702 3,948 313,724 1,038,254 402,458 2003 - 258,666 71,400 4,914 325,152 946,846 422,504 2004 - 271,326 59,220 14,028 316,518 769,525 434,117 2005 - 300,192 54,432 26,202 328,422 655,373 444,694 2006 - 290,413 61,523 22,213 329,723 629,254 438,855 2007 - 350,641 22,560 23,926 349,275 303,006 476,242
Year
Celgar Generation Supplied for Mill Load
-
50,000
100,000
150,000
200,000
250,000
300,000
350,000
1990
1992
1994
1996
1998
2000
2002
2004
2006
MW
h
Old 3.5 MW turbine decommissioned
52 MW turbine operational
Ended reliance on natural gas
Capital Project Installed
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4.1 Discussion of Mill Load: 1. The Zellstoff Celgar pulp mill provides, on a cost basis, the City of Castlegar with water.
The city of Castlegar pays Zellstoff Celgar the industrial rate for electricity. Zellstoff Celgar consumes in pumping water for city residents. On an annual basis this translates into approximately 1000 MWhs of load burden placed on the Zellstoff Celgar pulp mill. Most cities own and operate their own water pumping stations and purchase this electricity from their utility.
2. The Zellstoff Celgar pulp mill uses significant volumes of pure oxygen in its processes.
Historically, liquid oxygen was trucked from Calgary to supply the mill’s needs. When Zellstoff Celgar was purchased by Mercer it entered into a third party over the fence agreement with an oxygen supplier to build and operate an Oxygen plant adjacent to the Zellstoff Celgar pulp mill. The supplier had two options to either hook into the Zellstoff Celgar mill grid or apply for service with FortisBC. The decision at the time was to hook up to Zellstoff Celgar. This Oxygen plant currently uses approximately 1MW/h of electricity therefore having an impact on Zellstoff Celgar’s load of 8400MWhs.
Celgar Mill Load Levelized:
Operating Hours*
Celgar Annual Mill
Load City Water Services
Third Party Oxygen
Plant Levelized Mill
Load Mill Base
Load (MWh/yr) (MWh/yr) (MWh/yr) (MWh/yr) (MW)
1994 8,400 334,509 1,000 - 333,509 39.7 2005 8,400 328,422 1,000 - 327,422 39.0 2006 8,400 329,723 1,000 4,000 324,723 38.7 2007 8,400 349,275 1,000 8,400 339,875 40.5
*On average Celgar is shutdown for 15 days per year for planned maintenance
Year
If one compares Zellstoff Celgar’s “levelized” mill load during the new mill’s first full year of operation and the first three years of Zellstoff Celgar’s operation under Mercer’s ownership. Zellstoff Celgar’s mill load has only increased by 2% while Zellstoff Celgar’s pulp production over this same period has increased by 34%.
4.2 Zellstoff Celgar Pulp Mill Generation: The original Celgar mill had a 3.5 MW capacity steam turbine, which in 1993 produced 5,866MWh of electricity. In 1994, Celgar’s incremental 52 MW capacity electric turbine became operational, producing 236,253 MWh of incremental electricity. Between 1993 and 2000, the Zellstoff Celgar pulp mill maximized the generation of electricity using natural gas. In 2000, to help West Kootenay Power meet peak load needs, Celgar focused even harder on generating electricity by burning gas. Celgar’s recovery boiler takes approximately 21 GJ of natural gas to make 1MWh of electricity. At the end of 2000, with the
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rapid rise in gas prices, it was determined that burning natural gas to generate electricity was not economical. Howe Sound Pulp and Paper made a similar determination, which resulted in its idling of generation. However, as Howe Sound Pulp Mill was a BC Hydro customer, it had recourse to BC Hydro’s policies and practices. Howe Sound made a request to BC Hydro to deem a portion of its generation capacity idle which triggered commission order G-38-01. As Celgar operated in a different jurisdiction there was no reason for Celgar to seek a similar determination from BC Hydro to deem a portion of its generation as idle (so as to allow it in the future to sell it to market). Zellstoff Celgar’s potential ability to enter into arrangements directly with FortisBC to allow it to sell its full mill load made any such requirement for dispensation from BC Hydro unnecessary. This was part and parcel of Celgar operating under the FortisBC jurisdiction rather than that of BC Hydro. To provide a fair comparison of Celgar’s “green biomass generation” since the installation of its incremental turbine, it is necessary to adjust the generation output to reflect base line natural gas use. Zellstoff Celgar believes its baseline use of natural gas for start-up and mill upset situations is approximately 400,000 GJ’s. Celgar Mill Biomass Generation Levelized:
Operating Hours*
Natural Gas for Steam
Production
Levelized Natural Gas
*
Excess Gas Used in
Electricity Generation
Excess MWhs
Generated with Gas
Actual Generator
Output
Levelized Generator Output - Biomass
Levelized Biomass
Generator Baseline
(GJ/yr) (GJ/yr) (GJ/yr) (MWh) (MWh) (MW)
1990 8,400 713,923 400,000 - - 15,949 15,949 1.9 1991 8,400 708,154 400,000 - - 13,890 13,890 1.7 1992 8,400 1,926,553 400,000 - - 10,583 10,583 1.3 1993 8,400 2,342,843 400,000 - - 5,897 5,897 0.7 1994 8,400 2,187,618 400,000 1,787,618 85,125 236,253 151,128 18.0 1995 8,400 2,272,132 400,000 1,872,132 89,149 308,810 219,661 26.2 1996 8,400 2,182,835 400,000 1,782,835 84,897 287,352 202,455 24.1 1997 8,400 2,084,008 400,000 1,684,008 80,191 251,348 171,157 20.4 1998 8,400 1,859,556 400,000 1,459,556 69,503 231,310 161,807 19.3 1999 8,400 2,071,780 400,000 1,671,780 79,609 301,600 221,991 26.4 2000 8,400 3,799,135 400,000 3,399,135 161,864 278,780 116,916 13.9 2001 8,400 1,360,898 400,000 960,898 45,757 190,507 144,750 17.2 2002 8,400 1,038,254 400,000 638,254 30,393 223,970 193,577 23.0 2003 8,400 946,846 400,000 546,846 26,040 258,666 232,626 27.7 2004 8,400 769,525 400,000 369,525 17,596 271,326 253,730 30.2 2005 8,400 655,373 400,000 255,373 12,161 300,192 288,031 34.3 2006 8,400 629,254 400,000 229,254 10,917 290,413 279,496 33.3 2007 8,400 303,006 400,000 - - 350,641 350,641 41.7
*On average Celgar is shutdown for 15 days per year for planned maintenance**Levelizing adjustment is assumed natural gas used only as an auxiliary fuel
Year
Adjusting for discretionary natural gas use Celgar generated 151GWh in 1994 with its new incremental turbine. Through evolution and efficiency gains from increased pulp production Zellstoff Celgar produced 279 GWh in 2006 prior to Mercer’s capital upgrades that increased steam generation. 2007 saw a levelized increase of 70GWh increase as a result of the capital upgrades.
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5 BC Pulp and Paper Electricity Use: The Lockwood-Post Directory of Pulp Paper Mills 2006 edition is a database of all of the world’s pulp and paper facilities. The information supplied in the directory is obtained from listed companies on a voluntary basis as a result the information is not complete for all pulp and paper mills. Zellstoff Celgar has used this information to prepare the following table. BC Pulp and Paper Electricity Use:
Pulp Mill Name LocationBC Hydro Customer
Mill Annual Capacity
Annual Mill Load
Annual Electricity Purchases
Self-Supplied Electricity Comments
(tonnes) (MWh)* (MWh)* (MWh)*
Catalyst Elk Falls Cambell River YES 840,000 N/A 1,470,000 N/A
Catalyst Crofton Crofton YES 745,000 1,394,400 1,092,000 302,400 Celgar estimate based upon industry knowledge
Catalyst Powel River Powell River YES 460,000 1,668,450 1,055,950 612,500
Quesnel River Pulp Quesnel YES 332,500 731,500 731,500 - Estimate based upon 2.2MWhr per tonne of energy used in CTMP process
Catalyst Alberni Port Alberni YES 320,000 798,000 630,000 168,000
Canfor Taylor Taylor YES 220,000 588,000 588,000 -
Howe Sound P&P Port Mellon YES 605,000 932,750 465,500 467,250 Received 108 million dollar interest free loan from BC Hydro for self-generation
Tembec Chetwynd Chetwynd YES 200,000 440,000 440,000 - Estimate based upon 2.2MWhr per tonne of energy used in CTMP process
Celgar** Castlegar NO 480,000 349,275 349,275 - Celgar Energy Purchases if it buys its mill load from FortisBC
Eurocan*** Kitimat YES 442,500 428,000 286,000 142,000 Receives Tier 2 subsidy-generation revalued as Hydro's acquisition costs rise
Harmac Pulp Nanaimo YES 400,000 352,800 84,000 268,800
Mackenze Pulp Mackenzie YES 220,000 201,600 67,200 134,400
Cariboo Pulp Quesnel YES 360,000 280,000 31,500 248,500
Celgar** Castlegar NO 480,000 349,275 22,560 326,715 Celgar Actual Electricity Purchases in 2007
Canfor Pulp Intercon Prince George YES 288,000 252,000 - 378,000 Received $50 million Subsidy from BC Hydro to increase Generation by 390,000 MWh
Skookumchuck Cranbrook YES 270,000 218,400 N/A N/A Has PPA with BC Hydro allowed to buy well selling power
Northwood Prince George YES 570,000 N/A N/A N/A
Kamloops Pulp Kamloops YES 480,000 N/A N/A N/A Received $20 million subsidy from BC Hydro to increase generation
Canfor Pulp PG Pulp Prince George YES 309,000 N/A N/A N/A
*Source Lockwood Post Directory of Pulp and Paper Mills 2006 edition (note daily electricity usage multiplied by 350 days to obtain annual numbers)**Celgar's data based of 2007 results***Eurocan's numbers extrapolated from West Fraser annual report, BC Hydro's Forestry Forecasting study and assumption of 350 day per year operation.
The data that is available is able to illustrate 13 of the 26 BC pulp and paper mills that purchase electricity.
Out of the 13 mills there are only 3 mills that produce more product than the Zellstoff Celgar pulp mill.
Out of the 13 mills there are 11 that purchase more electricity than the Zellstoff Celgar pulp mill.
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If Zellstoff Celgar purchased its entire mill load requirements from FortisBC there would still be 8 facilities that purchase significantly more electricity than Zellstoff Celgar, with potentially more facilities also doing so, as 13 facilities are not accounted for in the above chart.
To provide a partial answer to Zellstoff Celgar IR 2.2.2 based upon our information:
3 BC Hydro P&P mill site customers purchased greater than 1000 GWh of electricity in 2005
4 BC Hydro P&P mill site customers purchased greater than 700 GWh of electricity in 2005
8 BC Hydro P&P mill site customers purchased greater than 400 GWh of electricity in 2005
It should be noted we do not have data or estimates for 13 of BC Hydro Pulp and Paper Customer sites.
5.1 BC Pulp and Paper Electricity Cost: PricewaterhouseCoopers with cooperation from the North American Pulp and Paper Industry prepares an annual benchmarking report on pulp mill costs. As part of this process individual mills provide their confidential cost information and in return receive a benchmarking report that compares costs of their mill compared to regional averages. One of the metrics that is measured is actual electricity costs. Electricity costs include all demand, energy, ad hoc and service fees charged on a per MWh basis. Zellstoff Celgar believes that the BC Mill top quartile is the best proxy for payments made by pulp and paper mills to BC Hydro for electricity charges, and that the average is not representative as the large price Zellstoff Celgar pays skews the BC average upwards. Zellstoff Celgar does not have the 2007 report.
Benchmarking Analysis of Actual Purchased Electricity Costs ($/MWh):2006 2005 2004 2003 2002
BC Mill Average 37.91$ 42.24$ 41.56$ 39.24$ 36.85$ BC Mill Median 37.37$ 41.27$ 40.21$ 38.67$ 37.54$ BC Mill Top Quartile 34.80$ 39.99$ 38.75$ 37.24$ 36.54$ Celgar 58.86$ 52.74$ 49.65$ 45.24$ 40.26$
The actual average costs paid by BC Hydro pulp and paper mills customers have been falling since 2005 as these customers take advantage of the stepped rate subsidy. Even though Zellstoff Celgar operates in BC, it is competitively disadvantaged by BC Hydro’s favourable rate structure given to its large industrial customers compared to the rate structure that FortisBC charges its large industrial customers.
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6 History of Biomass Generation in BC: (Last 19 years) 1989 Zellstoff Celgar pulp mill revitalization project announced, included in plans are to install
an incremental 52 MW turbine. 1989 Howe Sound Pulp & Paper receives a 108 million dollar interest free loan from BC
Hydro. In exchange for this loan Howe Sound agrees to self-supply this generation to meet its mill load. This contract according to MEMPR 1989 annual report was to supply 70% of Howe Sound’s mill load requirements.
1989 BC Hydro reaches agreement with the owners of the Williams Lake Biomass
Cogeneration plant for the installation of a 55 MW turbine. Source (MEMPR 1989 annual report).
1993 Howe Sound’s 86 MW biomass turbines becomes operational and as agreed to with BC
Hydro begins displacing mill load. 1993 Celgar’s existing 3.5 MW capacity turbine has an end of life situation and is permanently
decommissioned. 1994 The Williams Lake Biomass plant becomes operational. The turbine installed was 66
MW and not the 55 MW that was originally agreed to with BC Hydro. In EPCOR’s Annual report 2007 it states the turbine agreement had a 25 year term where BC Hydro would purchase 440 GWh per year of firm electricity at fixed prices which escalate over time. BC Hydro also agreed to purchase all incremental generation above the 440 GWh at a market rate derived price. EPCOR states on page 55 when referring to fuel cost at Williams lake that: “In general any increase in cost of fuel is flowed through to BC Hydro.”
1994 Celgar’s 52 MW capacity biomass turbine became operational. Zellstoff Celgar made no
agreements or assumed any obligations to self-generate in perpetuity. 2000 Celgar establishes an agreement with FortisBC predecessor to generate peaking
electricity through the burning of natural gas. In 2000 Celgar burns a record 3.8 million GJ’s of natural gas in 2000 to maximize electricity generation at approximately 278,000 MWhs.
2001 With rising natural gas prices Celgar determined that burning natural gas in its Power and
Recovery Boilers was uneconomical. Natural Gas usage was reduced from 3.8 million GJ’s to 1.36 million GJ’s of natural gas and annual electricity generation was idled to 190,000 MWhs.
2001 Howe Sound Pulp and Paper made similar economic decisions on burning natural gas to
generate electricity. Howe Sound reduced its natural gas usage, correspondingly reduced its generation and was outside of the parameters of its original agreement with BC Hydro
15
to displace 70% of its load with self-generation. Howe Sound subsequently requested that the BCUC declare its idled capacity as incremental and allow it to be free to sell this idled capacity to third parties while purchasing load from BC Hydro. (BCUC Order G-38-01).
2001 The Skookumchuck Pulp mill in Cranbrook BC the adjacent competitor for wood supply
installs a 45 MW turbine. BC Hydro arbitrarily assigns this installation the status of being an IPP. BC Hydro entered into an Energy Purchase Agreement with Skookumchuck to purchase the first 11 MW of capacity off of this turbine at above embedded costs rates thereby allowing Skookumchuck to sell power while purchasing from BC Hydro.
2002 Celgar continues to reduce its natural gas use in generating electricity. Celgar focuses on
increasing electrical generation ability through the use of biomass. Annual generator output increased to 224GWh.
2003 Tolko’s 20 MW biomass power plant becomes operational at its Armstrong mill site. BC
Hydro arbitrarily assigns this installation the status of being an IPP. BC Hydro entered into a purchase agreement with Tolko for the purchase of this plant’s capacity at above embedded cost rates. Tolko’s adjacent industrial complex receives steam from the plant and supplies the biomass fuel stock for its operation. BC Hydro did not require this plant to self-supply and this plant has no future obligation to self-supply. Its output is sold at market rates.
2003 Zellstoff Celgar continues to reduce its natural gas use in generating electricity. Zellstoff
Celgar focuses on increasing electrical generation ability through the use of biomass. Annual generator output increased to 259GWh.
2004 Zellstoff Celgar continues to reduce its natural gas use in generating electricity. Zellstoff
Celgar focuses on increasing electrical generation ability through the use of biomass. Annual generator output increased to 271GWh.
2005 BC Hydro with the introduction of industrial stepped rates sets Customer Base Loads
(CBL). 2005 Domtar’s 30MW capacity turbine at the Kamloops mill becomes operational. The
company enters into an obligation to self-supply 20 MW of capacity to its industrial site for a term of 10 years. After 10 years the Kamloops mill is free to sell this generation to third parties and revert back to embedded cost electricity.
2005 Mercer acquires the Zellstoff Celgar pulp mill and commits to s $28 million investment
aimed at lowering costs and increasing both pulp and energy production. Zellstoff Celgar again increases its generation output to 300 GWhrs while continuing to reduce the amount of natural gas used in the generation of electricity.
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2006 Canfor Pulp’s 49 MW capacity turbine at their Prince George Pulp mill becomes operational. The company enters into an obligation to self-supply 390 GWhrs per year to its pulp mill operations offsetting BC Hydro purchases for a term of 15 years. In exchange for this obligation Canfor received a cash payment of $49 million dollars from BC Hydro.
2006 Zellstoff Celgar’s annual generator output drops from 300GWhrs to 290 GWhrs. This
drop reflects the peak that was reached in 2005 and that Zellstoff Celgar had a fewer operating days in 2006 resulting in its generation being correspondingly lower.
2006 At the end of 2006 the capital upgrades announce by Mercer for its Zellstoff Celgar mill
were completed. FortisBC advises Zellstoff Celgar that Load Displacement does not qualify under their program.
2006 Stepped rates begin to have effect. BC Hydro pulp and paper customers incrementally
increase generation to take advantage of the financial incentive provided by Tier 1 power. 2007 In January Eurocan Pulp and Paper mill’s 17MW turbine became operational. West
Fraser stated in its 2007 annual report that the generator will supply one third of the mill’s load. Zellstoff Celgar estimates that based on an operating year of 350 days this generator would have a yearly output of approximately 140 GWh, from which Zellstoff Celgar derives Eurocan’s annual load to be 428GWh. BC Hydro allows customers to make stepped rate adjustments at one location and claim benefit at multiple sites. It is estimated that West Fraser receives Tier 2 benefit prices for all of Eurocan’s generation which effectively values this generation at $54/MWh in 2008 and in 2009 the value is adjusted up to $70/MWh. Eurocan will continually benefit from the adjustment of Tier 2 pricing.
2007 Zellstoff Celgar realized the increased energy production from its capital investment
producing an incremental 60 GWh and produced significant quantities of excess steam to justify the investment of an incremental 48 MW capacity turbine. No agreements had been made with anyone to lock this incremental generation in as being used for self-supply in perpetuity. Zellstoff Celgar reduced its natural gas usage in its boilers to 300,000GJ, achieving a 92% reduction from year 2000 levels.
2008 Mercer commits $55 million to increasing Zellstoff Celgar’s generation capacity with the
installation of an additional 48MW condensing turbine, the upgrade of its power boiler and steam savings projects which combined with Zellstoff Celgar’s current excess steam energy will provide the energy to create the incremental electricity. This project was undertaken with the order of a turbine and related equipment in April of 2008. As with Zellstoff Celgar’s past increased generation, no agreements had been made with any third parties to purchase the output of this electricity. Zellstoff Celgar intended to find third party buyers at a later date or export and sell this generation in spot markets of Alberta and the U.S.
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2008 Zellstoff Celgar submits a proposal to sell its new generation to BC Hydro in its Bioenergy Call.
7 Kraft Pulp Mill – Fibre/Fuel Use Overview To better understand how we have allocated our fiber/fuel use some familiarity of the NBSK manufacturing process is needed. The following process diagram illustrates the flow of logs and residual chips to energy and pulp production. Figure 1:
NBSK Manufacturing Process
Modern Kraft pulp mills like Zellstoff Celgar, can extract heat energy out of the wood fiber to make heat energy that is in excess of its needs without supplemental steam contributions from a power boiler. This technique extracts the highest value out of a wood resource - that being cellulose and highly valued biomass energy. Approximately 93 percent of all heat energy produced at Zellstoff Celgar’s pulp mill comes from its recovery boiler with the remaining coming from its Power Boiler. In BC there are very few mills that fit this modern configuration. Most BC mills require significant steam generation from power boilers to meet steam needs. Therefore when making comparisons to other mills in BC, Zellstoff Celgar utilizes less heat energy as a whole to manufacture pulp. As a result of this relative efficiency, Zellstoff Celgar’s fuel consumption is
18
made up of a significantly higher proportion residual chips and whole log chips versus other mills who utilize a significant quantity of hog fuel (bark/wood waste fuel) in power boilers to manufacture supplemental steam. Additionally, as a result of this efficiency, Zellstoff Celgar has very significant steam resources that can be utilized to generate electricity.
7.1 Allocation of Fuel/Fibre Figure 2
Highest Value Use of Low Value WoodBlack liquor wood chip usage
Electricity Generation
36%
Losses14%
Heat used in Pulp Mill
50%
Wood Chip Product:
Pulp47%
Black Liquor Biofuel
53%
Results of burning black liquor in pulp mill
Results of burning black liquor in pulp mill
Kraft pulp mills have the ability to extract the highest value from a wood resource, producing pulp and generating high quality green energy
Black liquor product:
** For discussion purposes only and is meant to approximate energy allocation in a pulp mill For every cubic metre (m3) of wood chips that are consumed at Zellstoff Celgar’s mill, approximately 47% of the wood chip is extracted for use in pulp production. The remaining approximate 53% is burned for energy production. Of the energy produced, 50% is used to heat pulp mill processes, with the remaining being used in the production of electricity. Pulp mills are bio-refineries separating the various components of wood into higher value products. Black liquor, created when lignin is separated from the cellulose, is a rich fuel product that has many complex chemicals that have the potential to be refined to higher value organic chemicals and plastics. Currently, standard industry practice has been to optimize energy recovery from Black Liquor within modern pulp mills. Zellstoff Celgar has a modern recovery boiler relative to other BC pulp mills and is therefore able to maximize energy production through Combined Heat & Power Cogeneration. In order to fairly allocate losses between pulp mill heat use and electricity generation we look at the differences between “conventional separate generation” and “combined heat and power generation.” Figure 3 compares these processes
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7.2 Allocation of Losses
Figure 3: Conventional Separate Generation vs. Combined Heat & Power Cogeneration:
Value of Cogeneration
5050
ELECTRICITY
HEAT AND LINE LOSSES
95
9
BOILER EFFICIENCY
LOSSES
PROCESSHEAT
POWER STATION
FUEL
1303535
COGENFUEL
189 100
CONVENTIONAL SEPARATE GENERATION
COMBINED HEAT AND POWER COGENERATION
59ELECTRICITY
ENERGY USER
BOILER FUEL PROCESS
HEAT
15
CHP EFFICIENCY
LOSSES
CO2
CO2
189 Units of fuel creates 85 units of useful energy
100 Units of fuel creates 85 units of useful energy
VERSUS
“Biomass Cogeneration supplying both electricity and heat to an industrial site will use 30 – 40 % less primary fuel than conventional generation. This
can represent a reduction of CO2 emissions of up to 50%.”
As can be seen in Figure 3, it is clear that Combined Heat and Power Generation is a superior process. Simply put, a pulp mill can utilize the lower quality heat that is not energetic enough to generate electricity. In Figure 2 (above) we have identified 14% losses. To fairly allocate these losses between pulp mill heat use and electricity generation we need to look at Figure 3 “Conventional Separate Generation” and the losses that are associated with this process. As can be seen, 95 units are lost in associated electricity generation and 9 units are lost in associated heat generation for a combined total of 104 units of losses. Electricity therefore shares 95/104 or 91.3% of cogeneration efficiency losses and pulp mill heat shares 8.7% of cogeneration efficiency losses. Based on this ratio, we allocate the 14% in losses as follows: 12.8% being allocated to electricity generation 1.2% being allocated to pulp mill heat use
As a result, Figure 4 shows how Zellstoff Celgar allocates costs between pulp production and energy production with consideration for process losses
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7.3 Allocation of Fibre/Fuel Cost Figure 4:
Cost of Electricity generation
5.5 m3 of Wood Chips
53%47%
1 tonne of pulpBlack Liquor fuel
51.2% 48.8%
Heating pulp mill
Cost of electricity generation
Pulp mill costs Generator costs Following the wood chip through the process: 47% of every m3 of wood chips consumed is converted to pulp 53% of every m3 of wood chips consumed is converted to energy
o Of the 53% energy, 51.2% of the energy is used for heating the pulp mill (27.1% of total wood costs),
o Of the 53% energy, 48.8% of the energy is used for production of electricity (25.9% of total wood costs).
Therefore, for every m3 of wood chips consumed in a pulp mill, 25.9% of it is utilized in the generation of electricity. Therefore 25.9% of all chip/whole log costs incurred at Zellstoff Celgar are allocated to generation of electricity.
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7.4 Fibre/Fuel Cost Pulp mills to make pulp and energy consume wood chips. Wood chips come from two sources:
1. Sawmill residuals: Wood chips from sawmills that are a byproduct of the lumber making process. Simply put lumber is square and logs are round, chips are the portion of log that cannot be converted into lumber. Chip production is a large volume component of the lumber making process and thus pulp mills have a symbiotic relationship with sawmills. Without pulp mills to provide a continuous off take of chips at fair market prices, sawmills would not be able to operate as they require this significant revenue stream and off-take for the large chip volumes they generate.
2. Whole Log Chips: Pulp logs are a byproduct of saw log harvesting. Typically when saw
log harvesting occurs there is a certain percentage of logs that are too low of a grade to be manufactured into lumber. These low quality logs are either sent to burn piles by the logger or are procured by pulp mills from Forest License holders as pulp wood. Pulp wood is debarked and chipped for use. The symbiotic relationship between sawmills and pulp mills also occurs in the forest as pulp mills provide an uptake for low quality logs, helping to minimize forest burn piles
Mercer and Zellstoff Celgar do not own any forest tenures or have any timber rights in the Province of British all wood is purchased at market prices in business to business transactions with third parties. The provincial government’s Forests and Range Ministry (Revenue Branch) publishes average monthly residual chip prices by community. The link to the site is as follows: http://www.for.gov.bc.ca/hva/parameters_interior.htm?2008. The prices contained in these reports are at sawmill gate and do not include transportation costs from the sawmill to the pulp mill, nor do they reflect the cost of whole log chips. October 2008 the average market price reported for white wood sawmill residual chips in the BC Southern Interior was $106/BDU or $39/m3 converted using 2.72832 m3 per bdu. For the purposes of analysis and discussion we will use a range of $39/m3 to $55/m3. This range is meant to capture varying market prices for residual chips, higher cost whole tree chips and the associated transportation costs. The Zellstoff Celgar pulp mill on a yearly basis has operated at both cost levels in recent history.
7.4.1 Fuel Cost for Black Liquor Electricity Generation: Utilizing the allocation accounting principles discussed above a $/MWh range has been established.
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Costs of Black Liquor Electricity Generation (Low Range)Cost
Average Price / m3 of wood chips 1.00 m3 39.00$
Wood chips used to make 1 tonne of pulp 2.60 m3 101$ Wood chips used to make Black Liquor 2.93 m3 114$
Total Wood chips used in NBSK process 5.53 m3 216$
Value of Black Liquor produced 1.87 MWh 114$ Percentage used to heat pulp mill 51.2%Cost of Black liquor used to heat pulp mill 0.96 MWh 59$
Percentage used for electricity generation 48.8%Cost of Black Liquor used for electricity generation 0.91 MWh 56$
Cost of Black Liquor to generate 1MWh of eletricity 1.00 MWh 61$
Costs of Black Liquor Electricity Generation (High Range)Cost
Average Price / m3 of wood chips 1.00 m3 55.00$
Wood chips used to make 1 tonne of pulp 2.60 m3 143$ Wood chips used to make Black Liquor 2.93 m3 161$
Total Wood chips used in NBSK process 5.53 m3 304$
Value of Black Liquor produced 1.87 MWh 161$ Percentage used to heat pulp mill 51.2%Cost of Black liquor used to heat pulp mill 0.96 MWh 83$
Percentage used for electricity generation 48.8%Cost of Black Liquor used for electricity generation 0.91 MWh 79$
Cost of Black Liquor to generate 1MWh of eletricity 1.00 MWh 86$
51.2%
48.8%
Volume
51.2%
48.8%
Volume
With a fibre cost range of $39 to $55 per m3 the fuel cost to generate one MWh of electricity is between $61 & $86 per MWh. A key point to recognize is that simple physics apply here because whether Black Liquor is being burned to make a MWh of electricity or a Stand Alone biomass plant burns wood to make a MWh of electricity the same volume of wood equivalent is needed to make a MWh in each case. The key difference between the Stand Alone Biomass plant and the Black Liquor fired pulp mill is that a pulp mill is able to create a value added product by taking low value wood and extracting the cellulose component out of it before burning it as opposed to a stand alone power plant simply burning all of the wood that it brings in with no value added production.
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7.4.2 Additional Allocated Fuel Costs for Black Liquor Electricity Generation:
Costs that need to be allocated to generating electricity include: Maintenance (TG, Recovery Boiler, Piping, pumps, fuel handling etc. Property Tax (Allocation of costs associated to generating assets
including recovery boiler) Personnel (Steam plant, fuel handling) Administration (Reasonable allocation based on size of generation
assets) Depreciation on the associated equipment
Approximate Operating Costs for pulp mill electricity generation: $25 / MWh
Note: According to EAO public documents the Mackenzie Green Energy Biomass Plant states on page 57 of its submission that estimated non-fuel operating costs will be 17.5 million dollars per year or $31/MWhr. It is reasonable to assume pulp and paper generating facilities would have a similar cost.
7.4.3 Black Liquor Electricity Generation Costs: To displace industrial power purchased from FortisBC, the Zellstoff Celgar pulp mill incurs an allocated cost of $86 to $111 per MWh depending on the market price of wood. This cost does not include any return on capital. The replacement cost of the Zellstoff Celgar pulp mill’s generating assets which include its power boiler and recovery boiler is approximately 325 million CAD. Applying the weighting established in Figure 4 on the associated steam generation assets and including the replacement cost of the electric generator it would be reasonable to expect electricity generation should provide a return on capital on approximately 105 million CAD of replacement cost assets, if one applied the guaranteed rate of return of 8% that regulated utilities are able to receive these assets should generate a return to its shareholder of $8.4 million per year or generate a return of approximately $24/MWh of electricity generated.
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Black Liquor Electricity Generation CostsLow ($/MWh) High ($/MWh)
Cost of Black Liquor to generate 1MWh of electricity 61$ 86$ Operating Costs for pulp mill electricity generation 25$ 25$ 8% Return on Capital Invested 24$ 24$
Total Generation Cost ( $ / MWh) 110$ 135$
Cost to purchase industrial power from FortisBC ($ / MWh) 49$ 49$
Celgar Gain / (Loss) per MWh generated to displace purchased power from FortisBC (61)$ (86)$
Accounting for Zellstoff Celgar’s allocated cost approximation at two different fuel costs and a reasonable return of capital, the Unit Energy Cost (UEC) for electricity currently generated by Zellstoff Celgar is in a range of $110 to $135 per MWh. It should be noted that this cost is similar to the levelized range of $104 to $158 per MWh that BC Hydro has estimated in its 2008 Long Term Acquisition Plan for biomass electricity. See BC Hydro response to Zellstoff Celgar IR #1.14.1
IN THE MATTER OF
BRITISH COLUMBIA HYDRO AND POWER AUTHORITY 2004/05 to 2005/06 Revenue Requirements Application
and
BRITISH COLUMBIA TRANSMISSION CORPORATION
Application for Deferral Accounts
October 29, 2004
BEFORE:
Robert H. Hobbs, Chair Lori Ann Boychuk, Commissioner Murray P. Birch, Commissioner
EXECUTIVE SUMMARY
In December 2003 BC Hydro applied to the BCUC for an order to increase domestic rates by 7.23
percent effective April 1, 2004 and again by 2 percent effective April 1, 2005 based upon BC Hydro’s
then current financial information. In April 2004 BC Hydro filed a REU seeking an additional 1.67
percent increase for 2004. The request for a 2 percent rate increase for 2005 was withdrawn.
BC Hydro also applied-for:
• revenue requirements and bundled service rate increase;
• a reduction in WTS rates;
• approval of deferral accounts; and
• approval of the REAP.
In December 2003 the BCTC filed an application with the Commission for an order to establish four
deferral accounts to be effective April 1, 2004. The Commission determined that the BCTC Application
should be heard at the same time as BC Hydro’s Application and there would be one record for both
Applications.
Revenue Requirements
BC Hydro’s rates have been legislatively frozen since 1996 and have not been increased since 1993.
Significant changes to BC Hydro’s organizational structure have been made since 1993 including:
• implementation of a “line of business” internal management structure;
• the creation of BCTC, independent of BC Hydro;
• the transfer to BCTC of certain operating and planning responsibilities; and
• BC Hydro agreements with ABS to outsource certain back-office functions to the private sector.
Since 1993, BC Hydro’s energy and capacity requirements and OMA expenses have increased, but were
offset by higher trade revenues and reduced financing costs. BC Hydro’s ratepayers have benefited,
however, on a net basis through effective rate reductions of 14 percent in real terms since 1993.
(ii)
To explain the need for a rate increase, BC Hydro stated that domestic load has now grown beyond the
capability of its low cost Heritage Resources and significant cost pressures are expected in the next two
years to maintain reliability and safety. Many components of BC Hydro’s system are nearing the end of
their useful lives and reliability has suffered in recent years.
Commission Findings
The Commission Panel concluded that BC Hydro has established that a one-time significant increase in
revenue requirements is needed in order to earn its allowed rate of return, but also expects BC Hydro to
manage future rate increases in the context of inflation. The Commission Panel approved BC Hydro’s
OMA and capital revenue requirement subject to specific directions.
The Commission Panel accepted BC Hydro’s proposed criteria for determining the appropriateness of
deferral accounts but concluded that risk/reward considerations are also relevant to this determination.
The Commission Panel approved the deferral accounts requested by BC Hydro and BCTC, with the
exception of the distribution emergency cost element of BC Hydro’s NHDA.
BC Hydro filed its 2004 IEP for acquiring the necessary long-term demand-side and supply-side
electricity resources, and its REAP, which identified BC Hydro’s proposed short-run investment in
specific energy acquisitions, capital expansion projects or DSM initiatives.
The Commission Panel concluded that BC Hydro must provide a meaningful level of review of resource
options with stakeholder and Commission input. To this end, the Commission Panel accepted BC
Hydro’s revised regulatory review proposal including the filing and review of an ROR. The
Commission Panel concluded that the essential elements of the ROR should include identification of
resource types with target ranges for energy and capacity and an expected unit energy cost range for
each resource type. The Commission Panel also concluded that the 2004 IEP is not susceptible to
meaningful review at this time.
(iii)
The Commission Panel accepted certain changes in depreciation rates requested by BC Hydro except for
the accelerated depreciation of the Burrard Generating Station and distribution transformers. The
Commission Panel also concluded that a 10-year amortization period is appropriate for expenditures on
water use plans and First Nations negotiations.
Absent a specific direction from the Provincial Government, the Commission Panel applied normal
regulatory principles and concluded that it is appropriate to order a variance from GAAP and required
that the F2004 balance in the FRSR account remain as a liability to be utilized for dismantling costs that
are incurred in F2005 and beyond.
Power Smart is BC Hydro’s demand-side management initiative. The Commission Panel approved all
Power Smart expenditures in the REAP during the test period with the exception of the Load
Displacement program. The Commission Panel established reporting requirements and specific energy
saving hurdles with respect to allowing future expenditures on the Power Smart program.
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6.7 Capital Expenditures
Introduction
BC Hydro and BCTC total Capital Budgets for F2004 to F2006 are listed in Exhibit B1-96, which is an
update of Table 11-2 in the BC Hydro Application. Table 11-2 as updated is reproduced in Table 6-6
below.
Table 6-6: Capital Expenditure Forecast, F2004 to F2006
Expenditure Category (Note 1) Fiscal 2004 Fiscal 2005 Fiscal 2006 ($ millions) S G Total S G Total S G Total
Generation Hydro 95 22 117 96 13 109 123 12 135 Generation Thermal 6 33 39 3 0 3 3 0 3 Transmission – Lines (Note 2) 71 16 87 41 9 50 44 12 56 Substations (Note 2) 34 37 71 45 80 125 53 150 203 Distribution 75 118 193 84 123 207 86 130 216 Computers 65 2 67 41 2 43 50 4 54 Land & Buildings 10 0 10 8 0 8 6 0 6 Surveys & Investigations (including Aboriginal Negotiations)
9 0 9 10 0 10 5 0 5
Vehicles 21 0 21 17 0 17 19 0 19 Power Smart 0 116 116 0 105 105 0 94 94 BCTC (Note 3) 12 0 12 47 0 47 0 0 0 Other 27 0 27 18 0 18 5 0 5
Gross Expenditures 425 344 769 410 390 800 394 595 989 CIA – Specific 0 (8) (8) 0 (8) (8) 0 (9) (9) CIA - Recurring (3) (37) (39) (4) (38) (42) (4) (41) (45)
Net Expenditures 422 299 722 406 344 750 390 545 935
Notes: 1. S = Sustaining Capital Expenditures; G = Growth Capital Expenditures;
Capital expenditures listed in the Table above do not include expenditures for VIGP/GSX, which have been given separate treatment.
2. BCTC has responsibility for planning and obtaining approval for transmission and substation expenditures required to allow BC Hydro to serve its customers.
3. Expenditures are for BCTC – owned assets: Business Support Systems, Control Centre, Lands, Buildings, Tools and Equipment. BCTC’s updated Capital Plan (May 2004 Filing, Exhibit C23-11) shows that these figures have now been revised to read $45 million and $56 million for F2005 and F2006, respectively.
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Sustaining Capital refers to investments such as equipment replacements made to existing infrastructure
to continue the current level of service. Growth Capital refers to investments required to expand service
capabilities due to load growth or specific customer request.
BC Hydro stated that its capital planning approach for Sustaining versus Growth Capital was to ensure
emphasis was placed on sustaining the capability of the ageing electric system (Exhibit B1-7, BCUC IR
1.16.17(a)). BC Hydro further advised that the drivers for sustaining capital expenditures include:
reliability, risk mitigation, regulatory compliance, environmental compliance and improvements, safety
compliance and improvements, and social requirements.
6.7.1 Generation Capital Expenditures
Exhibit B1-8, BCUC IR 2.195.5, Schedule D1-1 at page 2 as revised on April 2, 2004 reproduced in part
as Table 6-7 provides information on capital additions for Generation (Heritage Assets):
Table 6-7: Capital Additions (Heritage Assets)
F2003 F2004 F2005 F2006 Plan Actual Plan Estimate Plan Plan
Sustaining 119.7 114.9 157.0 120.0 116.4 137.4 Growth 146.8 134.4 75.7 54.6 71.4 204.1 Deferred Capital - - - - - - Total Capital Additions 266.5 249.3 232.7 174.6 187.8 341.5 CIA - (5) - - - - Total Net Capital Additions 266.5 244.3 232.7 174.6 187.8 341.5 Less: GSX/VIGP (58) (193)
Adjusted Total 129.8 148.5 (GSX/VIGP costs are calculated as the difference between Generation Thermal in Table 11-2 (Exhibit B1-1, p. 11-2) and Generation Thermal from the REAP table) (Exhibit B1-23, p. 2). An examination of the capital plan in the Application (Exhibit B1-1, p. 5-10, Table 5-7), indicates that
for F2005, 43 percent of the Generation capital expenditure is allocated to facilities, while 34 percent is
expended on dam safety, and 11 percent on Resource Smart projects. Similarly, the F2006 figures show
that 53 percent is allocated to facilities, 30 percent for dam safety and 8 percent for Resource Smart
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projects. The remaining expenditures relate to costs for environmental sustainability and aboriginal
negotiations as well as IT.
6.7.1.1 Rate Impacts
As an illustrative example to show the relative rate impacts of the proposed capital budgets and based on
BC Hydro’s assumptions in Exhibit B1-61 (including an average life expectancy of 50 years) the impact
on the income statement per year of a capital expenditure of $13 million would be approximately $1
million. Based on this approximation the impact on rates from budgeted capital expenditures for the
years F2005 and F2006 is calculated to be approximately $10 million and $11.5 million. Exhibit B1-64
states that the impact of a $25 million reduction in costs would be approximately a 1 percent rate
reduction. Using this approximation, the impact of capital budgets for F2005 and F2006 would be a 0.4
percent and 0.46 percent rate increase, respectively.
6.7.1.2 Facilities
The capital expenditures earmarked for facilities are primarily used to sustain the generating capability
of existing equipment. This is illustrated in Figure 5-2, page 5-9 of Exhibit B1-1. The expenditures are
spread over a large number of small projects throughout the province.
6.7.1.3 Dams and Dam Safety
Generation is responsible for the management and safety aspects of the 75 hydroelectric dams in the
system. The dams are managed in accordance with the provisions of the Provincial Water Act and the
associated Dam Safety Regulations, under the auspices of the Comptroller of Water Rights. BC Hydro
has incorporated the Canadian Dam Association 1999 “Dam Safety Guidelines” into its dam safety
program, as well as the International Commission of Large Dams Bulletins that represent international
practices (Exhibit B1-1, p. 5-42).
105
BC Hydro stated that its dam risk management process includes surveillance, periodic comprehensive
dam safety reviews, identification and prioritization of dam safety issues, dam safety investigations and
capital improvements when required. Comprehensive Dam Safety reviews of each dam are conducted
every 5 to 10 years by independent external senior engineering consultants.
BC Hydro advised that it has instituted the use of Automatic Data Acquisition Systems for dam
surveillance. Therefore, an updated instrumentation database called “Dam Smart” has been
implemented to facilitate the efficient and comprehensive evaluation of data and identification of
anomalous instrumentation readings.
The dam safety budgets for F2005 and F2006 as shown in Tables 5-25 and 5-26 of Exhibit B1-1, page
5-41 are partially reproduced below in Table 6-8 have increased 33 percent and 35 percent respectively,
over F2004.
Table 6-8
$million F2004 F2005 F2006
OMA 4.2 4.3 4.3
Capital > $2 million 27.2 37.5 38.1
Total 31.4 41.8 42.4
(Note: The figures for capital projects for F2005 and F2006 only include those projects with total costs over $2 million).
6.7.1.4 Resource Smart Projects
Resource Smart projects are those projects which provide economic energy gains at existing BC Hydro
facilities. These projects are evaluated against the cost of new supply and their implementation costs are
included with Generation’s overall Capital Plan.
For the test years, capital will be expended on 11 Resource Smart projects yielding energy gains of
104 GWh and 31 GWh in F2005 and F2006, respectively (Exhibit B1-1, p. 5-33).
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6.8 REAP
The REAP contains the following elements:
• Capital Expenditure Forecast for F2005 and F2006;
• Action Plan for F2005 to F2008;
• Contracted Energy Purchase Expenditures for F2005 to F2008; and
• Demand Side Management Expenditure Forecast for F2005 and F2006.
The capital expenditure forecast discussed in Section 2 of the REAP, includes all of BC Hydro’s
forecasted capital expenditures required to serve its customers (Exhibit B1-23, Table 1, p. 2). The
supporting documentation for the capital expenditures in Table 1 is found in Chapters 3 through 9 of the
BC Hydro Application.
The Action Plan discussed in Section 3 of the REAP, is composed of four main categories: continuance
of the current programs; new projects and initiatives; future resource additions requiring near-term
evaluations; and planning and portfolio management. It also contains a contingency plan which presents
the steps BC Hydro will take to manage risks and uncertainties (Exhibit B1-23, pp. 3, 10).
Section 4 of the REAP outlines the contracted energy purchase expenditures and lists the corresponding
energy for the committed EPAs (Exhibit B1-23, Table 2, p. 11).
The DSM expenditure forecast (Section 5 of the REAP) shows the revenue requirement for F2005 and
F2006 that flows from the Power Smart expenses and capital expenditures to F2006 (Exhibit B1-23,
Table 4, p. 12). The supporting documentation for these expenditures is found in Chapter 4, Section 2
and Chapter 8, Section 1 of Exhibit B1-1.
BC Hydro’s specific requests for approval and directions related to the REAP are discussed below as
well as project investigation costs contemplated in the REAP.
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6.8.1 BC Hydro’s Specific Requests for Approval/Directions
In its Final Argument, BC Hydro requests the Commission to determine that:
(i) the expenditures made pursuant to existing Energy Purchase Agreements are in the public interest and ought to be recoverable in rates (BC Hydro Argument, p. 87);
(ii) committing to acquire an additional 400 GWh through an energy call, conducted generally in accordance with the procedures employed in previous energy calls and in a way that ensures a level playing field between all bidders in the process, is a prudent action that should be approved and that any expenditure commitments made pursuant to that energy call should be recovered in future rates, provided that BC Hydro has filed the EPAs with the Commission and the Commission is satisfied that their individual terms comply with the framework established by the energy call (BC Hydro Argument, p. 88);
(iii) with respect to other section 71 filings, the Commission should send a clear signal that it will only require a review of individual contracts in exceptional circumstances (BC Hydro Argument, p. 92); and
(iv) there should be no further inquiry into whether the specific expenditures contemplated both of a capital nature and with respect to DSM are prudent and that those aspects of the REAP should be recovered in rates (BC Hydro Argument, p. 87).
Further details of the above items follow:
6.8.1.1 Filed Energy Purchase Agreements
With respect to resource acquisitions, the REAP elaborates some portions of the cost of energy chapter
in the Application, but it also encompasses those commitments which are anticipated to be made during
the REAP period (i.e., the next four years), whether or not they result in expenditures by BC Hydro in
that period (BC Hydro Argument, p. 86).
A summary of the energy supply costs arising from EPAs in the test periods is found at Table 4-3,
Exhibit B1-1, Chapter 4, Section 3, pp. 4-9 to 4-15. Both EPAs contracted before F2001 and since
F2001 are described. Four energy calls have been conducted since F2001:
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• 2000 request for expression of interest for green energy which resulted in three signed agreements;
• 2001 green energy call which resulted in 18 small projects and three large projects entering into agreements;
• 2002 customer based generation call which resulted in five bidders signing agreements; and
• 2002 green power generation call which resulted in 16 bidders entering into agreements.
The pricing for each contract is confidential, resulting from the 2000 request; however, according to BC
Hydro, at or below BC Hydro’s estimate of long-term electricity prices on a levelized basis. The
levelized unit energy cost for the other three calls, expressed in 2003 dollars, is $51/MWh (small
projects)/$48/MWh (large projects), for the 2001 Green Energy Call, $54/MWh and $51/MWh,
respectively, for the 2002 calls (Exhibit B1-1, pp. 4-12, 4-15). These four calls have expected deliveries
of 425 GWh in F2004, 937 GWh in F2005 and 1,056 GWh in F2006 for a grand total of 2418 GWh .
EPAs related to these calls were filed with the Commission on October 21, 2003 (Exhibit B1-3),
January 13, 2004 and April 8, 2004 (Exhibit B1-26). By Orders No. E-10-3 dated December 24, 2003,
E-1-04 dated March 17, 2004 (Exhibit A-2) and E-2-04 dated July 14, 2004, the EPAs were accepted as
filed as energy supply contracts pursuant to section 71 of the Act.
As noted, these EPAs were referred to in the Application and the REAP and BC Hydro’s filings with the
Commission were made part of the record of the proceeding. No parties commented or expressed
concerns related to these EPAs or the costs associated therewith in relation to the test period.
Commission Findings
The Commission Panel approves the costs for F2005 to F2008 associated with energy purchase
agreements, as identified by BC Hydro in its REAP (Exhibit B1-23, Table 2, p. 11).
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6.8.1.3 Direction re Section 71 Energy Purchase Agreement Filings
BC Hydro believes that the Act does not contemplate, nor does efficient regulation require, contract-by-
contract approval with respect to resource acquisition expenditures (BC Hydro Argument, p. 87; Exhibit
B1-9, Elton Directive Evidence, p. 4). BC Hydro compares section 71 EPA filings with the CPCN
process contemplated by section 45 of the Act and concludes that the Commission is intended to
intervene and conduct public reviews only by exception (BC Hydro Argument, pp. 89-90).
BC Hydro submits that the REAP process allows the Commission to be apprised of proposed EPAs
before they are issued and that individual EPAs ought only to require review where they are not on their
face value within the scope of a previously approved acquisition plan or the Commission has reason to
believe that the manner in which they were entered into was inconsistent with its expectations when it
approved the REAP of which they were a part (BC Hydro Argument, pp. 90-91).
The IPPBC has no objection to a timely Commission contractual review before BC Hydro initiates a
competitive bidding process and would welcome the opportunity to discuss issues such as flow-through
of future tax increases, liquidated damage provisions, non-refundable performance fees, pricing, length
of term, green premiums, but not after a contract has been executed. The IPPBC suggests that any
review of contracts between IPPs and BC Hydro should be upfront and not at the end of the BC Hydro
competitive bidding process (IPPBC Argument, p. 49). IPPBC notes that even with the benefit of an
executed contract, a significant number of projects will not pass the ‘finance market’ test and states that,
for IPPs, this is the ultimate external review process.
Commission Findings
The Commission Panel recognizes that the appropriate regulatory review of an executed EPA awarded
following a competitive process needs to be determined with consideration given to transaction costs
and the need for the parties to the contract to proceed as efficiently and expeditiously as possible. In
most circumstances, the competitive process should be sufficient to establish that the awarded contract
was the most cost-effective bid. The REAP should establish that each RFP is in the public interest and
that EPAs awarded pursuant to the terms of the RFP will be cost effective compared to other
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alternatives. The Commission Panel also recognizes the views of the IPPs that it is essential that they
learn as early as possible where there is significant regulatory concern with respect to any contracts they
are entering into with BC Hydro.
The Commission Panel encourages BC Hydro to file pro forma contracts with the Commission for
comment prior to the commencement of a competitive process, where practicable. In any case, if BC
Hydro desires an efficient and effective regulatory process it is incumbent upon BC Hydro to design its
competitive processes so that there is a reasonable opportunity for the Commission to comment on the
terms and conditions of EPAs prior to the awarding of contracts.
6.8.1.4 Capital and DSM Expenditures
With respect to capital expenditures, BC Hydro states that the REAP simply recasts Chapter 11 of the
Application and the explanations contained in the chapters describing each of the lines of business in
connection with those expenditures. Similarly, the REAP identifies DSM expenditures which are more
fully described in the discussion of Power Smart in the Application (BC Hydro Argument, p. 86).
In the context of this particular hearing, BC Hydro argues that the specific expenditures contemplated
both of a capital nature and with respect to DSM generally have been fully vetted through the
Application and those aspects of the REAP should be approved for future recovery in rates without
further inquiry into whether those specific expenditures fully described and contemplated for the test
years are prudent (BC Hydro Argument, p. 87).
Commission Findings
The Commission Panel finds that there is a sufficient record to allow the Commission to make
certain determinations with respect to the capital and DSM expenditures contemplated in the
REAP.
With respect to capital expenditures, the Commission Panel considers that this proceeding has provided
parties with an opportunity to challenge and question the applied-for capital expenditures in the
Application and supporting documentation, and that a further review process is not required.
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The supporting information for the capital and DSM expenditures and contracted energy purchase
expenditures form part of the material filed with the Revenue Requirement Application (Exhibit B1-23,
p. 1). The specific components of the applied-for capital and DSM expenditures are considered further
in Chapter 9 of this Decision. Project investigation costs included in the REAP are considered below.
6.8.2 Project Investigation Costs
Section 3.2 of the REAP outlines “New Projects and Initiatives” including in respect of BC Hydro
Generation – Revelstoke 5 and Mica 5.
Section 3.3 of the REAP outlines “Future Resource Additions Requiring Near-Term Evaluation”
including in respect of “new supply options”, a proposal to maintain the Peace River Site C project as an
option for F2015 (Exhibit B1-23, p. 8).
6.8.2.1 Revelstoke 5 and Mica 5
The REAP Action Plan (Exhibit B1-23, p. 6) includes Resource Smart capacity additions for Revelstoke
5 and Mica 5, and mentions the preservation of a 2009 in-service date for one of these projects.
In testimony, Generation stated that Revelstoke 5 was the more economical choice and would be
considered first for development and that additional expenditures will be incurred to investigate these
projects and maintain in-service capability by 2009 (T19: 3369-3372). Investigation expenditures are
estimated to be $1.2 million and $6.5 million for F2005 and F2006, respectively.
Mr. Wait suggested a thorough cost analysis be completed before decisions are made regarding the
installation of additional generators at Revelstoke and Mica. Mr. Wait felt that work to firm up the cost
and schedule for Site C should proceed (Wait Argument, p. 9).
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9.0 DEMAND-SIDE MANAGEMENT POWER SMART
9.1 Introduction
Power Smart is BC Hydro’s DSM initiative. The first significant DSM program was launched in 1989
but it was ramped down during the 1995-1998 period. It was not ramped up again until 2001 when BC
Hydro re-launched what is now called Power Smart 2 (T6: 705-707). The total Power Smart 2
investment of approximately $690.6 million is found in the Power Smart 10-Year Plan (Exhibit B1-2,
Tab I, Table 4.5).
The Application identifies Power Smart as one of the most significant cost drivers over the test period.
During the rate freeze between 1996 and 2003, DSM programs were not subject to BCUC review.
Therefore, this proceeding is the first opportunity for the BCUC to comprehensively review Power
Smart programs.
Ms. Van Ruyven of BC Hydro testified that the 10-Year Plan acts as a contextual document to
understand the expenditures in the two-year test period and that BC Hydro is not asking for approval of
the 10-Year Plan or the expenditures in that plan as filed in this Application (T7: 880). However, in
Argument, BC Hydro requests approval of the 10-Year Plan pursuant to subsection 45(6.1)(c) and
subsection 45(6.2) of the Act (BC Hydro Argument, p. 113). During the oral phase of argument, BC
Hydro advised that the resource options presented in the IEP would continue to include Power Smart.
Further, that the annual filing of REAP would give the Commission an opportunity to review the Power
Smart programs (T22: 4155; T23: 4200).
The reduction in energy requirements, costs and rate impact of the first four years of the 10-Year Plan
are summarized in Table 9.
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Table 9 A Summary Of Power Smart Costs, Energy Savings and The Impact On Revenue Requirements
F2003 F2004 F2005 F2006 Source
Energy Savings (GWh) n.a. 280 928 1,375 Exhibit B1-1, Table 4-11
OMA Amortization Costs Total ($m)
12.8 24.9 37.7
19.1 24.3 43.4
22.6 31.0 53.6
22.4 36.5 58.9
Exhibit B1-1, Table 4-2; Exhibit B1-7, BCUC IR 1.21.1 Table 1
Deferred Capital Expenditures ($m)
44.3 118.4 115.0
62.7 (actual)
106.5 95.4 Exhibit B1-1, Table 8-4; Exhibit B1-2, Tab I, Table 4.5;
Exhibit B1-197, p. 12
Rate Increment ($/MWh) n.a. n.a. 0.10 0.19 Exhibit B1-8, BCUC IR 2.144.1, Table 1
Residential Rate Impact (%)
n.a. n.a. 0.18 0.33 Exhibit B1-8, BCUC IR 2.144.1, Table 2
n.a.: not available The capital funding requirement to deliver Power Smart programs was $44.3 million in F2003 and BC
Hydro predicts an increase of capital expenditures to approximately $100 million a year for F2005 and
F2006 (Exhibit B1-1, Table 8-4). The current level of capital investment in Power Smart represents
around 4.5 percent of domestic revenues (Exhibit A-43). BC Hydro forecasted about $115 million in
capital expenditures for F2004 but actual expenditures recorded were $62.7 million (Exhibit B1-2, Tab
I, Table 4.5; Exhibit B1-197, p. 12; JIESC Argument, p. 30).
In this Application BC Hydro categorizes the amortization costs associated with Power Smart into two
groups: Power Smart Before F2002 and Power Smart From F2002. The OMA costs are greater than
$20 million for each of the two test years (Exhibit B1-1, Table 4-2; Schedule D-3, p. 2-84).
DSM costs increased from F1994 to F2006 by an average of 6.6 percent per year (Exhibit B1-7, BCUC
IR 1.21.1). The rate increment associated with the Power Smart portfolio is $0.10/MWh in F2005 and
$0.19/MWh in F2006. The residential rate impact is 0.18 percent for F2005 and 0.33 percent for F2006
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(Exhibit B1-8, BCUC IR 2.144.1, Tables 1 and 2). The average rate impact over the course of the
programs is 0.26 percent (Exhibit B1-166).
Among the major electric utilities that are active in DSM in Canada, BC Hydro expects to spend
between 3.4 percent to 3.9 percent of domestic revenues on capital investments compared to 0.4 percent
for Hydro Quebec and 2.1 percent to 2.4 percent for Manitoba Hydro. BC Hydro’s incremental savings
from DSM will be around 1.0 percent of domestic energy sales, compared to 0.2 percent from Hydro
Quebec and 0.3 percent for Manitoba Hydro (Exhibit A-42; Exhibit A-43). BC Hydro commented that
the level of activity in DSM is not driven by rates although as one of the three utilities with the lowest
rates in North America, BC Hydro needs incentives to get customers to move to DSM (T13: 2184).
Following this introductory section, the major issues with respect to DSM are considered:
• Energy Savings Target;
• Screening Tests;
• Load Displacement Projects;
• Evaluation of Energy Savings;
• Power Smart Costs; and
• Regulatory Review For Power Smart.
9.2 Energy Savings Target
The current Power Smart energy savings target is based on the CPR Update. The CPR Update focuses
on hard-wired electricity efficiency potential rather than behavioural change.
The CPR Update estimated: (1) a reference case to project increases in electricity consumption that
includes conservation that would occur without utility programs like Power Smart; (2) Economic
potential energy savings if the Cost of Conserved Energy is less than or equal to six cents per kilowatt-
hour; and (3) Achievable Potential which is the proportion of the savings identified in the Economic
Potential Forecast that could realistically be achieved within the study period. From the Achievable
Potential, the Most Likely Achievable Potential and the Upper Achievable Potential efficiency savings
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are estimated (Exhibit B1-2, Tab H, pp. 3-6). Findings from the CPR Update were not contested during
the public hearing.
The Power Smart programs are expected to result in savings in gross system energy requirements of 928
GWh and 1,375 GWh (including line losses) for F2005 and F2006 (Exhibit B1-1, Table 4-11; Exhibit
B1-7, BCUC IR 1.52.2). At the end of the 10-Year Plan (F2012), the savings are expected at 3,515
GWh per year. BC Hydro testified that the 10-Year Plan is not scalable because a plan with a different
overall target or weighting by sector would require a different level of investment, and that participation
and support by customers, retailers and trade allies cannot be turned on and off (Exhibit B1-81, 2.0).
Respectively in F2005 and F2006, Power Smart savings in gross system energy will account for 1.7
percent (928/55,375) and 2.4 percent (1,375/56,180) of reference load, and 14 percent (928/6,594) and
20 percent (1,375/6,995) of purchases. By the end of the 10-Year Plan, energy savings percentage
shares will reach 5.7 percent (3,515/61,620) of reference load and 36 percent (3,515/9,716) of purchases
(Exhibit B1-1, Table 4-11).
The total portfolio energy savings at the customers’ meter in the 10-Year Plan (2002/03 to 2011/12) are
3,618 GWh, which is made up of 2,145 GWh (59 percent) from the Industrial Sector, 754 GWh (21
percent) from the Commercial and Government Sector, and 719 GWh (20 percent) from the Residential
Sector (Exhibit B1-2, Tab I, pp. 13, 15).
Mr. Tim Woolf, on behalf of the Sierra Club, concluded that the Power Smart programs have targeted
only 85 percent of total savings identified in the CPR Likely Achievable Potential (Exhibit C27-6,
BCUC IR 3.2, Revised Table 3). The Sierra Club recommends that BC Hydro should pursue all the
savings identified in the Most Likely Achievable Potential and pursue at least a portion of the savings
identified in the CPR Update as the Upper Achievable Potential (Exhibit C27-6, BCUC IR 3.3; Sierra
Club Argument, p. 13).
BC Hydro testified that it is already relying on Power Smart for a third of its new resources going
forward (T11: 1694). If a more aggressive portfolio is needed, BC Hydro has identified additional
savings in the IEP through Power Smart 3, 4 and 5 (T21: 3773).
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Except for the Sierra Club, all of the other Intervenors raised issues related to the size of the Power
Smart portfolio. These other Intervenors also raised issues related to specific programs, particularly in
certain sectors.
Dr. Marvin Shaffer, on behalf of the BCOAPO, concluded that the findings of the CPR Update point to
a market failure due chiefly to rates not reflecting the incremental cost or value of electricity. Further,
Dr. Shaffer submitted that the 10-Year Plan has failed to consider the impact of Stepped Rates and has
failed to study the effect of falling real electricity prices over the last decade (Exhibit C10-3, pp. 5-6).
The BCOAPO submits that it has concerns with the Power Smart program as presently constituted and
argues that BC Hydro needs to move carefully and deliberately in developing new programs (BCOAPO
Argument, pp. 15, 21).
The IPPBC submits that Power Smart is BC Hydro’s alternative to increased imports and is used as a
means of claiming that BC Hydro does not need any new supplies, except for a small amount of
electricity from IPPs The IPPBC further argues that spending on Power Smart programs should be held
in abeyance pending the implementation of Stepped Rates, and that the load displacement portion of the
program is a thinly disguised source of subsidized generation (IPPBC Argument, pp. 9, 44).
The CECBC argues that investments such as Load Displacement programs should be considered utility
generation replacement instead of energy savings created by DSM (CECBC Argument, p. 32).
The JIESC argues that the current Power Smart programs understate the level of cross subsidies, and
submits that many of the programs that are not cost effective should be terminated (JIESC Argument,
p. 36).
9.3 Screening Power Smart Programs
BC Hydro contends that the cost effectiveness of its Power Smart programs should be viewed at the
portfolio level as opposed to the individual program or sector level. BC Hydro uses the TRC test as the
primary screening tool, the UC test as an additional filter to measure the impact on rates, and the RIM
test to assess the distributional impact (Exhibit B1-2, Tab I, pp. 5-6).
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BC Hydro conceded that certain programs are bearing the burden of some investments that were made
when BC Hydro focused on the UC instead of the TRC test (T14: 2258). For the 10-Year Plan, BC
Hydro submits that Power Smart as a whole passes the TRC test, with a benefit/cost ratio of 1.3 and a
levelized cost of 4.4 cents/kWh, and that virtually all of the Power Smart programs pass even when
Portfolio Level Costs are allocated to individual programs (Exhibit B1-81; BC Hydro Argument, pp. 94-
95). Those that do not pass the TRC benefit/cost ratios at the plan stage are close to 1.0, small in a
monetary sense and each have specific rationales, and are expected to pass 1.0 at the business case stage
once the non-electrical customer benefits are fully quantified (Exhibit B1-7, BCUC IR 1.59.1; BC
Hydro Argument, p. 98). BC Hydro submits that RIM benefit/cost ratios require a kind of contextual
analysis such as the number and identity of beneficiaries and the number and identity of those who may
be adversely affected by any individual program (BC Hydro Argument, p. 96).
The JIESC submits that the Power Smart portfolio contains programs with TRC benefit/cost ratios of
less than 1.0, which is below the minimum acceptable standard. It submits that the UC ratios are
misleading as they do not disclose all costs associated with a program, and that the RIM benefit/cost
ratios show that virtually every program other than the industrial programs require a subsidy from non-
participants (JIESC Argument, pp. 30-31). It argues that BC Hydro should be ordered to redesign all
programs with a TRC ratio or RIM ratio of less than 1.0 so that they either become economic and self
supporting or be terminated (JIESC Argument, p. 30).
Dr. Shaffer provided evidence that the benefit of conservation is not the cost BC Hydro would otherwise
incur for incremental supply but the difference between the cost of incremental supply and the amount
BC Hydro would have charged for it. He proposed that providing appropriate price signals would avoid
the selection bias, moral hazard and rebound effects from DSM programs (Exhibit C10-3, pp. 6-8). The
BCOAPO agrees with BC Hydro that the TRC and RIM tests are useful in assessing the cost
effectiveness of the programs and accepts that the RIM test is an equity test rather than efficiency test.
However, the BCOAPO argues that all Power Smart programs should be subject to rigorous analysis
where there appear to be cross-subsidies (BCOAPO Argument, pp. 16, 18).
The Sierra Club submits that BC Hydro’s programs are highly cost effective because they were tested
under a number of assumptions and the overall TRC benefit/cost ratios did not undergo significant
change either on a program or portfolio basis (Sierra Club Argument, p. 4). It submits that the UC ratio
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represents a remarkable opportunity to reduce revenue requirements and argues that the RIM should not
form the principal basis on which DSM programs are evaluated (T21: 3778, 3779; Sierra Club
Argument, pp. 6-7).
The CECBC submits that calculation of the RIM benefit/cost ratio does not provide any insight into the
impact of the programs on rates because the most useful indicators for comparing DSM program cost-
effectiveness are lifecycle revenue impacts expressed as the change in rates and the net present value
(CECBC Argument, p. 30). The CECBC argues that because BC Hydro’s definition of the avoided cost
of supply does not include distribution and transmission capacity savings, the benefits are understated.
Accordingly, this creates a problem when comparing the rate impact of programs for high-voltage
customers with those designed for distribution voltage customers (CECBC Argument, p. 31). Although
Mr. Hobson of BC Hydro agreed that there was an underestimation when cross-examined by the Sierra
Club (T11: 1674), the CECBC submits that mere recognition is inadequate because it fails to credit the
DSM resource for evaluation purposes (CECBC Argument, p. 32).
Mr. Belland, on behalf of the IPPBC, testified that there should be a higher priority for the RIM test, and
specifically for the RIM benefit/cost ratio (Exhibit C4-4, paragraph 6). The IPPBC advanced the
position that the appropriate screening test should be the ERIM (also labeled Economic Resource Test)
as it was put forth in the IPPBC Evidence (Exhibit C4-4, paragraphs 42-48). Mr. Belland argued that
the ERIM benefit/cost ratios will not lead to false positives (T21: 3808). The IPPBC submits that BC
Hydro’s accounting of savings through the use of year-end run rates led BC Hydro to overstate the
benefit/cost ratio by 2.2 percent (IPPBC Argument, Appendix 2, paragraphs 110-113).
Terasen does not support employing a RIM benefit/cost ratio of 1.0 as the program threshold. It submits
that fairness can be found in a variety of DSM program made broadly available and providing all
customers with options for reducing their energy consumption (Terasen Argument, pp. 5-6).
Screening tests were the subject of substantial evidence and cross-examination. During the hearing, it
was agreed that from the NPV perspective, the ERIM analysis and the RIM analysis performed by BC
Hydro will always yield the same NPV (Exhibit B1-179; T20: 3696; T21: 3851). Dr. Shaffer testified
that RIM and ERIM give different ratios because it is arbitrary in some respects where you put the lost
revenues. The focus should be on the NPV and the specific ratios are meaningless (T20: 3697).
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Mr. Woolf testified that RIM is a measure of equity, more so than cost effectiveness and a RIM
benefit/cost ratio of 0.8, 0.6 or 0.1 does not indicate what that means to customers (T21: 3761, 3780).
BC Hydro suggests that the equity issue could be addressed by demonstrating a RIM of greater than 1.0
for projects that are over a million dollars and designing a mix of programs where non-Participants are
only adversely affected because of their freely made choice to consume energy that is more expensive
than conservation based alternatives (T13: 2042; BC Hydro Argument, p. 100). As the RIM benefit/cost
ratio will vary over time in response to rate design decisions, BC Hydro argues that a cut-off for the
RIM would not be robust over time (BC Hydro Reply Argument, p. 46).
BC Hydro testified that loading costs that support all programs onto individual programs would lead to
inappropriate and less than optimum program selection (Exhibit B1-81, item 4). Terasen agrees with
BC Hydro that an allocation of indirect costs is likely to produce arbitrary results but adds that the issue
of the appropriate level of indirect or portfolio level Power Smart spending should be considered
separately from DSM program selection (Terasen Argument, p. 4).
With respect to the TRC, the Commission Panel notes the BCOAPO’s argument that just as programs
with a RIM less than 1.0 should not be rejected automatically if there are good reasons within the
overall Power Smart program to proceed with them, neither should programs with a RIM [sic] in excess
of 1.0 based on supposedly quantified non-energy items be automatically undertaken (BCOAPO
Argument, p. 20).
With respect to the RIM, the Commission Panel notes that BC Hydro conceded to Dr. Shaffer’s position
that the less broad-based the opportunity for participation, the greater opportunity for distributional
inequity (BC Hydro Reply Argument, p. 46).
The IPPBC raised the issue that a risk-adjusted discount rate would be more appropriate for the 10-Year
Plan (Exhibit C4-4, p. 23). Under cross-examination, Mr. Balland agreed to the proposition that one
way to address the issue of risk is “…. to use a single discount rate and adjust values of each individual
resource in the portfolio so you can see transparently that the time element of the portfolio is being
treated equally between the different resources” (T21: 3866).
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Commission Findings
The Commission Panel does not accept that the ERIM benefit/cost ratio offers useful information on the
efficiency of the Power Smart programs that is not supplied by the TRC, UC and RIM tests. The
Commission accepts BC Hydro’s argument that RIM is a measure of equity that represents cross-
subsidy from non-Participants to Participants and is not an efficiency test (BC Hydro Argument, p. 49).
BC Hydro took the position that if it was to eliminate programs from the Power Smart portfolio, it
would need to recast the entire plan itself (T14: 2299-2300). Although the Power Smart portfolio may
need to be “recast” with changes to programs, the Commission Panel finds that each program needs to
be evaluated on its merits against both the RIM and TRC screening tests. Further, each Power Smart
program should be evaluated from a “bottom line” perspective. In this regard, the third of BC Hydro’s
seven core principles that shape the 10-Year Plan should be the paramount principle and should include
both a portfolio and program perspective (Exhibit B1-2, Tab I, p. 2).
The Commission Panel is aware that Power Smart only returned three years ago to BC Hydro and that
the issue of maturation arises with respect to the availability of empirical evidence for judging the use of
RIM ratios in screening. The Commission Panel does not disagree with BC Hydro that it needs a large
degree of autonomy that will not discourage nuanced program optimization (BC Hydro Argument, p.
106). However, the Commission Panel accepts Intervenors’ arguments that BC Hydro needs to move
carefully in developing new programs at this juncture.
The Commission Panel approves all Power Smart expenditures in the REAP subject to the
exceptions discussed in Section 9.4 on the Load Displacement program. The Commission Panel
relieves BC Hydro of the obligations set forth in Exhibit B1-142, and directs BC Hydro to seek
approval for and file tariffs for all new Power Smart programs with a RIM benefit/cost ratio of
less than 0.8 and/or a TRC benefit/cost ratio of less than 1.0. For those Power Smart programs
with a RIM benefit to cost ratio of less than 0.8, BC Hydro is directed to justify with each REAP
filing the continuation of those programs.
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The Commission Panel determines that the Power Smart programs should be included in the
annual REAP filing. For the purpose of regulatory review, the TRC, UC and RIM should be
presented and calculated for the portfolio, by sector and by program. Portfolio Level Costs
should be allocated to programs, and BC Hydro is directed to use the same allocation
methodology based on kWh savings as used in Exhibit B1-81.
9.4 Load Displacement Projects
The industrial sector accounts for a large proportion of the energy conservation potential of BC Hydro.
The 2002 Conservation Potential Review conducted by BC Hydro identified Load Displacement as
representing approximately 35 percent of the total potential energy savings in the industrial sector
(Exhibit B1-2, Tab I, p. 2). Load Displacement is defined as the reduction of electricity requirements
from existing utility customers through electricity conservation or through customer self-generation
(Exhibit B1-2, Tab H, p. 41). BC Hydro has allocated approximately 39 percent of its proposed Power
Smart spending or $265.6 million toward Industrial Sector programs. Out of the Industrial Sector
programs, another 39 percent or $102.8 million is directed to Load Displacement programs. BC Hydro
also estimates that 21 percent or 760 GWh of Power Smart savings will come from Load Displacement
programs (Exhibit B1-2, Tab I, p. 15).
All Intervenors, with the exception of the Sierra Club, JIESC and Terasen, expressed concerns over the
evaluation of industrial programs. Many specifically debated whether subsidized industrial load
displacement projects, such as the Canfor and Weyerhaeuser projects, were the most efficient and
effective way for BC Hydro to achieve energy conservation. Much of the debate focused on the
procedure BC Hydro used to select and negotiate acceptable projects, especially in light of the potential
for Stepped Rates in the future.
In particular, Dr. Shaffer, on behalf of the BCOAPO stated:
… successful competitive firms do not pass up truly cost-effective technologies. The most fundamental reason why competitive firms in B.C. don’t implement cost-effective load displacing or electricity saving measures is the failure of B.C. Hydro’s electricity rates to signal to users the incremental costs or value of the electricity they consume (Exhibit C10-3, p. 5).
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Providing appropriate price signals avoids the selection bias, moral hazard and rebound effects of subsidized DSM. It eliminates the need for project applications, negotiations and other basically wasteful bureaucracy. And it allows industry to do what it can do best – to efficiently minimize its purchases and use of electricity (Exhibit C10-3, p. 8).
Dr. Shaffer went on to tabulate the cost to ratepayers under different assumptions for two load
displacement projects selected by BC Hydro, namely, at the Canfor and Weyerhaeuser paper mills. His
evidence concluded:
Not only could Weyerhaeuser and Canfor have implemented some conservation without the subsidy, particularly for that portion of their load subject to tier 2 rates, it is possible they would have installed turbo-generators on their own at some later date. With rising BC Hydro rates, greater access to domestic markets, and some already sunk costs, the projects might have proven economic in the foreseeable future (Exhibit C10-3, p. 12).
Despite holding a number of competitive calls for power from industrial sites in the past including a
self-generation call, BC Hydro chose, in 2003, to negotiate with Canfor and Weyerhaeuser. This action
was based on the assumption that neither would proceed with an energy conservation project without
BC Hydro incentive assistance. However, evidence shows that both Canfor and Weyerhaeuser had
contemplated similar projects in the past and Weyerhaeuser had arguably already purchased some
appropriate equipment. Ms. Van Ruyven further verified that several other projects from the 1995 bid
have been successful without assistance, albeit with power purchase agreements from BC Hydro (T14:
2263).
Dr. Shaffer said:
And that’s one of the problems with the subsidy approach to acquiring a resource or a load displacement project, that you don’t know what would otherwise have happened, and it’s not in the interests of the recipient to tell you exactly what they would do (T20: 3646).
Dr. Shaffer went on to say:
BC Hydro doesn’t have all of the same information that recipients will have. And that’s a problem. They have to work together as best they can, but they won’t have the same level of knowledge of when and where projects will be economic (T20: 3647).
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Commission Findings
The Commission Panel rejects BC Hydro’s approach to load displacement projects for the following
reasons:
1. BC Hydro does not seem to have benefited from the information garnered through past bidding processes or from its customer relations staff. No evidence containing an inventory of industrial sites, their self-generation capability and respective economics, with or without incentives, was presented to support BC Hydro’s assumption that incentives were necessary.
2. No competitive process was followed. It is not clear whether other sites could have been
completed successfully with less incentive than what Canfor and Weyerhaeuser received. BC Hydro could have designed a bidding program that might have minimized their incentives.
3. BC Hydro appears to have wasted the time and money of unsuccessful bidders who may well
have gone ahead with a project if 40 percent of the capital was provided up-front with a rate of return of up to 20 percent. Some projects may, indeed, have gone ahead for much less. As stated by Dr. Calvert on behalf of the CPP:
We believe that load displacement initiatives should not be included within the Power Smart envelope as long as Power Smart is promoted on the basis of its contribution to energy conservation as the power is simply generated by someone else (T21: 3739).
Consequently before allowing BC Hydro to make commitments to very major additional Power Smart subsidies, it seems to us that a thorough review of potential savings from alternative approaches, including regulatory and pricing should be done (T21: 3741).
The CECBC further argued:
…a utility demand side investment would pay for only the energy savings created by the project. Any other investment in the project by the utility should be considered supply side and subject to the acquisition criteria and hurdles applied to all supply side resources (CECBC Argument, p. 32).
4. Significant evidence was provided debating what the appropriate comparator should be with respect to determining the actual savings from load displacement projects.
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The Commission Panel determines that Load Displacement projects should be considered as
supply side alternatives and accordingly directs BC Hydro to not proceed with any new industrial
Load Displacement projects as part of the Power Smart 10-Year Plan.
The Commission Panel disallows F2005 and F2006 total expenditures on Load Displacement
projects other than with respect to expenditures for projects with a contract dated prior to the
date of the Application. For the purpose of calculating the disallowed amount, BC Hydro is
directed to allocate, based on energy savings, the Sector Enabler Costs, as well as Portfolio Level
Costs directly associated with the Load Displacement program. The calculation of the disallowed
amount should be filed with the Commission with the financial schedules to be filed as directed in
Commission Order No. G-96-04, issued with this Decision.
BC Hydro may apply on a project-by-project basis for approval of Load Displacement projects; the
Commission may then approve a deferral account for recovery of such expenditures in future test
periods. The Commission encourages BC Hydro to follow an appropriate competitive process for Load
Displacement projects if it pursues such projects in the future.
The Commission Panel directs that costs and benefits associated with all Load Displacement
projects be removed from the program statistics used for reporting the costs and benefits of the
overall Power Smart program and be removed from calculating BC Hydro investment threshold
tests, that is, the TRC, UC, and RIM.
BC Hydro proposes to undertake steps to ensure that no industrial program Participants will be able to
“double count” as a result of the implementation of the Stepped Rate (BC Hydro Argument, p. 102).
The Commission Panel directs BC Hydro to provide evidence at the next revenue requirements
hearing to demonstrate that incentives have been reduced for the industrial program, if Stepped
Rates are implemented during the test period.
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9.5 Evaluation
Savings from the Power Smart programs are converted into acquired energy in the reference energy
forecast (Exhibit B1-7, BCUC IR 1.46.2). The Power Smart group conducts Process, Market and
Impact Evaluations (Exhibit B1-2, Tab M, p. 3). In addition there is a third-party oversight team
(Exhibit B1-2, Tab M, Appendix F; T11: 1754). A critical issue is how much of the energy savings
estimated for the projects are realized and sustained, and can correctly be identified as specific to Power
Smart.
BC Hydro testified that it has exceeded its targets three years in a row and the measurement and
verification process shows that the incentive-driven projects have come out ahead. In the case of large
industrial customers whose incentives are under a 25/50/25 payment stream, BC Hydro has the ability to
hold back the last 25 percent or can claw back some of the 75 percent already provided if the future
savings fail to appear (T11: 1766; BC Hydro Argument, p. 109). For customers in the non-industrial
rate classes, BC Hydro submitted that it will bear the consequences of deficiency against forecast
savings as it will assume the risk on volume and cost of energy variances (T12: 1953-1956).
Dr. Shaffer provided evidence from a recent econometric study that DSM savings was roughly one-fifth
of what the utilities reported, due to free ridership and selection bias problems that are much greater than
utilities typically allow for (T20: 3689-3690; Exhibit C10-3, p. 7). The BCOAPO argues that BC
Hydro’s report on DSM savings requires very careful evaluation (BCOAPO Argument, pp. 17-18).
The CECBC submits that changes in Power Smart uptake rates within a 20 percent range might impact
net income by $2 million in F2006 (Exhibit B1-11, CECBC IR 1.3.1.1; CECBC Argument, p. 53) and
argues that a deferral account is appropriate.
BC Hydro argues that the results based on BC Hydro’s own evaluation methodologies provide much
better assessment of savings than results from an econometric study which only presents averages of
surveyed utilities (BC Hydro Argument, p. 109).
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Commission Findings
The Commission notes that Process Evaluation and Market and Impact Evaluations are generally
conducted from 6 to 36 months after program launch (Exhibit B1-2, Tab M, p. 6), and given that BC
Hydro has only ended the second year of the 10-Year Plan, the Commission is reluctant to direct BC
Hydro to re-assess its evaluation methodology without evidence that it has been over estimating energy
savings. However, the Commission Panel is concerned that the evaluation oversight team membership
is heavily weighted towards individuals from the Power Smart group and the Distribution line of
business (Exhibit B1-2, Tab M, Appendix F, p. 48) as opposed to being composed of individuals at arms
length from program management and marketing (T7: 946; T11: 1754-55). The Commission suggests
BC Hydro diversify the composition of its evaluation oversight team with representatives from different
lines of business and that the Chair of the team be designated from outside the Distribution line of
business.
The Commission Panel directs BC Hydro to file the executive summaries of its milestone
evaluation reports and the full final evaluation reports of all its Power Smart programs.
9.6 Power Smart Costs
BC Hydro submits that the past expenditures on Power Smart were prudent and that BC Hydro should
be permitted to recover their costs in rates (BC Hydro Argument, p. 50). BC Hydro further submits that
expenditures contemplated for DSM programs have been fully vetted and those aspects of the REAP
should be approved for future recovery in rates (BC Hydro Argument, p. 87). BC Hydro submits that
the prudency of Power Smart expenditures will be reviewed with each REAP, pursuant to subsection
45(6.1)(a) of the UCA (BC Hydro Reply Argument, pp. 55-56).
9.6.1 Impact on F2005 and F2006 Rates
Mr. Marchant of BC Hydro testified that all but a little over $2 million of Power Smart expenditure is
capitalized and deferred (T11: 1771-1772). BC Hydro argues that the forecast investment costs of $100
million a year have little impact on rates for the test period because it is the financing costs associated
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with expenditures made in prior years that impact rates in F2005 and F2006 (BC Hydro Argument, p.
48).
The JIESC submits that Power Smart annual expenditures have increased by 138 percent in the past two
to three years and approximately 20 percent of these costs are in the nature of overheads and advertising
without any benefits that can be attributable. It also points to the $53.5 million shortfall in F2004
investment cost that was only revealed in the June Financial Undertaking (JIESC Argument, pp. 29-30).
The JIESC argues for an annual reduction in DSM costs of $50 million because many Power Smart
programs are not cost effective and should be terminated (JIESC Argument, p. 36).
The Application identifies the investment in Power Smart as one of the significant cost pressures for the
next two years (Exhibit B1-1, p. 1-8). The estimated costs for F2005 and F2006 are $54 million and $59
million respectively (Table 9). These amounts exclude finance charges and ROE but include OMA and
amortization costs.
The OMA expenditures are $22.6 million and $22.4 million respectively for F2005 and F2006 (Exhibit
B1-1, Table 4-2; Exhibit B1-8, BCUC IR 2.195.6A, pp. 3-4) and the total OMA expenses reflect the
costs incurred by other administration and support activities within the Power Smart group and other
departments.
Amortization commences in the following year after the expenditure has been incurred and is amortized
over a 10-year period (Exhibit B1-1, p. 8-6; Exhibit B1-7, BCUC IR 1.52.4). Therefore, the
amortization costs for the test period include prior years’ expenditures up to the end of F2004.
The CECBC submits that BC Hydro’s DSM spending between 1995 and 2001 were forays into a
restructured market instead of acquisition of new energy savings. It submits that amortization costs
estimated at $12 million and $6 million respectively for F2005 and F2006 should be disallowed
(CECBC Argument, pp. 34-35).
The Reply Argument does not respond directly to the JIESC taking issue that the F2004 capital
investment shortfall was only revealed in the June Financial Undertaking. BC Hydro simply counters
that the JIESC does not have any real argument to support its change in position by using later data
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instead of a February 20, 2004 perspective (BC Hydro Reply Argument, p. 20). It argues that most
Intervenors in this proceeding have not attempted to undertake the line-by-line analysis that would be
required to identify excess expenditures (BC Hydro Reply Argument, p. 21). BC Hydro rebuts the
CECBC’s argument by maintaining that energy savings had continued to accrue between 1996 and 2000
and that no evidence has been adduced that any of the market-restructuring activities were funded using
deferral capital (BC Hydro Reply Argument pp. 24-25).
9.6.2 Efficiency in the Administration of Power Smart
BC Hydro’s position is that there is no suggestion in the evidence that the programs could have been
administered more efficiently (BC Hydro Argument, p. 48).
The JIESC submits that the lack of detailed description of the functions of Power Smart enabling
initiatives cannot justify the $10 million expenditures in this category (T11: 1776-1778; Exhibit B1-80).
It argues that the Commission must impose discipline on the $20 million of non-program specific
spending by reducing total allowed expenditures for these functions and by requiring the vast bulk of
expenditures to be assigned to the most relevant programs or be terminated (JIESC Argument, pp. 31,
32).
The BCOAPO argues that 20 percent of the 10-Year Plan base case plan totaling $135 million cannot be
properly assessed because they are allocated as non-direct program costs (BCOAPO Argument, p. 20).
It also argues that the re-instituted Power Smart program has led BC Hydro to over invest in incentive
programs. It submits that it is difficult to ascertain what the real impact of an industrial Stepped Rate
will be until the actual rate is established (BCOAPO Argument, pp. 15, 19).
The IPPBC submits that BC Hydro has ignored the imminent introduction of Stepped Rate when
implementing Power Smart spending on large power consumers, and this was contrary to the BCUC
Recommendation that was accepted by the Government (IPPBC Argument, pp. 23, 24).
The Sierra Club argues that even though structured rates are important means to create incentives to
consumers to make efficient use of energy, rates in and of themselves are not sufficient. Incentives are
still necessary to overcome market barriers (Sierra Club Argument, pp. 10-11).
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BC Hydro submits that it is committed to minimizing the extent of the incentives in light of the fact that
10 percent of consumption will be at market prices. In future, a customer who accepts money from BC
Hydro to displace its load will see its Customer Base Load reduced (Exhibit B1-7, BCUC IR 1.55.1; BC
Hydro Argument, p. 102).
9.6.3 Power Smart as Least Cost Alternative
It is BC Hydro’s position that the electricity expenditures of customers today are lower than they would
have been had BC Hydro not undertaken these past programs. The results of the TRC show that energy
is delivered at a lower cost than the next least-cost alternative means of acquiring energy (BC Hydro
Argument, pp. 49-50). BC Hydro argues that RIM does not measure bill impacts whereas a consumer’s
welfare depends on the benefit received from energy, not how much energy is consumed (BC Hydro
Argument, p. 97).
The Sierra Club submits that the average residential rate impact over the course of the programs would
be 0.26 percent. The extensive benefits including the obvious environmental benefits of the Power
Smart programs and their cost-effectiveness provide the case for approving the expenditures necessary
to fund these programs in the next two years (Exhibit B1-166; Sierra Club Argument, p .9).
The Commission notes that when the Energy Policy sets a target of 50 percent of new supply through
Clean Sources, this energy source is subject to less than a 0.2 percent per year rate impact (Exhibit B1-1,
p. 1-5). In comparison, the rate increment associated with the Power Smart portfolio is 0.18 percent and
0.33 percent for F2005 and F2006 (Table 9).
Commission Findings
There is no evidence that the market restructuring activities between 1995 and 2001 were funded using
deferred capital. The Commission Panel determines that BC Hydro should be permitted to recover
their past expenditures in rates.
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The planned annual expenditures for the test period are a rapid increase from the recent past. The
difference between actual and forecast expenditures experienced in F2004 and the late revelation of this
difference implies a high degree of uncertainty in program forecasts. The Commission Panel denies
the request for approval of the Power Smart 10-Year Plan pursuant to subsections 45(6.1)(c) and
45(6.2).
There is an inadequate description of Portfolio Level Costs. The Commission Panel directs BC Hydro
to provide further justification of the Portfolio Level Costs, than was presented in this proceeding, with
the next REAP and revenue requirements application.
BC Hydro has planned for 257 staff for F2005 and F2006 to deliver Power Smart programs (Exhibit B1-
1, Table 8-2). Given that BC Hydro is directed not to proceed with further Load Displacement projects
and given other program changes that may be necessary in the future, BC Hydro should ensure that
staffing levels for the implementation of Power Smart programs can be modified with changes to the
Power Smart program and that an appropriate mix of full-time, part-time and contract staff permits such
changes in the future at a reasonable cost.
9.7 Regulatory Review of Power Smart
BC Hydro is directed to provide information to the Commission for on-going review of Power
Smart performance through:
• Executive Summaries of milestone evaluation reports and full final evaluation reports for
each program.
• Semi-annual reports on DSM activities which, amongst others, will include:
• detailed breakdown of OMA expenses related to support activities carried out
within the Power Smart group and in other departments that support Power Smart organization;
• detailed description of the functions of portfolio level costs and how these costs are
allocated to programs;
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• summaries of the overall performance of Power Smart with reference to program objectives; and
• variances of fiscal year budgeted and actual deferral capital expenditures and
explanation of variances.
The Commission Panel directs BC Hydro to file evaluation results for F2005 by June 30, 2005 or
as soon thereafter as practicable. The evaluation results should include a comparison of actual
and forecast for energy savings, TRC, UC and RIM for the portfolio, by sector and by program.
If the F2005 TRC for the portfolio is less than 0.9, then BC Hydro is directed to discontinue any
programs with a TRC less than 1.0 and/or a RIM of less than 0.8. If the F2005 TRC for the
portfolio is 0.9 or greater and less than 1.0, then BC Hydro is directed to make whatever program
changes are appropriate to achieve a portfolio TRC exceeding 1.0. If the F2005 actual energy
savings is less than 75 percent of the forecasted energy savings for the portfolio, then the
Commission Panel directs BC Hydro to reapply for F2006 Power Smart program expenditures.
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11.0 SUMMARY OF DIRECTIVES
This Summary is provided for the convenience of readers. In the event of any difference between the Directions in this Summary and those in the body of the Decision, the wording in the Decision shall prevail.
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1. The Commission Panel has decided that the question concerning the
Commission’s jurisdiction to approve the service level agreements can be more properly dealt with once the agreements are filed and will allow the public an opportunity to address the issue at that time.
12
2. The Commission Panel approves the WTS rate application and the WTS rates described in Rate Schedules 3000 and 3001 and presented in the Application Chapter 6A, Table 6A-13, as filed, subject to the adjustments required in this Decision.
18
3. The Commission Panel approves the four deferral accounts proposed by BCTC, such approval being subject to review for test periods beyond F2006. The Commission Panel approves BCTC’s proposal that annually the average balance in each deferral account attract an interest charge or credit equivalent to BCTC’s weighted cost of debt during the same period.
25
4. In view of section 6(c) of SD9, the Commission Panel also approves the BCTC proposal for the clearing of these accounts.
25
5. The Commission Panel does not adopt the JIESC’s proposal for a RTO West deferral account.
25
6. The Commission Panel directs BCTC to file quarterly and annual reports of the balances in each of the approved deferral accounts, including details on exact elements and costs.
25
7. The Commission Panel determines that the onus is on BCTC to ensure clarity with respect to the exact elements and costs to be contained in the deferral accounts. The Commission Panel directs BCTC to file, by January 31, 2005, the name, number and account description from BCTC’s Code of Accounts that are to be included in the deferral accounts approved in this Decision.
25
8. The Commission Panel determines that it has jurisdiction to approve the cost elements of the HPO proposed by BC Hydro.
27
9. The Commission Panel concludes that the forecast of the HPO should be based on the best, known, available information as to water conditions as of the Evidentiary Cut-off Date.
36
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34. The Commission Panel does not accept that an increase in R&D spending is
appropriate at this time, particularly given the significant applied-for rate increase for F2005. Therefore, the Commission Panel approves R&D expenditures for F2005 of $3.04 million and for F2006 of $3.04 million. In the next revenue requirements proceeding, R&D expenditures should be supported by evidence of expected benefits to customers.
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35. The Commission Panel notes the uncertainty with respect to the future of Burrard, and denies BC Hydro’s request to change the depreciation rate for the Burrard facility.
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36. The Commission Panel denies BC Hydro’s request to change the depreciation rate of distribution transformers based on a change in the useful life from 35 years to 30 years because the evidence provided does not indicate that the installed base is experiencing either accelerated failure rates, or disproportional contributions to outage frequencies or durations. The Commission Panel accepts the salvage value evidence of Gannett Fleming and approves the change to a minus 10 percent negative net salvage value provision for distribution transformers.
111
37. The Commission Panel approves the costs for F2005 to F2008 associated with energy purchase agreements, as identified by BC Hydro in its REAP (Exhibit B1-23, Table 2, p. 11).
117
38. The Commission Panel approves BC Hydro’s 400 GWh energy call proposed in the REAP, as modified during the course of this proceeding.
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39. The Commission Panel finds that there is a sufficient record to allow the Commission to make certain determinations with respect to the capital and DSM expenditures contemplated in the REAP.
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40. The Commission Panel approves the $1.2 million F2005 investigation costs related to capacity additions for Revelstoke 5 or Mica 5 and denies approval for $6.5 million sought for F2006. BC Hydro may apply for approval of F2006 expenditures following filing of the 2005 REAP.
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41. The Commission Panel approves the initial $1.9 million sought for F2005 for Stage 1 Cabinet approval of Site C expenditures and denies approval for $5.5 million sought for F2006. BC Hydro may apply for approval of F2006 expenditures as contemplated by BC Hydro’s proposed approach to the investigation of Site C.
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42. The Commission Panel approves the capital expenditures contemplated in the
REAP, subject to adjustments required by this Decision. Capital expenditures contemplated in the REAP beyond the first quarter of F2006 are also subject to a Commission decision on the February 2005 REAP. For certainty and clarity, the Commission Panel specifically approves the F2006 BC Hydro’s Owners’ Revenue Requirement of $390 million, subject to the adjustments required by this Decision.
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43. The Commission Panel directs BC Hydro to prepare and file with the next revenue requirements application a status report for the Strategic Workforce Renewal Initiative that presents costs since its inception to its conclusion and a justification for positions added when compared to other alternatives.
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44. The Commission Panel approves the OMA revenue requirement, subject to the adjustments required by this Decision.
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45. The Commission Panel determines that the sales forecasts provided in the REU be used for the purpose of revenue forecast for the test period.
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46. The Commission Panel finds that the Evidentiary Cut-off Date is February 20, 2004.
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47. The Commission Panel accepts the changes in depreciation rates requested by BC Hydro in Exhibit B1-104 except for the accelerated depreciation on Burrard and the distribution transformers as described in Sections 6.7.1.7 and 6.7.2.3. The Commission Panel directs BC Hydro to file a depreciation study as part of its next revenue requirements application.
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48. The Commission Panel accepts that changes could occur to the arrangements with the Province, the remissions and the plan. Therefore an amortization period of 10 years for water use plans is accepted. The Commission Panel determines that the 10-year amortization period for ongoing negotiation and litigation costs with First Nations and the costs of settlements arising from those negotiations approved by Order No. G-53-02 continues to be appropriate.
155
49. The Commission Panel accepts the method of calculating the IDC rate and finds that a threshold for the calculation of IDC is not required.
156
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50. The Commission Panel has considered the evidence of BC Hydro, the JIESC and
the CECBC and the submissions made on this issue and concludes that it is appropriate in the circumstances to require a variance from Section 3110 of the CICA Handbook. Accordingly, the Commission Panel orders a variance from GAAP and requires that the F2004 balance in the FRSR account remain as a liability to be utilized for dismantling costs that are incurred in F2005 and beyond. For assets that require an ARO liability to be established and an FRSR provision was not established or is insufficient, BC Hydro and BCTC are to record a sufficient ARO provision in accordance with Section 3110 of the CICA Handbook.
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51. The Commission Panel finds that the accounting treatment proposed by the JIESC with respect to CIAC would be contrary to, and would be an indirect attempt to circumvent, the clear requirements of HC2.
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52. The Commission Panel accepts that Terasen’s submission is not a request to redesign BC Hydro’s SET. The Commission Panel directs BC Hydro to periodically update the input factors when evaluating customer driven projects. The amortization period for CIAC employed by BC Hydro is consistent with the amortization period allowed for other utilities under the Commission’s jurisdiction and, accordingly, is accepted.
167
53. The Commission Panel approves the Uneconomic Extension Assistance Program as applied-for by BC Hydro.
167
54. The Commission Panel approves the accounting change from the cash method to the accrual method for post-retirement benefits.
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55. The Commission Panel accepts BC Hydro’s position that amounts and the timing for recovery of the uncollected trade revenue is highly uncertain and therefore determines that no amounts should be forecast for the test period. In the event that the Alcan and California receivables are recovered in F2005, the balance in the TIDA should be considered when F2006 rates are adjusted for allowed return on equity.
170
56. The Commission Panel has determined that the required pre-income tax rate of return to be earned by BC Hydro under HC2 for F2005 is 13.91 percent. For F2006 the allowed pre-tax rate of return for BC Hydro will be determined based on the 2005 allowed rate of return on equity and the 2005 effective income tax rate for Terasen. In accordance with SD9, the allowed rate of return for BCTC in F2005 and F2006 will be equal to the allowed rate of return for BC Hydro.
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57. The Commission Panel approves the interest rates and foreign exchange rates
forecast in the REU, the forecast debt components, and finds that an interest rate and foreign exchange rate deferral account should not be approved.
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58. The Commission Panel finds that HC2 does not contain a provision that allows for a retained earnings deferral account or a cap on equity at this time. The proposals to establish a retained earnings deferral account or to otherwise set a cap on retained earnings would frustrate the intent of HC2 and accordingly are denied. The Commission Panel notes that the accrual of interest to the deferred revenue under the Skagit Agreement was not fully explored by the Intervenors at the hearing. BC Hydro is to provide a full justification in its next revenue requirements application for the method that it uses to produce a constant (inflation adjusted) rate of return on the deferred revenue balance.
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59. The Commission Panel directs that the forecasts for the test period be updated for the actual F2004 ending balance sheet and retained earnings account balances.
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60. The Commission Panel approves all Power Smart expenditures in the REAP subject to the exceptions discussed in Section 9.4 on the Load Displacement program. The Commission Panel relieves BC Hydro of the obligations set forth in Exhibit B1-142, and directs BC Hydro to seek approval for and file tariffs for all new Power Smart programs with a RIM benefit/cost ratio of less than 0.8 and/or a TRC benefit/cost ratio of less than 1.0. For those Power Smart programs with a RIM benefit to cost ratio of less than 0.8, BC Hydro is directed to justify with each REAP filing the continuation of those programs.
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61. The Commission Panel determines that the Power Smart programs should be included in the annual REAP filing. For the purpose of regulatory review, the TRC, UC and RIM should be presented and calculated for the portfolio, by sector and by program. Portfolio Level Costs should be allocated to programs, and BC Hydro is directed to use the same allocation methodology based on kWh savings as used in Exhibit B1-81.
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62. The Commission Panel determines that Load Displacement projects should be considered as supply side alternatives and accordingly directs BC Hydro to not proceed with any new industrial Load Displacement projects as part of the Power Smart 10-Year Plan.
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63. The Commission Panel disallows F2005 and F2006 total expenditures on Load
Displacement projects other than with respect to expenditures for projects with a contract dated prior to the date of the Application. For the purpose of calculating the disallowed amount, BC Hydro is directed to allocate, based on energy savings, the Sector Enabler Costs, as well as Portfolio Level Costs directly associated with the Load Displacement program. The calculation of the disallowed amount should be filed with the Commission with the financial schedules to be filed as directed in Commission Order No. G-96-04, issued with this Decision.
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64. The Commission Panel directs that costs and benefits associated with all Load Displacement projects be removed from the program statistics used for reporting the costs and benefits of the overall Power Smart program and be removed from calculating BC Hydro investment threshold tests, that is, the TRC, UC, and RIM.
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65. The Commission Panel directs BC Hydro to provide evidence at the next revenue requirements hearing to demonstrate that incentives have been reduced for the industrial program, if Stepped Rates are implemented during the test period.
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66. The Commission Panel directs BC Hydro to file the executive summaries of its milestone evaluation reports and the full final evaluation reports of all its Power Smart programs.
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67. The Commission Panel determines that BC Hydro should be permitted to recover their past expenditures in rates.
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68. The Commission Panel denies the request for approval of the Power Smart 10-Year Plan pursuant to subsections 45(6.1)(c) and 45(6.2).
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69. BC Hydro is directed to provide information to the Commission for on-going review of Power Smart performance through:
• Executive Summaries of milestone evaluation reports and full final
evaluation reports for each program.
• Semi-annual reports on DSM activities which, amongst others, will include:
• detailed breakdown of OMA expenses related to support activities
carried out within the Power Smart group and in other departments that support Power Smart organization;
• detailed description of the functions of portfolio level costs and
how these costs are allocated to programs;
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• summaries of the overall performance of Power Smart with
reference to program objectives; and
• variances of fiscal year budgeted and actual deferral capital expenditures and explanation of variances.
70. The Commission Panel directs BC Hydro to file evaluation results for F2005 by
June 30, 2005 or as soon thereafter as practicable. The evaluation results should include a comparison of actual and forecast for energy savings, TRC, UC and RIM for the portfolio, by sector and by program. If the F2005 TRC for the portfolio is less than 0.9, then BC Hydro is directed to discontinue any programs with a TRC less than 1.0 and/or a RIM of less than 0.8. If the F2005 TRC for the portfolio is 0.9 or greater and less than 1.0, then BC Hydro is directed to make whatever program changes are appropriate to achieve a portfolio TRC exceeding 1.0. If the F2005 actual energy savings is less than 75 percent of the forecasted energy savings for the portfolio, then the Commission Panel directs BC Hydro to reapply for F2006 Power Smart program expenditures.
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71. The Commission Panel has considered the costs to be incurred pursuant to the ABS contract, and in Chapter 6 of this Decision, has approved those costs for recovery in rates during the test period. The Commission Panel notes that the out-of-scope costs need to be managed to ensure cost efficiency and overall value are obtained for out-of-scope work. The Commission will review the extent of this work in future applications.
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72. The Commission Panel requests BC Hydro to re-evaluate its delivery plan for engineering services and directs BC Hydro to file with the Commission by March 1, 2005 an action plan for changes to the delivery of engineering services that starts by allocating an initial target percentage of engineering projects for bid to outside engineering firms (not just low-value commodity tasks bid to individual consultants) and culminates in open competitive processes for securing engineering services (either internal or external). Alternatively, BC Hydro may consider outsourcing the engineering function to an outside engineering firm(s), assuming BC Hydro would retain sufficient expertise to manage the procurement and delivery function as well as establishing standards and quality control.
212
73. The Commission Panel also directs Generation and Distribution to file by March 1, 2005 a business plan that starts immediately and clearly focuses on the ESG acting in the role of service provider rather than asset owner.
213
74. The Commission Panel approves the RTO West funding as proposed by BCTC.
216
Submitted to:BC Hydro & Power Authority
Forestry Forecasting StudyAugust 2007
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BC Hydro & Power Authority Vancouver, BC
Forestry Forecasting Study
International Economic and Market Trends and the Production Outlook for BC’s Forest Products Industries to 2026
Project 156433 August 2007
Prepared by:
Forest Industry Consulting Temanex Consulting Inc.
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TABLE OF CONTENTS
Page
1.0 GLOBAL OUTLOOK 1
1.1 Economic Trends and Prospects 1
1.1.1 Key Background Data 1
1.1.2 Aggregate Long Term Regional and Global Economic Outlook 3
1.1.3 North America 5
1.1.4 Asia 6
1.1.5 Euro-27 (Original European Union Members plus Recent New Ones) 7
1.1.6 Latin America 8
1.1.7 Special Section on Eastern Europe and the Former USSR 9
1.1.8 Key Currency Exchange Rates Trend and Forecast 10
1.2 Global Outlook for Pulp and Paper 12
1.2.1 Background Overview/Summary 12
1.2.2 Regional Pulp and Paper Forecasts to 2026 – General Considerations 17
1.2.3 Long Term Regional Paper/Paperboard Demand Forecasts
for Major Grades 21
1.2.4 Virgin Woodpulp Long Term Forecasts to 2026 25
1.2.5 Long Term Recycled Fibre Trends and Forecast 26
1.2.6 Long Term Regional Market Pulp Demand Trend and
Forecast to 2026 27
1.2.7 Short-to-Medium Range Key Product Price Trends and Forecasts 30
1.2.8 Implications of Price Trends and Forecasts 38
1.2.9 Meteoric Rise of the Chinese Economy and Paper/Board Industry 39
1.3 International Wood Product Overview 41
1.3.1 Total Production of Lumber and Panels 41
1.3.2 Trade in Softwood Lumber 42
1.3.3 Outlook for Global Softwood Lumber 44
2.0 BC TIMBER AND WOOD PRODUCTS OUTLOOK 46
2.1 Timber and Log Supplies 46
2.1.1 Timber Supply 46
2.1.2 Mountain Pine Beetle 50
2.1.3 Log Supply 58
2.2 Wood Products 73
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2.2.1 Principal Markets for BC Lumber 73
2.2.2 Principal Markets for BC Panel Products 92
2.2.3 BC Production Forecasts 94
2.3 Fibre Demand and Supply Balances 106
2.3.1 Forecast Methodology 106
2.3.2 Provincial Balances 106
2.3.3 Interior Fibre Balances 109
2.3.4 Coast Fibre Balances 111
2.3.5 Deciduous Fibre Balances 114
2.4 Wood Chips and Residues 116
2.4.1 Whole-log Chipping 116
2.4.2 Chip Price Forecast 117
2.4.3 Residue Supplies and Demand 118
3.0 BC PULP AND PAPER INDUSTRIES OUTLOOK 120
3.1 Competitive Aspects – An Overview 120
3.1.1 Comparative Softwood Fibre Costs 120
3.1.2 Electricity Costs 122
3.1.3 Kraft Pulp and Papers 124
3.1.4 Mechanical Pulps and Mechanical Printing Papers 126
3.2 Cost Competitiveness of Key Pulp and Paper Products 128
3.2.1 Newsprint Machines 130
3.2.2 Telephone Directory Machines 132
3.2.3 Soft Nip Calendered (SNC) Machine Cost Competitiveness 133
3.2.4 Lightweight Coated (LWC) Machines 134
3.2.5 Bleached Softwood Kraft Pulp (BSKP) 136
3.2.6 Market Bleached CTMP 138
3.3 Some Manufacturing Cost Sensitivities 139
3.3.1 Specific Electrical Energy Demand 139
3.3.2 Purchased Electrical Energy Cost 141
3.3.3 Exchange Rate Fluctuations 143
3.4 Electrical Energy Self-Generation Update 145
3.5 Productivity and Technological Age Comparisons 146
3.5.1 Newsprint 146
3.5.2 Directory 148
3.5.3 LWC Machines 148
3.5.4 Market Bleached CTMP 150
3.5.5 Market Bleached Softwood Kraft Pulp (BSKP) 150
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3.6 Financial Performance Overview 151
3.6.1 Tembec 152
3.6.2 Catalyst Paper 153
3.6.3 Canfor 154
3.6.4 West Fraser Timber 155
3.6.5 Other 155
3.7 Technical and Cost Challenges of the Mountain Pine Beetle Infestation 156
3.7.1 BC Interior Softwood Kraft Mills 157
3.7.2 Market Softwood CTMP and BC Coast Super-Bright Producing Mills 158
3.7.3 Newsprint 159
3.8 Pulp and Paper Products in BC 160
3.8.1 Background Summary of Recent Developments 160
3.8.2 Major Drivers for Change 162
3.8.3 Opportunities and Threats of the Rapid Southeast
Asian Industrialization 169
3.8.4 Newsprint 173
3.8.5 Printing and Writing (P&W) Papers 175
3.8.6 Kraft Paper and Paperboard 177
3.8.7 Other Paper and Paperboard Products 179
3.8.8 Wood Pulp 179
3.8.9 Most Likely (Base Case) BC Pulp and Paper Production Forecasts 184
3.8.10 Forecast Uncertainties and High/Low Scenarios 190
GLOSSARY OF TERMS AND ABBREVIATIONS
APPENDIX 1 – FIBRE SUPPLY / DEMAND BALANCES
APPENDIX 2 – BC PULP AND PAPER MILL SUMMARIES
AND PROJECTIONS TO 2026
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1.0 GLOBAL OUTLOOK
1.1 Economic Trends and Prospects
1.1.1 Key Background Data
Real economic growth, measured as GDP, has been the major driver for increased
paper and paperboard consumption for decades, with aggregate regional paper and
paperboard demand strongly, but not exclusively, dependent on the product of
(GDP/capita) x (Population). This relationship still holds in general. However, the
world’s most mature (and highest per capita paper consumption) market, North
America, began exhibiting increasingly strong signs of “de-coupling” of paper/board
demand from GDP in recent years. These signs are especially evident in graphic
paper end use sectors, in particular newsprint and business papers, as a result of
digital substitution (Internet advertising, magazines, newspapers, electronic forms,
and so on). Furthermore, the degree of de-coupling is strengthening. [Note: Early
signs of this are also beginning to show up in other relatively mature markets,
notably Japan and Western Europe.] Figure 1-1 summarizes the result vividly for
North American newsprint, BC’s largest tonnage paper product.
Figure 1-1 Recent North American Newsprint Capacity, Demand, and Shipments Trend (Shipments – Domestic Demand = Exports)
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CapacityShipmentsDomestic Demand
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Extending the domestic North American demand trend several decades in the past
shows that demand peaked around 1990, as seen in Figure 1-2. As a result of the
same factors which are responsible for the trend in the chart below, namely market
maturity and substitution by digital communication alternatives (notably Internet),
other paper grades, such as business and high end (coated) publication papers are
expected to exhibit similar behaviour during the next 10-20 years.
Figure 1-2 Long Term North American Newsprint Demand Trend
Special note on the economic growth forecasts which follow: perhaps stating
the obvious, but the longer the forecast horizon the greater its uncertainty.
Average global economic growth in 2006, estimated at 5.3%, was even better than
the very respectable 4.8% registered in 2005. Largely driven by strong growth in
emerging economies (8-10% per year region for China and India; 4-6% per year for
Other Asia, Latin America, Russia and Africa), average global economic growth rate
will remain at healthy levels in the 4.5% per year region during the next five years, in
spite of slower growth (2-3.5% per year region) in the mature, developed economies
of North America, Western Europe and Japan. Lower than average growth is
expected in major developed economies in 2007-08, in particular North America.
This will have a moderating impact on economic growth of export driven developing
economies in Asia and Latin America.
8
9
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11
12
13
14
1975 1980 1985 1990 1995 2000 2005
Mill
ion
MT
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Figure 1-3 summarizes our economic growth forecast by major global region from
the baseline year 2006 over the next five years (2007-2011).
Figure 1-3 Real GDP Growth Rate Forecast to 2011 for Key Regions
The following Sections 1.1.2 to 1.1.8 summarize short, medium, and long-term
regional and global economic outlooks. The main conclusion is that virtually all
regions will exhibit positive economic growth during the next few years. This is
expected to drive increased paper demand.
Although average economic growth is expected to be quite healthy in just about
every region over the next five years, the ongoing “de-coupling” of paper demand
from this growth in mature developed economies (especially in North America) will
result in slower paper demand growth than would have been the case in previous
decades.
1.1.2 Aggregate Long Term Regional and Global Economic Outlook
Table 1-1 summarizes the short-to-medium (1-5 year) term economic growth
forecast for major regional economies. Economies not shown in the table, because
of their relatively small individual size, include Africa, Oceania, Middle East, and
some of the smaller ex. Soviet Union countries in Central Asia. Collectively, these
regions account for a mere ~12% of global GDP share, and prospects are that this
share will rise only marginally over the next 10-20 years.
0
2
4
6
8
10
12
2006 2007 2008 2009 2010 2011
GD
P G
row
th, %
/Yea
r
EU-27 N. America L. America Japan China WORLD
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Table 1-1 Short-to-Medium Term Real (GDP) Economic Growth Trend and Forecast 2005-2011
Region 2005 2006 2007 2008 2009 2010 2011 N. America* 3.2 3.4 2.2 2.7 3.4 2.9 2.7 EU-27 1.8 3.0 2.8 2.6 2.5 2.1 2 L. America 5 5.1 4.4 4.2 4 3.9 4.1 Japan 3.3 2.3 1.9 2.2 0.9 1.8 2 China 10.2 10.7 10.5 10 9.5 9 9.2 WORLD 4.8 5.3 4.4 4.6 4.5 4.3 4.4
*USA plus Canada
Table 1-2 summarizes the long term economic growth forecast for the same key
regions to the year 2026. This includes the large and mature economies of North
America, Western Europe and Japan, emerging economies in Asia and Latin
America, as well as the All Other category (not included in Table 1-1).
Table 1-2 Long Run (2006-2026) Regional Average Economic Growth Rate Projections and Share of Global GDP
The share of GDP held by the developed economies will be dropping as a result of
faster growth in developing regions. The 47% collective share in 2006 for the three
largest developed regional economies (North America, Western Europe and Japan)
is forecast to decline to 33% by 2026. At the same time, the proportion held by
China is expected to increase from 17% to 30%. This will result in a corresponding
re-structuring of relative demand in regional paper and paperboard markets, with the
position held by China/Other Asia growing at the expense of the mature, developed
economies.
2011-16 2016-21 2021-26 2006-26North America 22 3.4% 3.3% 2.3% 2.7% 17EU-27 19 1.8% 2.1% 1.2% 2.1% 12Japan 6 1.5% 2.3% 1.2% 1.8% 4China 17 7.9% 7.4% 5.4% 7.1% 30Other Asia 15 5.8% 5.4% 4.3% 5.2% 18Latin America 8 4.1% 3.7% 3.1% 3.7% 7All Other 14 4.6% 3.3% 0.9% 3.9% 12Total World 100 4.6% 4.5% 3.2% 4.2% 100
Average Annual Growth Rate, %/Yr 2026 GDP Shares, %
2006 GDP Shares, %
Region
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1.1.3 North America
USA: Following three successive years of healthy expansion, in the 3-4% per year
region, US real economic growth is expected to drop to the 2-2.5%/year this year
(2007) and only slightly better, 2.5-3%/year range, next year (2008). The main
culprits responsible for slower growth rate are the ongoing downturn in the housing
sector, resulting pressure on consumer spending, and cautious corporate capital
investments. During the first quarter of 2007, US real GDP growth was barely over
1% on an annualized basis. Consumer spending accounted for much of this growth,
however its growth continues to slow. Essentially, residual consumer spending
strength, attributed to a booming stock market and favourable employment and
income gains over the past year or two, is getting depleted. Aggravating this
situation and depressing consumer confidence have been inflationary pressures
(especially increased energy prices), which further constrain household purchasing
power. Declining housing affordability, as a result of about 8-10 years inexorable
rise in housing prices is of course a major driver for ongoing weakness. As
consumers scale back spending, private sector firms may pick up some of the slack,
but most companies learned to be cautious in the 2001-02 downturn. On the
positive side, a weakening US dollar (see later Figure 1-4) and healthy foreign
demand should continue driving exports, particularly in high tech products, including
aircraft and industrial machinery. Moderating US consumer spending is expected to
reduce import demand, hopefully resulting in some trade deficit reduction. However
significant reduction in the deficit, from the approximately US$800 billion per year
level it has ballooned to, will not be easy to achieve due to the huge US reliance on
imported energy and robust appetite for low-cost products manufactured in China
and other emerging nations.
Canada: Canada’s economy, boosted by recent strong growth in its largest trading
neighbour to the south, coupled with rising commodity demand and prices in
resource-constrained emerging countries (especially in Asia, and within Asia the
China powerhouse), has also exhibited strong growth during the last 2-3 years. A
result of energy and other commodity price spikes in the last few years has been a
significant increase in the strength of the Canadian dollar against its US counterpart.
From near record lows of about US $0.62 in early 2002, the Canadian dollar has
recently spiked as high as US $0.95, with some forecasters projecting parity with the
US dollar before longer term correction. This has dealt a devastating blow to
Canadian (including BC) pulp and paper companies’ profitability, with almost all
companies showing losses during the last 4-5 years.
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Recent trends and current short-medium term predictions for the Canadian vs. the
US dollar are summarized in Figure 1-4. [Note: Forecasting long term exchange
rates is a risky and meaningless exercise, as too many unpredictable factors
influence exchange rate relationships.] The expectation is for the Canadian dollar to
peak around its current level of around US$(0.94-0.95), and to remain above US$0.9
through 2008. The sharp increase in the Canadian dollar strength of the last few
months has resulted in further significant deterioration of the Canadian and BC pulp
and paper companies’ cost-competitive position.
Figure 1-4 US$/C$ Exchange Rate Trend and Short Term Forecast
1.1.4 Asia
With the exception of the relatively large Japanese economy, which exhibited
anaemic growth during the last 10-15 years (but which is showing signs of a revival
during the last 1-2 years), Asian economies have outperformed all other regions in
average growth rate. China, which has led, and continues to lead, the world in
economic growth during the last 8-10 years, is of course the shining example,
consistently turning growth rates in the 9-10% per year region. More recently, India
is also moving into the fast lane and approaching China’s growth rate, with other
regional economies (Korea, Taiwan, Thailand, other) at highly respectable and
enviable growth rates in the 4-6% per year region.
0.84
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0.92
0.94
0.96
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US
$:C
an$
Forecast
History
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Japan: After several years of barely positive, and often negative (contraction)
economic growth, the Japanese economy appears to have returned to moderate and
sustainable growth characteristic of mature economies with slow/no population
growth similar to Western Europe’s. Business investment and foreign trade are the
two primary drivers, with government and consumer spending remaining depressed.
China (and India): China is expected to continue leading all other economies, with
8-10%/year growth over the next few years, and around 7%/year in the longer term.
Some re-structuring is under way, with the government focusing more effort on
encouraging consumer spending and rural development, as opposed to primarily
capital expenditures which has been the dominant driver in recent years. However,
the Chinese government is being (wisely) cautious to avoid significant slowdown in
overall economic activity, as this will likely lead to job losses and social unrest.
Another ongoing development will be some speed-up in the pace of renminbi
appreciation in 2007-08. [Note: This should set the stage for further yen, as well as
other regional currencies, appreciation.] India is now second only to China as an
emerging economic powerhouse. Economic growth is expected to expand by an
average of 7.5-8%/year in 2007-08, as Indian manufacturers focus increasingly on
exports, rather than their traditional focus on the rather limited domestic market.
Strong development of internationally focused Indian-based software development
and business services is a major contributor to growth, although appreciation of the
rupee is beginning to dampen expansion in some export-oriented activities.
Other Asia: Economic growth prospects remain positive for most other Asian
countries. South Korea and Taiwan managed to cope with recent escalating energy
costs without suffering significant economic growth dislocations, and other countries,
such as Thailand and Indonesia, are continuing their shift to industrialized status.
Average growth rates in the 4-6%/year region are expected for most of these
countries.
1.1.5 Euro-27 (Original European Union Members plus Recent New Ones)
Following several years of lacklustre performance, Western European economic
growth has taken a significantly brighter hue in recent months. In fact, Western Europe
will, for the first time in years, outperform North America in economic growth this year
(2007). A major contributor is the return of the largest regional economy, Germany, to
healthier activity levels, after several years of little or no growth. Reduced
unemployment (down from around the 10% level about 2-3 years ago to 7-7.5% now)
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is contributing to rising consumer expenditures and confidence, although traditional
negative factors, such as high taxation rates and aging population, continue to act as
inhibitors to even faster growth. Another contributor, not so readily recognized, is the
ongoing addition of new EU members (e.g. Poland, Slovenia, and others, which have
raised the total number of EU members from the initial 12 to 27). Although the per
capita GDP of these new members lags well behind that of the large, developed
economies of Germany, UK, France and Italy, GDP growth of the new members is, on
average, significantly faster (e.g. 3-3.5%/year vs. around 2% for the mature economy
members).
[Special note on paper exports: Rapidly rising paper and paperboard demand of new
EU members, as their economies strengthen, is driving increased exports from
traditional large Western European paper producers, such as Scandinavia and
Germany. In the longer term, and unless the US dollar appreciates significantly
against the euro, this should result in less aggressive exports to North America, and
benefit North American paper producers.]
The implications of recent euro:US$ exchange rate trends and future outlook are
discussed in some detail in the final Section, 1.1.8. For now, suffice it to note that the
significant appreciation of the euro against the US dollar since 2002 has helped
contain European inflation, but at the same time it has reduced the cost-
competitiveness of European exports.
1.1.6 Latin America
Latin America has enormous economic growth potential. Unfortunately, although the
sustainable growth objective appears to be getting closer, the region still has to shed its
traditionally unstable and erratic performance image. Nevertheless, driven by increasingly
stable and growth favouring conditions in large economies (Brazil, Chile, Mexico, Peru,
Colombia), as well as improving conditions of economies in crisis 3-4 years ago (Argentina
and Venezuela), the region is expected to continue improving steadily. GDP growth rate, in
the 4-6%/year region over the next few years will be much faster than (mature) North
America’s growth. Furthermore, healthy foreign exchange reserves (estimated in the US
$250 billion region for the top 5-6 regional economies) are minimizing the traditionally
unpleasant currency fluctuation and resulting inflation fears, and are encouraging consumer
spending. The major short term inhibitor to even higher economic growth rates, whose
adverse impact will be felt most strongly by Mexico, is the 2007-08 slowdown of the large
US economy, which will limit Latin American exports and overall trade with the USA.
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1.1.7 Special Section on Eastern Europe and the Former USSR
This region, under communist rule for many decades until about 1990, has a
relatively small share (about 3-4%) of global GDP, therefore it is included in the “All
Other” categories in Table 1-2. However, it deserves special mention and overview
for the following reasons:
• The former USSR has enormous forest products potential, since Russia has the
world’s largest reserve of free standing softwood timber. We would anticipate
that, over the next 10-15 years, Russia will begin exploiting this valuable
resource, not just as an exporter of raw materials (logs to China, Japan, and
Finland), but as a producer of manufactured products (lumber, pulp and paper).
• Steps are being taken to extract greater value from this resource. As an
example, a huge increase in the log export tax (from 6.5% to 80%) was
announced by president Putin in February-2007, to be implemented by July-
2009. Clearly the primary objective of this quantum jump in the export tax is to
encourage domestic manufacture of forest products.
• The transition to a market economy and higher petroleum prices are driving
faster average GDP growth for the region.
• Finally, this region is characterized by a highly educated population, including
scientists and engineers able to develop, manage and operate state-of-the-art
machinery and processes.
During the last few years, the region’s economic growth, led by the relatively large
and growing Russian economy, has outperformed the mature economies as well as
most other regions, with the exception of China. This trend is expected to continue
to at least 2015 and possibly beyond, with GDP growth in the 4-6%/year range. A
beneficial result is that rising personal wealth is driving demand for advertising and
business papers. However, the capacity to manufacture such papers in Russia and
other Eastern European countries is almost negligible. As a result, Western
Europe’s share of exports of high value publication papers to Russia and other
Eastern European countries has been rising, at the same time as the share of
Western European paper exports to North America has been declining, as shown in
Figure 1-5. This minimizes, to a degree, traditionally aggressive Western European
exports to North America.
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Figure 1-5 Export Shares of Advertising-Driven Papers from Western Europe
Prior graph needs to be fixed
1.1.8 Key Currency Exchange Rates Trend and Forecast
Figure 1-6 summarizes the significant decline of the US dollar (the major global
commodity price currency) against the euro during the last few years (see earlier
Figure 1-4 for Canadian dollar exchange rate forecast).
Figure 1-6 Euro vs. US$ Exchange Rate Trend and Forecast to Q4-2008
0%
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40%
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100%
1995 2000 2005 1995 2000 2005
Sh
are
Of
W. E
uro
pea
n E
xpo
rts,
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E. EuropeOther ExportsN. America
Coated Mechanical Grades Supercalendered Grades
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Table 1.-3 provides a summary average annual forecast of the euro and Canadian
dollar exchange rate against the US dollar to the year 2009. Regional manufacturing
cost-competitiveness, expressed in US$ per tonne of product, will be affected by the
relative currency positions.
Table 1-3 Key Currency Exchange Rates vs. the US Dollar
Exchange Rate 2002 2003 2004 2005 2006 2007 2008
US$/CDN$ 0.637 0.716 0.770 0.826 0.882 0.929 0.938 US$/Euro 0.945 1.132 1.244 1.244 1.256 1.30 1.31
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1.2 Global Outlook for Pulp and Paper
1.2.1 Background Overview/Summary
Global paper (including paperboard) demand rose a healthy 12.6 million MT (3.4%)
in 2006 over 2005, as seen in Figure 1-7. Over the 10-year period 1996-2006, the
cumulative demand increase was around 100 million MT, or 35% of 1995 demand,
robust growth for a mature industry indeed.
Figure 1-7 Global Paper and Paperboard Consumption Trend 1994-2006
However, as seen in Figure 1-8, North America’s share of the cumulative 10-year
(1995-2005) demand increase has been the smallest of all major regions at 7%
(right hand chart), in spite of the fact that its 1995 baseline demand share was the
largest at 33% (left hand chart). Asia has the dominant share of paper demand
growth, with a nearly 60% share of the 10-year demand increment. This trend is
expected to continue, and it reflects a combination of factors, notably:
• Much faster paper/board demand growth of emerging economies in Asia, in
particular China.
• Market maturity in the developed, advanced economies of North America and
Western Europe (as well as Japan, not separated out from Asia here).
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360
380
400
1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006
Mill
ion
MT
-3
-2
-1
0
1
2
3
4
5
6
7
%/Y
ear
Million MT %/Year
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Figure 1-8 1995 Baseline Paper/Board Demand Regional Shares and 1995-2005 Incremental Cumulative Demand Shares
A direct result will be an ongoing restructuring of regional shares, with the mature
markets (North America, Western Europe, Japan) losing share to emerging
economies in Asia, Latin America, and the rest of the world – see Figure 1-9.
Figure 1-9 Paper/Board Regional Demand Share Shifts 1995 to 2005
N. America
33%
W. Europe
24%
Asia30%
All Other13%
1995 1995-2005
N. America
7%W. Europe
19%
Asia58%
All Other16%
Baseline Demand Shares Demand Increment Shares
0
5
10
15
20
25
30
35
N. America W. Europe Asia All Other
% S
har
e O
f G
lob
al D
eman
d
1995 2005
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The pulp and paper industry has had an increasingly challenging time in recent
years, in particular in mature, developed economies. Return on capital employed
(ROCE) has been especially low during the current decade, and has caused
numerous pulp mill and paper machine closures (also some corporate bankruptcies
in North America). Figure 1-10 summarizes key regional comparisons, showing
emerging low cost producers (Latin America) and high paper demand growth (non-
Japan Asia) regions outperforming competitors in mature, developed regions.
Figure 1-10 Regional Average Pulp & Paper ROCE Comparisons 2005 & 2006 (Source: PricewaterhouseCoopers Annual Paper & Packaging Survey)
Figure 1-11 compares ROCE of key, specific, major Canadian pulp and paper
producers, showing a vastly inferior performance in comparison with two major
South American competitors.
0 2 4 6 8 10
W. Europe
Japan
USA
Canada
Non-Japan Asia
L. America
ROCE, %
20062005
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Figure 1-11 Key Regional Pulp & Paper Corporate ROCE Comparisons (Source: PricewaterhouseCoopers Annual Paper & Packaging Survey)
The root cause of poor performance of Canadian pulp and paper companies is
illustrated in the conceptual chart of Figure 1-12. Essentially, over the last few
decades, the constant dollar market price of major pulp and paper commodities has
been declining at a faster rate than the decline in Canadian producers’ delivered
costs. Eventually the two declining trends have converged, and delivered costs now
often exceed market price, resulting in red ink on the bottom line. A direct result of
this has been the shutdown of dozens of paper machines and removal of over 2
million tonnes/year of bleached kraft capacity in North America since 1999.
Figure 1-12 Conceptual Chart of Market Price and Delivered Cost Trend for Major Pulp and Paper Products
95
105
115
125
135
1970 1975 1980 1985 1990 1995 2000 2005
Pri
ce In
dex
In C
onst
ant $
/MT
Delivered Cost
Price
-4 0 4 8 12 16
Aracruz-Brazil
Klabin-Brazil
Arauco-Chile
VCP-Brazil
Catalyst
Domtar
Abi-Con
Canfor
Tembec
ROCE, %
20062005Canada
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Forward projection of paper consumption for a given region is simply determined by
the product (population) x (average per capita paper consumption). Changes in
either of these two parameters bring about a change in paper consumption. Over
the last few decades, since at last the end of WWII (when global paper consumption
stood at 29-30 million MT – compared with 380 million MT in 2006) real GDP and
GDP/capita growth have been the primary drivers for incremental paper demand.
There are, of course, regional differences in the absolute numbers (kg of paper per
capita per year), based on differences in regional resource, economic and cultural
characteristics. However, for 50-60 years, to the beginning of the current decade,
the paper demand to GDP relationship has held. This changed in North America in
recent years, with ongoing de-coupling of paper demand from GDP growth for
certain grades and end uses. It appears that similar trends are underway in other
mature, developed economies, although currently at an earlier, embryonic stage.
Global population growth has followed a power law for the last few centuries, and
especially the last few decades, as medical breakthroughs and improved living
standards have resulted in significantly increased adult longevity and decreased
infant mortality. There are, however, significant differences in regional population
growth rates, with developing nations generally growing much faster than developed
ones. Table 1-4 summarizes trends and forecasts to 2030.
Table 1-4 Regional Population and Population Growth Rates by Continent 2000-2030 (Data in Millions of People and %/Year)
2000 2010 2020 2030 CAGR 2000-2030 REGION Millions %/Year
Americas 836 935 1,027 1,110 1.0% Europe 730 728 721 704 -0.1% Asia 3,687 4,136 4,566 4,904 1.0% Africa 797 982 1,189 1,416 1.9% Oceania 31 35 38 41 1.0% WORLD TOTAL 6,080 6,816 7,542 8,175 1.0%
Figure 1-13 summarizes global population and GDP from 1990 to 2030, showing
healthy growth in both parameters.
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Figure 1-13 World Population and GDP 1990-2030
With regard to paper/board consumption, there are truly enormous regional
differences in per capita paper/board consumption, as summarized in Table 1-5.
Table 1-5 Apparent* per Capita Consumption of Paper & Board for Selected Regions or Countries (2006)
Country/Region Per Capita Paper Consumption (kg/capita/year)
N. America 295 (down from ~325 in 2000) Japan 250
Oceania 156 China 49 Brazil 42 Africa 6.5
* Apparent consumption is the favoured parameter for estimating paper/board consumption of a given region. It is defined as regional Production+Imports-Exports
1.2.2 Regional Pulp and Paper Forecasts to 2026 – General Considerations
Background Issues and Forecasting Pitfalls
Forecasting is a hybrid endeavour between art and science. It uses some scientific
tools (statistics, trends, moving averages, correlation, and so on), but ultimately a
forecast is based on assumptions about future developments that are impossible to
predict with certainty. As a result, forecasts have a great deal of built-in uncertainty.
0
3,000
6,000
9,000
1990 2000 2010 2020 2030
Po
pu
lati
on
, M
illio
n
0
50
100
150
GD
P,
Tri
llio
n 2
005
US
$
Population GDP In 2005 US$
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Some common forecasting errors, which have plagued major forecasting
organizations or think tank forecasts in the last 5-10 years, have included:
• Simplistic assumptions relating fixed links between per capita paper
consumption and per capita GDP (not all societies achieving a given level of per
capita income will have a per capita consumption as high as North America’s
~325 kg/capita/year in 1999-2000 at the same per capita income).
• Linear extrapolation of historical trends, a technique many economists favour,
which unfortunately does not consider evolutionary changes in market structure
or manufacturing process technology and products.
As recently as the 1990s, the UN FAO long-term forecasts of paper and paperboard
consumption to the year 2010 were as high as 480-490 million tonnes. Coincident
with a staff change in 1996, the UN FAO’s traditionally optimistic forecast for paper
and paperboard consumption in the year 2010 was downgraded significantly to 396
million tonnes, a huge, 20% reduction (which is actually shaping up to have been
too much of a reduction). Quoting directly from the FAO document “The Global
Outlook for Forest Products”, relating to timber demand for fuel and industrial forest
products (solid wood products plus pulp and paper): “FAO issued global projections
in 1991 and 1995. Soon afterwards, it commissioned an evaluation of the forecasts,
which revealed some methodological weaknesses and a tendency for the
results to be too high, partly due to over-optimistic assumptions of economic
growth”.
Forecast Methodology
The forecasting methodology includes, on a regional and global basis, the effect of a
number of key factors, notably:
• Population and economic growth forecasts.
• Demographic and socio-economic trends and forecasts (population age
distribution, literacy, workforce structure, and so on).
• Resource, market and industry structural evolution.
• The impact of electronics on paper demand, including the bypassing of some
traditional paper end uses by emerging economies as they move up towards
developed economy standards. An example of this is (paper) telephone
directories which may well be by-passed in favour of electronic directories, as
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emerging economies make the transition to modern telecommunication systems.
This is even evident in telephone hardware, where many users in Latin America
and Asia have gone directly to cellular phones due to limited land-line system
capacity. In developed nations digital substitution has begun to have a negative
effect on key end use sectors, such as newspapers, business forms, books,
magazines, and so on.
• The effect of ongoing reductions in the average basis weight (weight per unit area)
of most paper products, as technological developments allow the production of
lighter weight (in grams per square metre) paper while maintaining product
performance.
Major Assumptions
The forecast is based on the following key underlying assumptions:
• The forecast population and economic growth trends provided in the earlier
sections of this report will proceed without disruption by radical changes, such
as massive scale natural catastrophe, disease, famine or military conflicts.
• The regions with the greatest economic growth over the next 20 years will be
developing areas, (especially Asia and Latin America) subject to sufficient
capital being made available for required expansions.
• The old USSR countries experienced highly adverse conditions after their
economic and social structure collapse in the 1990s. However, most have made
the transition to free market economies, and even though their share of global
GDP (and paper demand) remains relatively small, they will continue exhibiting
high economic and paper demand growth rates during the next 15-20 years.
• North America and Western Europe will continue to lose share of global paper
demand, as paper demand of other regions grows faster.
• World population, which went over the 6 billion mark at the turn of the century,
will exceed 7.5 billion by 2020 and reach 7.9 billion by 2026, this project’s
forecast horizon.
• Market pressures, including environmental campaigns, will continue to influence
industrial strategies. In developed nations, these campaigns will generally have
a negative impact on paper and paperboard demand.
• Maximization of Performance/Cost ratios and Resource Value Addition will drive
new technology and products, as well as the paper industry’s development. This
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is noted here for the record as it is a relatively complex subject to explore and
analyze in detail.
• Pulp and paper industry, as well as supplier (chemicals, pigments, machinery)
consolidation will continue on a regional and global basis, as the industry tries to
become more competitive and profitable.
• Regional resource constraints and economics will drive utilization of recycled
fibre and the choice of grades to be produced in the different world regions.
• Smaller and substitute packaging products, and electronic substitution, will
continue to have an increasingly strong (negative) impact on paper and board
tonnage growth in the next 10-20 years, especially in developed, mature
economies.
• Government regulations will affect production and specifications for products,
but there will continue to be significant differences between producing and
consuming regions.
• Technological advance and improvements in paper and paperboard industry
productivity will continue to satisfy market demand for a wide range of consumer
products at competitive prices.
• Real (i.e. excluding the effect of inflation) product prices will continue their
gradual downward trend. For some products and regions, however, resource
constraints will slow this down and may eventually (after 2010-15) reverse it.
• Mandatory inclusion of increasing quantities of recycled fibres will continue in
North America and Western Europe, although it levelled off by the late 1990s as:
– governments/legislators began to appreciate the fact that there are
economic factors limiting wastepaper utilization rates;
– incremental wastepaper availability declined (aggravated by China’s ongoing
explosive demand increase).
• Southeast Asia will have the largest relative (%/year) growth in paper demand,
especially in mature grades such as newsprint, in which the developed societies
are exhibiting signs of peaking demand and the onset of decline (North
American annual newsprint consumption reached a peak around 1988, and it
has dropped a huge 25-30% since a short-lived demand spike in 1999-2000).
• The P&W grades market will continue to demand quality, but will accept some
changes in specifications (hybrid mechanical-woodfree grades, higher
recycled/filler content) for cost-effectiveness.
• Improved literacy will drive demand for printing papers, but digital alternatives
will have the reverse effect in certain sectors.
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• Tissue will exhibit healthy demand growth rates, particularly as living standards
in developing nations improve with economic growth. As a rough rule of thumb,
tissue demand begins to grow strongly once average annual income per capita
goes over $2,500. However, in mature (high per capita demand), developed
markets, growth rates will follow the slow population growth rates and
demographic trends (e.g. adult incontinence products as the population ages).
• Packaging, especially in developed countries, will continue to be subject to strict
environmental controls (integration of selling and recovery/reuse functions).
• Increased industrialization and export trade from/by East/Southeast Asia will
require more packaging papers and boards in that region. However, the quest
for regional self-sufficiency of this relatively low per capita natural (forest)
resource region will continue.
• The continued growth in paper and paperboard consumption will require ongoing
increases in the supply of pulp, both market and integrated. However, during
the period under review, there will be changes in grade mix, source of supply
and increased use of substitutes for virgin fibre chemical wood pulp, most
notably recycled fibres and filler/coating agents.
• There will be some economic constraints on regional wood fibre resource
availabilities. The BC Interior mountain pine beetle infestation will have a major
adverse impact on resource quality and availability over the next twenty years.
• The Internet will (continue to) have an increasingly strong negative impact, in
particular on graphic or communication papers, namely newsprint and P&W
papers. North America is exhibiting increasingly strong signs of “de-coupling” of
paper demand from economic growth, as noted earlier.
Finally, it should be noted that global consumption has grown ten-fold in the sixty
years between 1945 and 2005, rising from 29-30 million tonnes per year to 368
million tonnes in 2005. This is an impressive 4.3% per year compound average
annual growth rate over this relatively long, 60-year period.
1.2.3 Long Term Regional Paper/Paperboard Demand Forecasts for Major Grades
The following summary points should be noted:
• Paper demand in mature/developed economies (North America, Western
Europe, Japan) with high per capita consumption will grow slower than average,
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in particular for graphic papers (newsprint plus printing and writing, P&W) which
are increasingly feeling the negative impact of digital substitution.
• Rapidly growing emerging economies, notably those of Asia and Latin America
will exhibit the highest demand growth rates. A high demand growth rate will
also be seen in Eastern Europe, as it continues its transition to market economy
and faster than (global) average economic growth.
Tables 1-6 and 1-7 summarize long term paper/board growth forecasts by major
grade and region respectively, with historical data for 1995 and 2000, as well as 5-
year interval forecasts between 2006 and 2026.
Regarding major grades, Table 1-6 shows that tissue and Other (mostly packaging
grades) will exhibit the fastest growth, while the mature, newsprint grade is forecast
to grow at the slowest rate.
Table 1-6 Global Paper and Paperboard Consumption to 2026 by Major Grade(in million tonnes by year)
On a regional basis, Table 1-7 shows that the fastest growth rates will be in Asia
and Latin America, whereas the mature economies of North America and Western
Europe will grow slowest. The All Other category is also forecast to grow at a faster
than average rate, as the countries in Eastern Europe and CIS, get their free market
economies moving increasingly strongly, and Middle East economies improve.
1995 2000 2006 2011 2016 2021 2026Grade 2006-16 2011-21 2016-26
Newsprint 35.1 39.6 39.1 42.2 44.9 46.0 46.1 1.4% 0.9% 0.3%P&W 83.4 101.7 114.7 129.4 142.4 152.0 157.9 2.2% 1.6% 1.0%Tissue 16.8 20.9 26.3 31.4 37.6 44.2 49.8 3.6% 3.5% 2.8%Other 142.8 162.9 200.2 235.2 270.7 308.5 343.7 3.1% 2.7% 2.4%
TOTAL 278.1 325.1 380.3 438.2 495.5 550.7 597.5 2.7% 2.3% 1.9%
CAGR, %/YearMillion MT/Year
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Table 1-7 Global Paper and Paperboard Consumption to 2026 by Major Region (in million tonnes by year)
The above tables show fastest growth for:
A) Tissue among paper/board grades,
B) Asia, All Other, and Latin America among regions.
Graphic papers (Newsprint and P&W) will grow slowest.
Tables 1-8 to 1-10 provide the summary forecasts by region for each major
paper/paperboard grade class.
Table 1-8 Regional Newsprint Demand Forecasts to 2026 (million tonnes and %/year)
Global newsprint demand will grow more slowly than that of any other major paper
and paperboard sector. Demand growth has already turned negative for the highly
developed North American market, and it is expected to do so for Western Europe
and Japan in the next few years (note that Japan is included in the total Asian
demand which will remain positive due to robust demand increase of the rest of
Asia).
Latin America, Asia and the All Other category, which includes the old Soviet Union
countries, will exhibit intermediate to strong growth. Asia’s aggregate growth rate is
1995 2000 2006 2011 2016 2021 20262006-16 2011-21 2016-26
N. America 92.4 100.3 98.6 100.5 102.2 103.6 104.0 0.4% 0.3% 0.2%W. Europe 66.5 80.4 83.7 90.1 95.0 97.3 98.2 1.3% 0.8% 0.3%Asia 82.4 99.5 136.6 171.4 205.5 238.5 267.2 4.2% 3.4% 2.7%Latin America 15.0 19.4 22.9 27.3 32.1 37.4 41.8 3.4% 3.2% 2.7%All Other 21.8 25.5 38.5 49.0 60.8 73.9 86.3 4.7% 4.2% 3.6%TOTAL 278.1 325.1 380.3 438.2 495.5 550.7 597.5 2.7% 2.3% 1.9%
REGIONMillion MT/Year
CAGR, %/Year
1995 2000 2005 2006 2011 2016 2021 2026 2006-16 2011-21 2016-26
N. America 12.8 13.0 10.4 10.0 8.5 7.9 7.2 6.5 -2.3% -1.6% -1.9%W. Europe 9.3 10.9 10.3 10.5 11.3 10.9 9.8 8.5 0.4% -1.4% -2.5%Asia 8.3 10.1 11.9 12.4 14.8 17.0 18.5 19.7 3.2% 2.3% 1.5%Latin America 1.9 2.0 1.8 1.8 2.0 2.2 2.3 2.4 1.8% 1.5% 0.9%All Other 2.8 3.6 4.3 4.4 5.6 6.9 8.2 9.0 4.7% 3.9% 2.7%TOTAL 35.1 39.6 38.6 39.1 42.2 44.9 46.0 46.1 1.4% 0.9% 0.3%
CAGR, %/YearGRADE
Million MT/Year
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dragged down by the large (currently about 25% of total Asian market size, down
from 30% 4-5 years ago), mature Japanese market. This (Japanese) market is
growing very slowly, with no prospect for change, based on demographics (aging
population and economic growth rate, while the rest of Asia is growing faster than
any other region in the world, and it is expected to continue to hold that position for
some time to come.
Table 1-9 Regional P&W Papers Demand Forecasts to 2026 (million tonnes and %/year)
P&W papers growth rate used to be second to the fastest growing tissue sector (see
below). However, primarily as a result of digital (Internet) substitution in major, key
end sectors, in particular advertising-dollar-driven ones such as magazines and
catalogs, it has now been relegated to third place, just ahead of the slowest growing
Newsprint sector.
Again, Asia, Latin America and All Other will exhibit the highest growth rates, while
the mature North American market will grow slowest, and Western Europe will be
somewhere in the middle. Asia excluding Japan (whose slow growth drags down
the aggregate average for Asia) will grow fastest.
Table 1-10 Regional Tissue Papers Demand Forecasts to 2026 (million tonnes and %/year)
1995 2000 2005 2006 2011 2016 2021 2026 2006-16 2011-21 2016-26
N. America 28.5 32.1 31.4 31.5 31.8 31.5 30.5 29.0 0.0% -0.4% -0.8%W. Europe 22.3 28.9 28.7 29.6 32.0 33.5 33.0 32.0 1.2% 0.3% -0.5%Asia 24.8 30.1 36.2 37.3 44.3 51.5 58.0 63.0 3.3% 2.7% 2.0%Latin America 3.5 4.6 5.0 5.1 6.2 7.4 8.7 9.4 3.8% 3.4% 2.4%All Other 4.3 6.0 10.3 11.3 15.1 18.5 21.8 24.5 5.1% 3.7% 2.8%TOTAL 83.4 101.7 111.6 114.7 129.4 142.4 152.0 157.9 2.2% 1.6% 1.0%
CAGR, %/YearREGION
Million MT/Year
1995 2000 2005 2006 2011 2016 2021 2026 2006-16 2011-21 2016-26
N. America 6.2 6.9 7.6 7.7 8.2 8.8 9.4 10.0 1.4% 1.4% 1.3%W. Europe 3.9 5.4 5.7 5.9 6.8 7.9 9.0 9.7 2.9% 2.8% 2.1%Asia 3.9 5.0 7.2 7.7 9.8 12.0 14.0 15.5 4.5% 3.6% 2.6%Latin America 1.6 2.0 2.4 2.6 3.2 4.0 4.9 5.8 4.6% 4.4% 3.8%All Other 1.3 1.6 2.4 2.4 3.5 4.9 6.9 8.8 7.3% 7.2% 6.0%TOTAL 16.8 20.9 25.3 26.3 31.4 37.6 44.2 49.8 3.6% 3.5% 2.8%
CAGR, %/YearREGION
Million MT/Year
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Tissue demand growth rates remain the highest of all paper and paperboard grades.
North America, the world’s most sophisticated market and technology region for
tissue production, is in the process of relinquishing this additional (to newsprint and
P&W) number one position as a consumer to Asia. Once more, relative growth
rates will be highest for Asia, Latin America and All Other, and lowest for North
America, with Europe in-between.
Table 1-11 Regional Packaging/Other Papers Demand Forecasts to 2026 (million tonnes and %/year)
Much like all other major grade sectors, the mature, industrialized economies of
North America and Western Europe will grow slowest in packaging and
miscellaneous other (industrial, specialty) grades, while emerging economies in
Asia, Latin America and All Other categories will grow fastest.
1.2.4 Virgin Woodpulp Long Term Forecasts to 2026
The forecast of global (virgin) woodpulp demand, as well as the corresponding
woodpulp percentage of total paper/paperboard produced, are both provided in
Table 1-12.
Table 1-12 Global Wood Pulp Consumption Forecasts to 2026 (million tonnes and %/year)
1995 2000 2005 2006 2011 2016 2021 2026 2006-16 2011-21 2016-26
N. America 44.9 48.3 48.5 49.4 52.0 54.0 56.5 58.5 0.9% 0.8% 0.8%W. Europe 31.0 35.2 37.3 37.7 40.0 42.7 45.5 48.0 1.2% 1.3% 1.2%Asia 45.5 54.3 74.6 79.2 102.5 125.0 148.0 169.0 4.7% 3.7% 3.1%Latin America 8.0 10.8 12.8 13.4 15.9 18.5 21.5 24.2 3.3% 3.1% 2.7%All Other 13.4 14.3 19.0 20.5 24.8 30.5 37.0 44.0 4.1% 4.1% 3.7%TOTAL 142.8 162.9 192.2 200.2 235.2 270.7 308.5 343.7 3.1% 2.7% 2.4%
CAGR, %/YearREGION
Million MT/Year
1995 2000 2005 2006 2011 2016 2021 2026 2006-16 2011-21 2016-26
Total Global Woodpulp Demand
155.8 166.6 171.9 176.5 194.6 214.3 234.6 251.5 2.0% 1.9% 1.6%
Woodpulp % Of Paper
56% 51% 47% 46% 44% 43% 43% 42%
Million MT/Year CAGR, %/Year
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Virgin woodpulp demand will grow at about 80% the rate of growth in paper/board
demand over the next 10-20 years. The reason is faster growth in recovered paper
(wastepaper) recycling and mineral pigment (clays, calcium carbonates, other
minerals) utilization in the production of paper, driven by the need to maximize
paper quality at minimum cost. As a result, the percentage of virgin woodpulp in the
global furnish will continue declining, as seen in the above table (last row).
However, once it goes below about 45% of paper tonnage share, it is expected to
begin levelling off, since recycled paper/fibre quality deteriorates at wastepaper
utilization rates (wastepaper as percent of total paper raw materials) higher than
about 55%.
1.2.5 Long Term Recycled Fibre Trends and Forecast
Table 1-13 summarizes the recovered paper demand by major region. Asia will
again lead global demand growth. For the time being, the major supplier of
wastepaper to Asia is the large, US source of supply. [Note: The strong Asian
demand has been driving US wastepaper prices up during the last 6-7 years,
compounding North American paper producers’ financial woes, through higher raw
material costs for recycled paper products.]
Table 1-13 Regional Wastepaper Demand Long Term Forecasts to 2026
Figure 1-14 summarizes processed recycled fibre and woodpulp share trends,
adding to 88-90% of paper/board raw materials. The remaining 10-12% consists of
non-wood (e.g. bamboo, straw) pulp and mineral pigments. [Note: Recycled fibre is
an insignificant raw material for BC papermaking, so it is not analyzed further here.]
1995 2000 2005 2006 2011 2016 2021 2026 2006-16 2011-21 2016-26
N. America 33.5 36.3 34.9 35.7 37.4 39.4 41.7 42.3 1.0% 1.1% 0.7%W. Europe 30.5 41.0 44.0 45.9 49.2 54.1 55.8 55.6 1.7% 1.3% 0.3%Asia 36.5 54.0 59.9 65.0 86.8 105.5 122.9 137.4 5.0% 3.5% 2.7%All Other 10.5 17.3 42.6 43.8 51.3 59.8 70.3 81.8 3.2% 3.2% 3.2%Total Global Demand
111.0 148.6 181.4 190.4 224.6 258.9 290.7 317.0 3.1% 2.6% 2.0%
Wastepaper % Of Paper
40% 46% 49% 50% 51% 52% 53% 53%
Million MT/Year CAGR, %/Year
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Figure 1-14 Virgin Woodpulp and Recycled Fibre* Shares Forecast to 2026
*Note: This is lower than actual wastepaper percentage, since about 15% of wastepaper tonnage is lost in processing it to recycled fibre.
1.2.6 Long Term Regional Market Pulp Demand Trend and Forecast to 2026
Table 1-14 summarizes market pulp demand forecasts by major region, a parameter
of much greater interest in this study than total (integrated plus market) woodpulp
demand, since BC is a major market pulp supplier to the world, and market pulp is
the primary BC pulp and paper product. It is seen that, unlike the slower growth
forecast for total virgin woodpulp in the earlier Table 1-12, market pulp demand
growth rate will be similar to that for paper and paperboard, reflecting the fact that
most of the papermaking capacity growth will be in regions with limited forest
resources, notably China, India and other emerging Asian economies.
Table 1-14 Global Market Pulp Consumption Forecasts to 2026 by Major Region (million tonnes)
30%
35%
40%
45%
50%
55%
60%
1995 2000 2005 2010 2015 2020 2025
% S
har
e P
aper
/Bo
ard
To
nn
age
VirginWoodpulp
Recycled Fibre (AfterProcessing Wastepaper)
1995 2000 2005 2006 2011 2016 2021 2026 2006-16 2011-21 2016-26
N. America 7.4 8.4 8.6 8.9 9.0 9.3 9.5 9.6 0.4% 0.6% 0.4%W. Europe 15.3 17.3 19.2 19.1 19.2 20.0 20.2 20.7 0.5% 0.5% 0.3%Asia 9.5 12.1 15.9 16.7 21.3 26.3 32.6 37.7 4.6% 4.4% 3.7%All Other 3.8 4.5 5.1 5.7 7.7 10.4 12.9 13.7 6.2% 5.3% 2.8%Global Market Pulp Demand
36.0 42.3 48.8 50.4 57.1 66.0 75.3 81.8 2.7% 2.8% 2.2%
Market Pulp % Of Woodpulp
23% 25% 28% 29% 29% 31% 32% 33%
Million MT/Year CAGR, %/Year
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A related trend is the steady increase in market pulp as a percentage of total
woodpulp share. Figure 1-15 summarizes this trend.
Figure 1-15 Global Market Pulp % Share of Total Virgin Woodpulp to 2026
North America and Western Europe are forecast to have relatively slow market pulp
demand growth and a shrinking share of global demand. Primary reasons include:
a) High wood and labour costs in developed regions making it increasingly difficult to compete in commodity market pulps with low cost producers, notably Latin America. To overcome these deficiencies, developed regions have been integrating pulp forward into paper and moving up the value added chain.
b) Domestic pulp and paper industry and market maturity, resulting in progressively slower papermaking capacity growth.
c) Ongoing integration of market pulp into paper as a result of the above.
Figure 1-16 shows regional market pulp demand forecast to 2026. Asia and Other
are forecast to command a combined ~65% share by 2026, up from ~35% in 2005.
21%
23%
25%
27%
29%
31%
33%
35%
1995 2000 2005 2010 2015 2020 2025
Mar
ekt
Pu
lp %
Of
To
tal V
irg
in W
oo
dp
ulp
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Figure 1-16 Market Pulp Regional Demand Trends to 2026
Declining supply share is a related development. After peaking around 1990 at
slightly more than 50% of global market pulp capacity, North America’s share has
been declining, and it is expected to relinquish the number one spot to Latin
America around 2010. Figure 1-17 summarizes the global share trend of these two
key regions, and includes a forecast to 2026.
Figure 1-17 North American Share of Global Market Pulp Capacity
Table 1-15 summarizes regional market pulp net import-export position to 2026
(negative sign indicates net export, while positive shows net import position).
0
10
20
30
40
50
1970 1980 1990 2000 2010 2020
% S
har
e O
f G
lob
al North America
Latin America
0%
20%
40%
60%
80%
100%
1995 2000 2005 2011 2016 2021 2026
% S
har
e O
f G
lob
al D
eman
d
OtherAsiaW. EuropeN. America
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Table 1-15 Estimated Paper Grade Market Pulp Net Imports/Exports Position (million tonnes)
North America’s dominant net export position will decline significantly to 2026, while
Latin America’s soars. Eastern Europe will be the second fastest growing net export
region. This expectation is based on the reasonable assumption that the vast
(world’s largest free standing forest resource) Russian softwood resource will be
developed commercially over the next 10-20 years. Despite large-scale
establishment of fast growing plantations, the big net import increase will be in Asia
(largely as a result of China’s voracious appetite for market pulp to feed its fast
growing paper capacity expansions in this country of very limited forest resources).
Western Europe is also expected to exhibit increased net market pulp import.
1.2.7 Short-to-Medium Range Key Product Price Trends and Forecasts
BC’s largest tonnage pulp and paper products are market pulp (bleached softwood
kraft and hardwood and softwood BCTMP) and newsprint. As the North American
newsprint market demand (as well as capacity and production) declined strongly
during the last few years, an increasing share of newsprint capacity has been
switched to uncoated (in particular glossy, pigment-filled, soft nip or super-
calendered) and coated mechanical grades, whose importance continues to rise.
This section reviews long term constant dollar price trends, and it provides short-to-
medium (5-year) term outlook and price forecasts for all these key pulp and paper
products. A note of warning about price forecast risk: Commodity product
price forecasting is a highly error-prone process, even in the short-to-medium
term, since prices can fluctuate wildly even over a period of a few months.
Over the long term, on the other hand, commodity product prices tend to decline in
constant dollars, reflecting the relationship between product price position and
1991 1996 2001 2006 2011 2016 2021 2026
North America -8.8 -9.2 -9.6 -8.2 -6.8 -4.8 -2.8 -2.7Western Europe 4.8 5.6 6.3 7.0 7.7 8.7 9.7 10.5Asia 6.2 8.0 9.7 13.7 17.6 22.6 27.6 33.0Latin America -1.3 -2.9 -4.5 -9.1 -13.7 -18.1 -22.5 -26.0Eastern Europe -0.3 -0.8 -1.3 -2.2 -3.1 -5.4 -7.6 -9.3Africa & Oceania -0.6 -0.6 -0.6 -1.2 -1.7 -3.1 -4.4 -5.5Net 0 0 0 0 0 0 0 0
RegionMillion MT/Year (Negative = Net Export)
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declining (in constant dollars) manufacturing and delivered cost. This condition, of
course, applies only as long as average raw material, energy, chemical and labour
costs do not rise faster than cost savings realized through efficiency, technology and
related operational improvements. These improvements, in general, tend to drive
commodity product (constant dollar) manufacturing costs down, and they include
shifting raw material composition of papers without compromising product
performance. A direct result of production cost minimization is that it allows the
constant dollar prices of commodity grades such as market pulp, newsprint and
large volume (uncoated and coated publication) P&W papers to continue sliding.
We begin each of the following sub-sections with the long term, constant dollar trend
and (conceptual) long term price forecast to 2026. [Note: This is only possible for
newsprint and bleached softwood kraft pulp on a consistent basis, since the
other grades lack a long term price history.] This is followed by the short-to-
medium term (2007 to 2011) forecast on an annual basis.
Newsprint
Figure 1-18 shows the North American newsprint price trend in constant 2005
US$/tonne. A real price decline of about 18-20% from the 1970s level is evident.
Based on historical price trends, plus expectations of newsprint input unit
costs evolution, the long term trendline price for newsprint to 2026 is
estimated to be in the range of US$(575-600)/MT in constant 2005 US $/MT for
48.8 grams/square metre product.
Figure 1-18 Newsprint (48.8 gsm) Long Term Trend Price (1970-2007) in Constant 2005 US$/MT – Actual and Trend Line
$550
$600
$650
$700
$750
$800
$850
1970 1975 1980 1985 1990 1995 2000 2005
Co
nst
ant
2005
US
$/M
T
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Key trends to note include:
• The price trend exhibits a decline of the order of US$(3-4)/MT per year.
• The last 20-25 years have been characterized by wild price fluctuations, in
response to supply-demand surges and a turbulent market, resulting in historical
high (1988) as well as historical low (1993 or 2002) prices. In fact the low 2002
newsprint constant dollar price was seen only once before during the Great
Depression in the 1930s.
• Expectations that the significant increase in industry consolidation of the last few
years (top five North American producers’ capacity total up from 40-42% in the
early-to-mid-1990s to 70-75% in the early 2000s) would result in a more stable
pricing environment have materialized only partially. The main culprit has been
much faster reduction in newsprint demand than expected, effectively destroying
suppliers’ efforts to stabilize the market through capacity removals (machine
shutdowns). Further consolidation is anticipated as the two largest suppliers,
Abitibi-Consolidated and Bowater, have announced plans to merge (note,
however, that these plans are currently encountering some resistance).
Figure 1-19 provides recent historical plus the 5-year price forecast for North
American newsprint on an annual basis. The forecast is based on assumed
average annual operating ratios (production:capacity), which are impossible
to predict with certainty, so we again warn the reader about the high forecast
risk noted earlier.
Figure 1-19 Medium Term North American Newsprint Price Forecast
$500
$550
$600
$650
$700
$750
1997 1999 2001 2003 2005 2007 2009 2011
2005
US
$/M
T
Historical Forecast
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The expectation is that after a relatively low price in 2007, as a result of
unexpectedly large newsprint demand decline in North America, capacity removals
will bolster the market by raising operating ratios by 2009-11.
Northern Bleached Softwood Kraft (NBSK) Price Trend
NBSK is the major price setting grade for other paper grade market pulps, including
bleached CTMP grades. Much like newsprint (and similar industrial commodities),
its price has exhibited a declining trend in constant dollars. [Note: In recent years
the global market has evolved into three distinct geographical regions with regard to
price. These are the three major consuming regions, Western Europe, Asia and
North America, each of which now has its own price position relative to the other
two. Generally, over the last 4-5 years, North American prices have been slightly
higher than Western Europe’s, and Asia’s prices have been lowest. In order to keep
a consistent comparison basis, as well as because of long term historical data
availability, and because the Western European market is very close to the global
weighted average price, we use data applicable to the largest regional market,
Western Europe in long term trend analysis). Figure 1-20 summarizes the long-term
constant dollar trend from 1970 to 2007, showing a decline of the order of
US$11/MT per year.
Figure 1-20 Long Term NBSK Price Trend in Constant 2005 US$/MT
$500
$600
$700
$800
$900
$1,000
$1,100
$1,200
$1,300
1970 1975 1980 1985 1990 1995 2000 2005
2005
US
$/M
T
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Key factors contributing to the declining constant dollar NBSK price trend include:
• Continuing high fragmentation (low supplier concentration) of the global market
pulp industry resulting in vicious, price-based competition for market share.
• Economies of scale of modern bleached kraft mills, leading to lower fixed costs.
Today’s modern single line kraft mills are being designed at up to 3,000
tonnes/day capacity, as opposed to 30-40 year old lines (such as many kraft
mills in BC) at 500-1,000 tonnes/day.
• Improved pulping and bleaching technology (e.g. full energy self-sufficiency, as
opposed to only partial in previous decades) for lower operating costs.
• Increasingly strong competition from low wood and labour cost regions,
specifically Brazil and more recently Indonesia for hardwood kraft pulps (not a
major competitive issue for BC), and Chile for softwood kraft.
• Papermaking technology which facilitates increasing displacement of higher cost
softwood kraft pulps by lower cost recycled fibres and hardwood pulps.
Figure 1-21 summarizes recent NBSK price trend and forecast to 2011 in constant
2005 US$/MT. Again, please note that price forecasting for these products is a
highly uncertain and inaccurate process since prices can fluctuate
significantly over a short period of time, as seen in the previous chart (e.g.
1994-96 and 1999-2001 for most recent large amplitude price swings).
Figure 1-21 Medium Term NBSK Price Forecast
$500
$550
$600
$650
$700
$750
$800
$850
1997 1999 2001 2003 2005 2007 2009 2011
2005
US
$/M
T
Historical Forecast
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Bleached CTMP Medium Term Price Trends and Forecast
Bleached market CTMP prices tend to loosely follow fluctuations in the price setting
NBSK product price analyzed above. However, in the early years following their
introduction as new market pulps in the 1980s, BCTMP grades had a difficult time in
the market. Although they were initially touted as “new and revolutionary pulps of the
future”, they have remained low competitiveness products struggling to penetrate
markets in the face of stiff competition from higher quality and low production cost
bleached hardwood kraft pulps from mills in South America and, more recently,
Indonesia. A direct result during the first ten years (1983-1993) of CTMP price history
was a declining trend in the BCTMP:NBSKP price ratio for both softwood and
hardwood BCTMP. What this means is that the rate of market CTMP price decline
was even faster than that of NBSK constant dollar price decline seen earlier.
Figure 1-22 shows the trend for hardwood CTMP. [Note: Bleached softwood
CTMP prices are not tracked as consistently as hardwood grades, but it
should be noted that they have averaged approximately 5% lower than
hardwood CTMP over the last 20-25 years.] It is seen that the declining BCTMP:NBSK price ratio trend bottomed out in the mid-1990s. Since then it has risen, recapturing roughly half of the ground lost between the mid-1980s and 1990s. China’s insatiable demand for cost-effective raw materials for packaging board was a significant positive driver, since BCTMP has proven to be an excellent raw material for this rapidly growing (in China) end use.
Figure 1-22 Bleached Hardwood Market CTMP Market Price as a Percent of Northern Bleached Softwood (NBSK) Price
65
70
75
80
85
90
1983
1985
1987
1989
1991
1993
1995
1997
1999
2001
2003
2005
2007
Pric
e R
atio
, %
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There are various grades of bleached CTMP market pulp, largely differentiated by brightness. The price data are given for the higher quality (brightness) products, namely 85-87% brightness for hardwoods and 80-82% brightness for softwoods.Figure 1-23 summarizes the medium trend market price forecast for these products, showing peaking in 2007 followed by a moderate decline in 2008-09, before a stronger decline in 2011.
Figure 1-23 Medium Term Bleached CTMP Price Trend and Forecast in Constant 2005 US$/MT
Coated Mechanical Medium Term Price Trends and Forecast
The primary grade of interest is lightweight coated, in BC produced on paper machine #5 at the Catalyst Paper, Port Alberni mill. Figure 1-24 provides recent historical trend and forecast to 2011 in constant dollars/tonne.
$350
$400
$450
$500
$550
$600
$650
$700
1997 1999 2001 2003 2005 2007 2009 2011
2005
US
$/M
T Historical Forecast
HardwoodCTMP
SoftwoodCTMP
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Figure 1-24 Medium Term 60 Grams/Square Metre LWC Price Forecast in Constant 2005 US$/MT
Uncoated Mechanical Supercalendered-A (SCA) Medium Term Price Trends
and Forecast
There are literally dozens, if not hundreds of uncoated mechanical paper grades
produced and consumed in North America. The market is highly fragmented and
non-uniform, therefore price analysis can only be carried out on a limited number of
large volume grades. The most important for the purposes of this analysis, and the
one for which relatively long term (going back to 1990) price data are available, is
supercalendered-A, or SCA for short. SCA is the highest quality, glossy, high
brightness uncoated mechanical paper. Two common examples are the New York
Times Sunday magazine, as well as intermediate-to-high end (but below coated
paper) quality retail advertising (e.g. some department and electronic stores).
There is currently no SCA machine in BC, but two machines (Catalyst, Elk Falls
machine #2 and Powell River machine #10) use slightly different technology and
produce the next highest quality (just below SCA) uncoated mechanical grades,
namely soft nip calendered SCB. The price fluctuations of the latter mimic those of
SCA (there are inadequate historical SCB price data available to carry out a
meaningful analysis). [It should be noted that at least one of the two BC SCB
machines is a candidate for upgrading to SCA by modernizing their current soft nip
calenders which date from the early 1990s.] Figure 1-25 summarizes recent price
trends and medium term forecast for SCA.
$700
$800
$900
$1,000
$1,100
$1,200
$1,300
$1,400
1997 1999 2001 2003 2005 2007 2009 2011
2005
US
$/M
T L
WC
60
gsm
Wei
gh
t
Historical Forecast
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Figure 1-25 Medium Term 52 Grams/Square Metre SCA Price Forecast in Constant US$/MT
1.2.8 Implications of Price Trends and Forecasts
The price forecasts suggest that, even though some grades, such as NBSK, are
currently in tight market conditions with relatively high prices, other products (e.g.
LWC) whose market is already relatively soft (i.e. relatively low prices) have little
prospect of significant improvement, as their demand is stagnant or declining.
Newsprint is currently in transition from relatively tight market conditions in the
second half of 2006 to softer conditions (and therefore lower prices) as demand
declined faster than suppliers anticipated (and reduced capacity through paper
machine closures or upgrades to higher value products). These are not good
prospects for the Canadian (and BC) pulp and paper industry, and they are made
particularly acute by the rising Canadian dollar. [Note: Prospects for raising prices
of certain grades to compensate for the adverse bottom line impact of the rising
dollar are not as good in some grades (e.g. woodfree and coated ones) where the
US paper industry has a dominant capacity share position in excess of 75% of North
American capacity, as they are in others where the Canadian industry dominates
(e.g. newsprint and uncoated mechanicals). Therefore, the incentive to raise prices
beyond standard cost escalation in US dollar terms is much lower for US producers
than it is for Canadian producers.]
$700
$800
$900
$1,000
$1,100
$1,200
$1,300
1997 1999 2001 2003 2005 2007 2009 2011
2005
US
$/M
T S
CA
52
gsm
Wei
gh
t
Historical Forecast
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1.2.9 The Meteoric Rise of the Chinese Economy and Paper/Board Industry
Specific, detailed data related to China’s rise to economic superpower status are
also found in Sections 1.1 (Economic Outlook) and 2.4 (BC Industry Outlook). The
latter section includes a discussion of implications for the BC pulp and paper
industry, since the Province is well positioned to supply many resource products
(pulp, some paper products, minerals, and other) to the rapidly industrializing
Southeast Asian region. However, a broad summary is warranted, and follows,
here.
China has 20% of the global population, and ranks second in land area (together
with Canada and the USA which have similar land areas) after Russia. Its GDP was
relatively small for decades, but it has been growing at phenomenal rates of around
10-12% per year since the early-to-mid-1990s, and it appears it will continue to do
so in the next 5-10 years at least. The rapidly growing personal wealth (GDP per
capita), as well as its primary driver, namely explosive industrialization in virtually all
industries (chemicals, textiles, machinery, electronic goods, and so) are driving
equally phenomenal growth in China’s paper industry. Figure 1-26 provides clear
evidence of this from 2000 with forecast to 2020. [Note: Statistical data prior to
2000 are scarce and generally unreliable, but 1990 is included to provide an initial
baseline perspective to show the enormous increase in Chinese paper/board
demand.]
Figure 1-26 Chinese Total Paper/Board Demand Growth Trend and Forecast
0
20
40
60
80
100
120
140
1990 1995 2000 2005 2010 2015 2020
Dem
and
& P
rod
uct
ion
, M
illio
n M
T
Demand Production
No Reliable1995 Data
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Even though China is adding paper/paperboard capacity at a near frenetic rate, it is
expected to remain a net importer of paper/paperboard, as its capacity growth will
lag demand increase. However, in certain product sectors, particularly higher value
P&W grades, notably coated woodfree, China has become a net exporter, as its
capacity outpaced domestic demand. It is not unreasonable to expect that this may
be sustained in the future, as another manufacturing and export activity of this
growing industrial giant (more of this in Section 2.4 of this report).
The 30-year (1990-2020) annual average growth rate for total paper demand is an
amazing 7.7%, and it will increase the rather small 1990 baseline approximately ten-
fold by 2020. The 15-year compound average growth rate (CAGR) between 2005
and 2020 for the four major grade classes is summarized in Table 1-16.
Table 1-16 Average Annual Chinese Paper/Board Demand Growth Rate by Major Grade Sector 2005-2020
2005-2020 CAGR, %/Year Newsprint 4.8% P&W 4.7% Tissue 6.1% Board/Other 5.8% TOTAL 5.5%
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1.3 International Wood Product Overview
1.3.1 Total Production of Lumber and Panels
The total manufacture of products made from global forest resources has been
increasing over the past 20 years at a little over 2% per year. Wood products, i.e.
lumber and panel products, which account for 65-70% of all products made from
roundwood, excluding firewood, have been increasing at a slightly slower rate than
paper and board products.
Figure 1-27 Global Consumption of Wood Products 1985-2005
Figure 1-27 shows that almost all growth in recent years has been in the use of
panel products such as plywood, particleboard, OSB and MDF. The consumption of
lumber in total has been fairly static over the 20 year period in spite of substantial
increases in both population and the global economy.
Over the last 15 years the volumes of hardwood lumber have been declining so that
the share of softwood has risen from below 70% to just over 75%. Consequently,
the volumes of softwood lumber have risen slightly but the annual increase in
volume only averages 1% per year over the past 15 years.
Regional production of softwood lumber is very focused with almost 70% being
produced in US, Canada and the European Community – see Figure 1-28.
0
100
200
300
400
500
600
700
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
Mill
ion
m3
LUMBER
PANEL PRODUCTS
Excluding Russia
Source: FAO
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Figure 1-28 Regional Shares of Softwood Lumber Production
The principal producers in Asia are Japan, China and India, accounting for 85% of
the Asian volume. The main producers under the “Other” category are Australia and
New Zealand.
1.3.2 Trade in Softwood Lumber
On a global basis, exports (and therefore imports) of softwood lumber amount to
about 30% of consumption. However, much of this volume is within regions, e.g.
from one European country to another or from Canada to the US. Consequently,
inter-regional exports are a very much lower share of the total.
The largest importing countries are shown in the following table.
US/Canada39%
European Community
30%
Russia6%
Latin America7%
Asia12%
Other6%
Based on average of recent years
Total 315 million m3
Source: FAO
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Table 1-17 Principal Importing Countries for Softwood Lumber 2005
Country Import Volume (million m3)
US 41.9 Japan 7.9 UK 7.6 Italy 6.2 Germany 3.6 France 3.4 Netherlands 2.5 Spain 2.4 China 2.3
Source: FAO
These countries account for about 80% of all imports and it is apparent that the US
is by far the largest importer. Japan is the second largest importer of softwood and
China, in spite of its enormous economic growth still imports very little.
The situation for exporters of softwood lumber is shown in Table 1-18.
Table 1-18 Principal Exporters of Softwood Lumber 2005
Country Export Volume (million m3)
Canada 39.8 Russia 14.6 Sweden 11.9 Finland 7.6 Germany 5.7
Source: FAO
Again, these countries account for about 80% of global exports. The substantial
trade between Canada and US is by far the most significant on a worldwide basis.
There is a great variation between countries in terms of their consumption of
softwood lumber. For example, in North America average consumption per 1000
people is around 500 m3, in Japan it is about 300 m3/1000, in Europe the level drops
to around 200 m3/1000 and in China it is barely 10 m3/1000. Consumption is driven
much more by traditional building practices rather than by economic prosperity.
Further details on consumption patterns and competitive supply in the principal
markets of current and potential interest to BC producers are provided in the next
chapter on the principal markets for BC lumber.
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1.3.3 Outlook for Global Softwood Lumber
It was apparent from Figure 1-18 and the subsequent discussion on trade flow that
North America and the European Community currently account about 70% of global
activity in softwood lumber. Over the medium term and long term it is expected that
there will be some changes in consumption, production and the consequent trade
flows for each region. The overall consumption is expected to rise over the period at
an average rate of about 1.5%, which is similar to rate of growth in the past.
North America and Europe will continue to take the largest share of the softwood
lumber consumed but will grow at a slightly lower rate. The principal growth is
expected to occur in the CIS countries, Latin America and a variety of Asian
countries. Though China is, and will continue to be, a major economic force in Asia
the volumes of softwood lumber consumed in that country are not expected to
increase substantially in terms of absolute volume since it currently consumes only
about 10 million m3 of softwood lumber. The other Asian countries, such as South
Korea, consume considerably more and have been showing significant growth in
softwood lumber consumption over recent years – expanding from 13 million m3 in
2000 to 25 million m3 by 2005.
Figure 1-29 Projected Consumption of Softwood Lumber
0
50
100
150
200
250
300
350
400
450
500
2000
2002
2004
2006
2008
2010
2012
2014
2016
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2022
2024
2026
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ion
m3
OtherCISLatin AmericaJapanEuropeUS/Canada
Source: Amec
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The major trends relative to supply expected are:
• Little possibility of much growth in North American production. Therefore the
increasing consumption levels will have to be satisfied by imports from other
regions.
• There could be some growth in production in Western Europe since there has
long been an excess of timber growth over removals. However, the expected
reduction in the supply of Russian logs to western European mills will constrain
this growth.
• Eastern Europe will continue to be a significant net exporter but consumption
growth is likely to be somewhat greater than the increase in production.
• There are expected to be substantial increases in net exports from Russia and
other CIS countries. Though consumption is expected to increase at over 5%
per year in the long term, the volume of exports is expected to increase by more
than 15 million m3 during that period. There are vast currently untapped
resources in the region and the new export duties on logs are likely to result in
much more domestic production.
• Plantation resources are increasing and it is projected that there will be an
increasing volume of export supply from Latin America, in particular.
Overall, though there is projected to be a considerable increase in consumption – in
absolute terms it is likely that there will be plenty of increased supply available to
meet the demand.
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Pulp
A significant portion of the residual wood chip volumes entering Interior pulp mills is
from beetle-killed logs processed at sawmills. To-date, there has been no significant
effects in pulp manufacturing as a result of the lower moisture content and the
consequent fracturing of chips. The reason being, pulp mills can adjust the process
for alkalinity, pressure and temperature in their digesters. However whole-log chips
made from dead and dry trees is an undesirable fibre source for both Kraft and
BCTM pulp mills.
The chips from the blue-stained sapwood of beetle-killed trees require additional
bleaching in BCTM pulp manufacturing. Chips must be processed quickly to prevent
the spread of the staining fungi to non-infected chips in the chip pile.
2.1.3 Log Supply
Utilization and Economic Considerations
The AAC and unregulated sources form the basis of the physical timber supply, but
to estimate the log supply available to manufacturing plants, AMEC has had to
consider timber utilization practices and economic factors that vary considerably by
region.
The volumes that are charged to the licensees’ AAC are determined by utilization
standards that specify the minimum size and quality of logs. Historically on the
Coast of BC, approximately 5% to 15% of the AAC of a management unit has been
left in the woods as waste since harvesting costs have exceeded the logs’ values.
The amount of waste varies with the changing market demand and utilization
standards as well as the quality of timber.
Conversely, in the Interior of BC, log recovery from most stands exceeds the
utilization standards as small logs and tops of trees can be processed in many mills.
In the past, the volumes of logs delivered to mills often exceeded the AACs by 8%
to 12%. In 2005, the MoF changed the Interior log scaling rules, which expanded the
utilization standards to include some logs previously exempted from the AAC. Today
licensees are given an endemic credit in the cut-control rules, which effectively
increase their AAC by about 6% to 7%.
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The available timber supply sets the upper limit for the log supply obtainable by the
manufacturing plants in AMEC’s model. The economics of timber harvesting are
driven by log demand and the model incorporates an iterative process whereby the
feedback from the market demand for lumber and pulp & paper increases or
decreases the economic supply of logs.
Imports, Exports and Regional Transfers
Log imports into BC are usually negligible although in the mid-1990s a short-term
timber supply shortage caused mills to purchase logs from the Prairie Provinces as
well as the US Pacific Northwest and Alaska. Log exports, virtually all of which are
from the Coast of BC, have grown considerably since the mid-1990s (Figure 2-6).
This is due to weak demand for logs from domestic Coastal sawmills and the
increase in harvests from private timberlands. Exports from Crown land are
controlled by both Federal and Provincial regulations; the latter normally make it
almost impossible to profitably export logs on a consistent basis. Most private
timberlands are covered by Federal rules but are exempt from the Provincial
regulations. The Federal rules usually allow exporting provided the logs are surplus
to the needs of domestic mills.
Figure 2-6
Log Exports from BC by Destination
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
5,000
1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006
Cu
bic
Met
res
000
China & Other
South Korea
Japan
USA
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The transfer of logs between the BCH Regions is significant. On the BC Coast
nearly all logs move by water (log booms and barges), which is a very low-cost
method of transportation. This combined with the building of mills on the lower
Fraser River and south-east coast of Vancouver Island, has led to a network that
transports nearly all logs harvested from the coastal sections of the North Coast
Region (Queen Charlotte Islands, Prince Rupert, Kitimat and Mid-coast areas) to the
Vancouver Island and South Coast Regions.
In the Interior, nearly all logs are transported by truck, which usually limits
transportation distances to under 200 km. However, the boundaries of the BCH
Regions particularly in the Prince George, Vanderhoof and Burns Lake areas as well
as near Kamloops, means that there are significant volumes transported between
the North Coast, Northern Interior and Central Interior Regions as well as between
the Central Interior and Southern Interior Regions. Furthermore, the rapid spread of
the mountain pine beetle and subsequent beetle control and salvage harvesting
operations, has resulted in logs moving longer than normal distances.
2.1.3.1 Base Case Log Supply
The Base Case is the Consultants’ estimates of the most likely market supply
scenario for coniferous logs that are economically harvestable. The deciduous
supply is discussed in Section 1.3.7.
Base Case – Provincial Log Supply
The log harvest in BC was 81.4 million m3 in 2006. The supply of economically
available logs is expected to be about 78.1 million m3 in 2007 as shown in Figure 2-
7. The drop in supply from the previous year is a result of weaker lumber markets
and lower log prices. The average supply is expected to be about 81.2 million m3
per year for the next five years. It is expected to increase to a peak of nearly 84
million m3 in 2009 as the economics of harvesting improve (higher log prices) with
stronger lumber markets.
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Figure 2-7
About two-thirds of the Province’s log supply comes from the three Interior Regions.
The supply in the Interior is expected to decline beginning in 2012 with the falldown
in the AACs because many of the lodgepole pine stands will have been destroyed or
damaged by the pine beetle epidemic so that they are no longer economically
operable. The supply on the BC Coast is much more stable than the Interior. Over
the 20-year projection period the Province-wide supply of logs is expected to drop by
22 million m3 or 27% from the current level (five-year average) to about 59 million m3
per year.
Base Case – Interior Log Supply
Figure 2-8 shows the Base Case projections of the economically available
coniferous log supply in the three Interior Regions. The supply for the next five years
is expected to average about 53 million m3 per year, which is slightly lower than the
actual harvest of 54 million m3 in 2006. However, by 2017 it is expected to decline
by 17 million m3 to reach a level of 37 million m3. Further reductions, albeit much
smaller, will then bring the available supply down to just under 36 million m3 at the
end of the 20-year projection. The total falldown is expected to be approximately 18
million m3 or 33% of the current supply, but is only 10% less when compared to the
pre-beetle AAC.
BC - Base Case Coniferous Log Supply
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
2007 2009 2011 2013 2015 2017 2019 2021 2023 2025
000
m3/
year
Coast
Interior
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The fall-down represents a return to long-term sustainable harvest levels following
the temporarily elevated AACs on many management units as a result of the beetle
epidemic. The reductions in cut are expected to affect the Northern and Central
Interior Regions the most, in particular the Prince George TSA (AAC down 9.7
million m3 in 2012) and the Quesnel TSA (AAC down 4.8 million m3 in 2011); both of
these TSAs have recently had the largest up-lifts in AACs in the Province. The
Southern Interior is affected to a lesser extent by the epidemic (e.g. AAC in the
Kamloops TSA down by 1.9 million m3 in 2013).
Figure 2-8
Base Case – Coast Log Supply
Figure 2-9 shows the projections of the log supply in the three Coastal Regions.
Interior Regions - Base Case Coniferous Log Supply
0
10,000
20,000
30,000
40,000
50,000
60,000
2007 2009 2011 2013 2015 2017 2019 2021 2023 2025
000
m3/
year
Northern Interior
Central Interior
Southern Interior
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Figure 2-9
The current supply is about 28 million m3 per year, which is expected to remain
stable for the next five years. The supply will then drop in the North Coast Region by
3 million m3 in 2012 through 2013 as a result of the beetle epidemic in the forest
management units east of the Coast Mountains, in particular the Lakes TSA and
Morice TSA.
The timber supplies for the South Coast and Vancouver Island Regions are fairly
stable – declining by about 0.5% per year. This decline is a result of the gradual
transition of harvesting in high-volume old-growth stands to lower volume second-
growth stands. (The Coast experienced significant reductions in timber supplies in
the mid-1990s because the Government of the time enacted major environmental
regulations and created large areas of parks, which restricted harvesting operations
and reduced the timber harvesting land base.)
2.1.3.2 Low Supply Scenario
The Low Scenario is AMEC’s projections of the economically available log supply
based on a negative outlook. This includes greater timber losses as a result of a
more aggressive beetle epidemic. In addition the supplies are lowered because of
weaker lumber markets and reductions in the timber harvesting land base, which
may occur from additional preservation or from more stringent harvesting
regulations.
Coast Regions - Base Case Coniferous Log Supply
0
5,000
10,000
15,000
20,000
25,000
30,000
2007 2009 2011 2013 2015 2017 2019 2021 2023 2025
000
m3/
year
North Coast
South Coast
Vancouver Island
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Low Scenario – Provincial Log Supply
Figure 2-10 shows the Province-wide supply of economically available logs under the
Low Scenario. The average annual log supply over the first five years of the
projections is expected to be about 75 million m3, which is about 6 million m3 per
year (8%) less than the Base Case. Log supply in the near future is not limited by
the physical supply of timber as determined by biophysical factors but will be
constrained by harvesting economics.
Figure 2-10
The log supply rapidly declines after 2011 and by 2026 AMEC expects that the
available amount of logs under the Low Scenario will be about 56 million m3 per
year, which is a decline of 19 million m3 or 25% from the first five years of the
projections.
Low Scenario – Interior Log Supply
Figure 2-11 shows the Low Scenario projections for available log supply in the
Interior. The supply for the next five years is expected to average about 49 million
m3 per year, which is about 4 million m3 per year less than the Base Case. Between
2007-2011 and 2026 the supply is expected to decline by 16 million m3 or 33% to
reach a level of 33 million m3.
BC - Low Scenario Coniferous Log Supply
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
2007 2009 2011 2013 2015 2017 2019 2021 2023 2025
000
m3/
year
Coast
Interior
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Figure 2-11
Low Scenario – Coast Log Supply
Figure 2-12 shows the Low Scenario projections of the log supply in the three
Coastal Regions.
Figure 2-12
Interior Regions - Low Scenario Coniferous Log Supply
0
10,000
20,000
30,000
40,000
50,000
60,000
2007 2009 2011 2013 2015 2017 2019 2021 2023 2025
000
m3/
year
Northern Interior
Central Interior
Southern Interior
Coast Regions - Low Scenario Coniferous Log Supply
0
5,000
10,000
15,000
20,000
25,000
30,000
2007 2009 2011 2013 2015 2017 2019 2021 2023 2025
000
m3/
year
North Coast
South Coast
Vancouver Island
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The supply for the next five years on the Coast under the Low Scenario is expected
to average around 26 million m3 per year, which is about 2 million m3 per year less
than the Base Case. Between 2007-2011 and 2026 the supply is expected to
decline by 4 million m3 or 14% to reach a level of 23 million m3. The largest drop is
expected in the North Coast Region (down 27%) as a result of the beetle epidemic in
the eastern parts of this Region.
2.1.3.3 High Supply Scenario
The High Scenario is AMEC’s projections of the economically available log supply
using an optimistic outlook. This includes lower timber losses as a result of a less
aggressive beetle epidemic, longer shelf-life for infected trees and shorter rotation
ages for regenerating forests. In addition the supplies are increased because of
stronger lumber markets and fewer reductions in the timber harvesting land base,
which may occur from less forest preservation and/or from relaxed harvesting
regulations.
High Scenario – Provincial Log Supply
Figure 2-13 shows the Province-wide supply of logs under the High Scenario. The
average annual log supply over the first five years of the projections is expected to
be near 88 million m3, which is about 7 million m3 per year (8%) more than the Base
Case.
Figure 2-13
BC - High Scenario Coniferous Log Supply
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
100,000
2007 2009 2011 2013 2015 2017 2019 2021 2023 2025
000
m3/
year
Coast
Interior
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After the first five years, the log supply declines by 23 million m3 (26%) to reach an
even flow of about 65 million m3 per year, which is 6 million m3 higher than the Base
Case.
High Scenario – Interior Log Supply
Figure 2-14 shows the High Scenario for log supply in the Interior Regions. The
supply for the next five years is projected to average around 58 million m3 per year
and is expected to be near 60 million m3 annually in 2009 through 2011 at the peak
of the next upswing in lumber markets. Despite an optimistic outlook, log supply is
still expected to drop substantially in the Interior and by 2026 log production will be
37 million m3 per year; the total falldown is anticipated to be about 21 million m3 or
36% less than the supply in the years 2007 to 2011.
Figure 2-14
Interior Regions - High Scenario Coniferous Log Supply
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
2007 2009 2011 2013 2015 2017 2019 2021 2023 2025
000
m3/
year
Northern Interior
Central Interior
Southern Interior
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High Scenario – Coast Log Supply
Figure 2-15 present the optimistic outlook for log supply on the Coast.
Figure 2-15
Under optimistic conditions, the Coastal log supply is expected to average around 30
million m3 per year over the next ten years. This is a result of delayed reductions in
the AACs in forest management units with beetle infested stands in the eastern
sections of the North Coast and from opportunities to shorten rotation ages and
increase the cuts in units on Vancouver Island and the South Coast. The North
Coast supply takes a step down in 2018 because of a significant falldown in the
Morice TSA’s AAC (2.1 million m3/ year). The long-term log supply is forecast at rate
of just over 27 million m3 per year for the Coast.
2.1.3.4 No-Beetle Scenario
AMEC has provided a No-Beetle forecast of available log supply. This was done by
revising the supply projections of those management units affected by the beetles
using timber supply projections and other information prepared around 1997 prior to
the current epidemic.
Coast Regions - High Scenario Coniferous Log Supply
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
2007 2009 2011 2013 2015 2017 2019 2021 2023 2025
000
m3/
year
North Coast
South Coast
Vancouver Island
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No-Beetle Scenario – Provincial Log Supply
Figure 2-16 shows the Province-wide supply of logs under the No-Beetle Scenario.
The hypothetical average annual log supply over the first five years of the projections
would then be a little less than 71 million m3, which is 10 million m3 per year (13%)
lower than the realistic situation (Base Case).
Figure 2-16
In the absence of the MPB, the annual log supply is very stable; declining by only 2
million m3 or just 3% over the 20-year forecast period. In 2026 the No-Beetle
Scenario shows a Provincial-wide yearly log supply of nearly 69 million m3, which is
10 million m3 higher than the Base Case.
No-Beetle Scenario – Interior Log Supply
The hypothetical No-Beetle projections for the Interior Regions are shown in Figure
2-17. The supply from all three of the Regions is steady through out the forecast at
about 44 million m3 per year.
No-beetle Coniferous Log Supply
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
2007 2009 2011 2013 2015 2017 2019 2021 2023 2025
000
m3/
year
Coast
Interior
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Figure 2-17
No-Beetle Scenario – Coast Log Supply
Figure 2-18 shows the No-Beetle outlook for the Coastal Regions.
Figure 2-18
Interior Regions - No-beetle Coniferous Log Supply
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
45,000
50,000
2007 2009 2011 2013 2015 2017 2019 2021 2023 2025
000
m3/
year
Northern Interior
Central Interior
Southern Interior
Coast Regions - No-beetle Coniferous Log Supply
0
5,000
10,000
15,000
20,000
25,000
30,000
2007 2009 2011 2013 2015 2017 2019 2021 2023 2025
000
m3/
year
North Coast
South Coast
Vancouver Island
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The timber supply on the Coast declines slowly as forest management units,
primarily on Vancouver Island and the South Coast make the transition from old-
growth stands to lower stocked second-growth stands.
2.1.3.5 Deciduous Log Supply
The deciduous log supply in BC is expected to be steady at just over 4 million m3 per
year, most of which is found in the Interior (Figure 2-19).
Figure 2-19
The Interior deciduous log supply comes principally from aspen stands located in the
Northern Interior (Figure 2-20).
Deciduous Log Supply
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
2007 2009 2011 2013 2015 2017 2019 2021 2023 2025
000
m3/
year
Coast
Interior
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Figure 2-20
The deciduous components of the AACs of most management units are currently
above their long-term sustainable levels. However, the fall-down in cuts to
sustainable rates is not expected to occur within the next twenty years.
The coastal deciduous log supply comes mainly from alder stands on Vancouver
Island and alder stands and cottonwood plantations in the Fraser Valley. The supply
is expected to remain steady through the forecast (Figure 2-21).
Figure 2-21
Interior Regions - Deciduous Log Supply
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
2007 2009 2011 2013 2015 2017 2019 2021 2023 2025
000
m3/
year
Northern Interior
Central Interior
Southern Interior
Coast Regions - Deciduous Log Supply
0
100
200
300
400
500
600
2007 2009 2011 2013 2015 2017 2019 2021 2023 2025
000
m3/
year
North Coast
South Coast
Vancouver Island
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2.3 Fibre Demand and Supply Balances
2.3.1 Forecast Methodology
The tables in the next sections of the report summarize the fibre supply and demand
Province wide and by the BCH Regions as grouped into the Interior and Coast. The
supporting schedules showing more detailed information are in Appendix I.
The top part of each table shows the log supply and demand balances. Log supply
was estimated after considering the available timber supply as well as other factors
that have been discussed previously. Log demand or utilization was determined by
the manufacturing and market conditions discussed in other sections of this report.
Log exports and imports were also considered. Woodchip supply and demand are
shown in the lower part of the tables. The residual chip supply was driven by the
output of solid-wood manufacturing plants. Round wood chip production is
principally determined by the demand for fibre by pulp mills. Chip demand was
estimated from the input requirements chiefly from the pulp & paper mills.
Log and chip transfers into and out of the Province as well as between the Regions
are shown as imports or exports.
2.3.2 Provincial Balances
The Province-wide coniferous fibre balances are shown in this section of the report.
Provincial Fibre Balances - Base Case
Table 2-12 presents the fibre balances across BC in the Base Case Scenario.
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Table 2-12 BC Base Case Fibre Balances Fibre Supply / Demand 2007 2008 2009 2010 2011 2016 2021 2026
Log Supply (000 m3) 78,120 80,071 84,059 81,936 81,815 66,018 60,624 58,979Log Utilization 71,062 72,050 77,033 74,460 74,754 61,204 55,600 53,845Domestic Log Balance 7,058 8,021 7,025 7,476 7,061 4,814 5,024 5,134Log Imports (Exports) -4,183 -4,812 -4,917 -5,042 -5,627 -4,207 -4,380 -4,438 Log Balance 2,875 3,209 2,108 2,434 1,434 606 644 696
Woodchip Output (000 m3) 30,247 30,633 32,617 30,605 30,263 24,383 22,214 21,482Pulp & Paper Mill Chip Input 27,929 27,660 27,638 26,797 24,403 21,105 21,170 21,201Domestic Balance 2,318 2,974 4,979 3,808 5,860 3,279 1,044 281Chips Imports (Exports) -1,159 -1,487 -2,490 -1,904 -2,930 -1,639 0 400Chip Balance 1,159 1,487 2,490 1,904 2,930 1,639 1,044 681
Total Fibre Balance 4,035 4,696 4,598 4,337 4,365 2,246 1,688 1,377
The table shows there are significant surpluses of logs and chips for the first five
years of the projections. After that, the log supply tightens considerably and
utilization by solid wood manufactures has to decrease significantly for the balance
of the forecast. Chip supplies are more than adequate to meet domestic demand
from the pulp & paper mills until the end of the forecast period when it may be
necessary to import small volumes of chips.
Provincial Fibre Balances - Low and High Scenarios
The Low Scenario balances are shown in Table 2-13. The first five years of the
projections have surpluses of logs and chips but not as large as predicted under the
Base Case. Over the longer term the log supply does not fall to the same extent as
utilization so the surpluses are slightly higher than in the Base Case. However this
does not apply to chips and more imports are required to supply pulp & paper mills.
Table 2-13 BC Low Scenario Fibre Balances Fibre Supply / Demand 2007 2008 2009 2010 2011 2016 2021 2026
Log Supply (000 m3) 75,761 76,824 74,791 73,726 72,809 62,515 57,347 55,727Log Utilization 70,723 71,887 69,281 66,855 66,869 55,861 50,343 48,194Domestic Log Balance 5,038 4,937 5,510 6,871 5,940 6,655 7,005 7,533Log Imports (Exports) -3,661 -3,909 -3,950 -4,347 -4,614 -5,416 -5,935 -6,466 Log Balance 1,378 1,029 1,560 2,525 1,326 1,239 1,070 1,067
Woodchip Output (000 m3) 30,106 30,556 29,519 27,657 27,209 22,134 20,013 19,138Pulp & Paper Mill Chip Input 27,929 27,660 27,638 26,797 24,403 19,774 19,839 19,870Domestic Balance 2,177 2,896 1,881 860 2,806 2,360 173 -732 Chips Imports (Exports) -1,088 -1,448 -940 -430 -1,403 -1,180 100 1,000Chip Balance 1,088 1,448 940 430 1,403 1,180 273 268
Total Fibre Balance 2,466 2,477 2,501 2,954 2,729 2,419 1,344 1,335
BCUC IR 1.19.7 Attachment 4
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Table 2-14 presents the fibre balances for BC in the High Scenario.
Table 2-14 BC High Scenario Fibre Balances Fibre Supply / Demand 2007 2008 2009 2010 2011 2016 2021 2026
Log Supply (000 m3) 82,107 85,027 89,950 90,479 91,144 74,843 65,408 64,755Log Utilization 71,492 73,374 83,456 81,350 83,217 70,141 61,971 62,837Domestic Log Balance 10,615 11,654 6,494 9,128 7,927 4,702 3,437 1,918Log Imports (Exports) -4,543 -5,298 -4,581 -5,059 -5,904 -3,639 -2,501 -1,157 Log Balance 6,072 6,356 1,912 4,070 2,024 1,062 936 761
Woodchip Output (000 m3) 30,425 31,219 35,188 33,298 33,606 28,348 25,143 25,391Pulp & Paper Mill Chip Input 27,968 27,749 27,728 26,886 24,489 22,806 22,872 22,902Domestic Balance 2,457 3,469 7,460 6,412 9,116 5,542 2,271 2,489Chips Imports (Exports) -1,229 -1,735 -3,730 -3,206 -4,558 -2,771 -1,136 -1,244 Chip Balance 1,229 1,735 3,730 3,206 4,558 2,771 1,136 1,244
Total Fibre Balance 7,301 8,091 5,642 7,276 6,582 3,833 2,071 2,006
The analysis shows large log surpluses in the next five years despite significant log
exports. The surpluses drop off in 2016 and through the balance of the forecast.
There are large chip surpluses and chip exports are expected throughout the
forecast.
Provincial Fibre Balances – No-Beetle Forecast
Table 2-15 has the No-Beetle Forecast of available log supply. Log utilization and
chip input for the mills are from the Base Case.
Table 2-15 BC No-Beetle Fibre Balances Fibre Supply / Demand 2007 2008 2009 2010 2011 2016 2021 2026
Log Supply (000 m3) 70,524 70,671 71,134 70,967 70,676 69,716 68,996 68,540Log Utilization 71,062 72,010 76,939 74,394 74,719 61,413 55,924 54,204Domestic Log Balance -538 -1,339 -5,805 -3,426 -4,042 8,302 13,072 14,337Log Imports (Exports) -3,851 -4,180 -4,198 -4,330 -4,913 -4,483 -4,728 -4,818 Log Balance -4,389 -5,519 -10,003 -7,757 -8,955 3,819 8,343 9,519
Woodchip Output (000 m3) 30,247 30,595 32,528 30,542 30,229 24,581 22,520 21,821Pulp & Paper Mill Chip Input 27,929 27,660 27,638 26,797 24,403 21,105 21,170 21,201Domestic Balance 2,318 2,936 4,890 3,745 5,826 3,477 1,350 620Chips Imports (Exports) 0 0 0 0 0 0 0 400Chip Balance 2,318 2,936 4,890 3,745 5,826 3,477 1,350 1,020
Total Fibre Balance -2,071 -2,583 -5,113 -4,011 -3,128 7,296 9,693 10,539
Had the beetle epidemic not occurred, then there are not enough logs to meet the
demand from mills for the first five years of the projections. In the longer term log
supply is more than sufficient to meet mill demand. However the balancing
incorporates log and chip utilization levels as taken from the Base Case, which had
been predicted with the beetle epidemic. (A significant increase in manufacturing
capacity has been put in place in the past few years to deal with more timber.)
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2.3.3 Interior Fibre Balances
Interior Fibre Balances - Base Case
Table 2-16 has the projected fibre balances for the three Interior Regions in the Base
Case. The balances for the individual Regions can be found in Appendix I.
Table 2-16 Interior Base Case Fibre Balances Fibre Supply / Demand 2007 2008 2009 2010 2011 2016 2021 2026
Log Supply (000 m3) 50,438 52,135 55,444 53,397 53,499 41,429 36,867 35,628Log Utilization 49,255 50,695 55,163 52,883 54,027 41,683 37,087 35,838Regional Log Balance 1,184 1,440 281 514 -528 -254 -221 -210 Regional Imports (Exports) 508 510 1,036 1,100 1,082 388 333 367Log Balance 1,691 1,951 1,317 1,614 554 134 112 157
Woodchip Output (000 m3) 19,608 20,181 21,938 20,465 20,908 16,098 14,331 13,805Pulp & Paper Mill Chip Input 15,178 15,030 15,119 14,676 14,411 14,500 14,525 14,553Regional Chip Balance 4,429 5,151 6,819 5,789 6,497 1,597 -194 -748 Chips Imports (Exports) -3,731 -4,156 -5,357 -4,550 -4,575 -865 444 1,029Chip Balance 698 995 1,462 1,239 1,921 732 250 281
Total Fibre Balance 2,389 2,946 2,779 2,852 2,475 866 362 438
The timber supply uplift from the beetle epidemic combined with normal supplies of
timber provides more than enough fibre in the Interior for the first two years of the
projections. The supply-demand balances tighten up beginning in 2009 as
improving lumber markets increase the demand for logs. It is then necessary to
increase log imports into the Interior, primarily from the eastern sections of the North
Coast into the Prince George area and small volumes of logs from the South Coast
into the south Okanogan.
There are large surpluses of chips in the initial years that are shipped mostly to the
South Coast and Vancouver Island. In the long run declining timber supplies are
insufficient to support these exports and the Interior becomes a net importer with
most outside chips coming from the North Coast and smaller volumes from eastern
Washington and Idaho into the southeast corner of BC.
BCUC IR 1.19.7 Attachment 4
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Interior Fibre Balances - Low and High Scenarios
Under the Low Scenario (Table 2-17), the log and chip balances are fairly tight
particularly when the falldown in timber supplies occurs in 2016 and subsequent
years. As with the Base Case, the eastern sections of the North Coast provide
nearly all log and chip imports into the Northern Interior Region; surplus chips are
exported from the Central and Southern Interior Regions to the Coastal mills.
Table 2-17 Interior Low Scenario Fibre Balances Fibre Supply / Demand 2007 2008 2009 2010 2011 2016 2021 2026
Log Supply (000 m3) 49,375 50,194 48,641 48,192 46,820 38,730 34,371 33,144Log Utilization 49,255 50,683 48,677 46,824 47,601 38,710 34,388 33,223Regional Log Balance 121 -488 -36 1,368 -781 21 -16 -79 Log Imports (Exports) 437 876 729 156 1,201 487 303 304Log Balance 558 388 693 1,525 420 507 287 225
Woodchip Output (000 m3) 19,608 20,170 19,376 18,145 18,427 14,903 13,247 12,749Pulp & Paper Mill Chip Input 15,178 15,030 15,119 14,676 14,411 13,972 13,996 14,024Regional Chip Balance 4,429 5,139 4,257 3,469 4,016 931 -749 -1,275 Chips Imports (Exports) -3,731 -4,147 -3,587 -3,207 -2,919 -524 903 1,442Chip Balance 698 992 670 262 1,097 407 154 167
Total Fibre Balance 1,256 1,380 1,364 1,786 1,517 915 441 392
Under the High Scenario (Table 2-18) there are ample log supplies because of the
beetle uplift in cut to meet log and chip demand for the first five years of the
forecasts. In the longer term supplies tighten up with demand but fibre imports from
the North Coast (logs and chips) and US (chips) are sufficient to just meet the
demand.
Table 2-18 Interior High Scenario Fibre Balances Fibre Supply / Demand 2007 2008 2009 2010 2011 2016 2021 2026
Log Supply (000 m3) 53,311 55,055 59,902 60,395 60,240 44,830 37,638 37,467Log Utilization 49,255 50,699 59,467 57,762 60,023 46,678 37,752 37,586Regional Log Balance 4,057 4,356 436 2,633 217 -1,848 -114 -119 Log Imports (Exports) 625 726 376 387 359 2,141 654 635Log Balance 4,682 5,082 812 3,020 576 293 539 516
Woodchip Output (000 m3) 19,608 20,186 23,615 22,339 23,194 17,941 14,513 14,414Pulp & Paper Mill Chip Input 15,178 15,044 15,132 14,689 14,424 13,985 14,009 14,037Regional Chip Balance 4,429 5,142 8,483 7,650 8,770 3,956 504 376Chips Imports (Exports) -3,701 -3,933 -6,116 -5,549 -6,092 -2,210 334 392Chip Balance 728 1,209 2,367 2,100 2,677 1,746 838 768
Total Fibre Balance 5,410 6,290 3,178 5,120 3,253 2,039 1,377 1,284
BCUC IR 1.19.7 Attachment 4
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Interior Fibre Balances – No-Beetle Forecast
The beetle epidemic has enabled mills (as in the Base Case) to increase log
consumption significantly above normal log supply levels. Consequently the No-
beetle Scenario (Table 2-19) has large log deficits in the first five years. The
situation then reverses after 2011 since the timber supply would have been much
higher and more stable without the beetle damage.
Table 2-19 Interior No-Beetle Fibre Balances Fibre Supply / Demand 2007 2008 2009 2010 2011 2016 2021 2026
Log Supply (000 m3) 44,026 44,204 44,200 44,109 44,040 43,908 43,838 43,820Log Utilization 49,255 50,664 55,083 52,831 54,005 41,892 37,411 36,196Regional Log Balance -5,229 -6,460 -10,883 -8,722 -9,965 2,016 6,427 7,625Log Imports (Exports) 271 219 370 433 415 244 159 157Log Balance -4,958 -6,241 -10,513 -8,289 -9,550 2,260 6,586 7,782
Woodchip Output (000 m3) 19,608 20,152 21,862 20,416 20,887 16,296 14,637 14,143Pulp & Paper Mill Chip Input 15,178 15,030 15,119 14,676 14,411 14,500 14,525 14,553Regional Chip Balance 4,429 5,122 6,743 5,739 6,476 1,795 112 -410 Chips Imports (Exports) -3,033 -3,150 -3,852 -3,286 -2,662 -677 820 632Chip Balance 1,396 1,972 2,890 2,454 3,814 1,118 933 222
Total Fibre Balance -3,562 -4,269 -7,623 -5,835 -5,736 3,378 7,519 8,004
2.3.4 Coast Fibre Balances
Coast Fibre Balances - Base Case
Table 2-20 has the projected fibre balances for the three Coast Regions in the Base
Case. The balances for the individual Regions can be found in Appendix I.
Table 2-20 Coast Base Case Fibre Balances Fibre Supply / Demand 2007 2008 2009 2010 2011 2016 2021 2026
Log Supply (000 m3) 27,682 27,936 28,615 28,538 28,317 24,589 23,758 23,352Log Utilization 21,807 21,355 21,870 21,576 20,728 19,521 18,513 18,008Regional Log Balance 5,875 6,581 6,744 6,962 7,589 5,067 5,245 5,344Log Imports (Exports) -4,691 -5,323 -5,953 -6,142 -6,708 -4,595 -4,713 -4,806 Log Balance 1,184 1,258 791 820 881 472 532 538
Woodchip Output (000 m3) 10,639 10,452 10,679 10,140 9,355 8,286 7,883 7,678Pulp & Paper Mill Chip Input 12,751 12,629 12,519 12,121 9,992 6,604 6,646 6,648Regional Chip Balance -2,111 -2,177 -1,840 -1,981 -636 1,681 1,237 1,030Chips Imports (Exports) 2,572 2,669 2,868 2,646 1,645 -774 -444 -629 Chip Balance 461 492 1,028 665 1,009 908 794 401
Total Fibre Balance 1,645 1,750 1,819 1,485 1,889 1,380 1,326 939
BCUC IR 1.19.7 Attachment 4
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The Coast as it is usually defined (that is west of the Coast Mountains which would
include the South Coast and Vancouver Island Regions as well as the western parts
of the North Coast Region) has been in a log surplus situation for the past five years
owing to depressed lumber markets and trade restrictions with the US. During this
period, log exports had increased significantly while domestic mills shut or took
downtime and AMEC’s forecast sees log exports continuing to be a major factor in
balancing supply and demand.
Virtually all Coastal log exports are from the Vancouver Island and South Coast
Regions, with most logs being shipped to the US Pacific Northwest, Japan and Asia.
Small volumes of logs have been trucked to mills in the Southern Interior and AMEC
expects that these inter-regional transfers will increase when the falldown in timber
supplies occurs in the Interior beginning around 2011. However the costs of truck
and rail transportation are expensive particularly if there are no back-haul logs so the
opportunities for major shipments to the Interior are limited.
While the Coast exports logs, it has and will continue for at least the next five years
to be a major importer of chips from the Interior. However pulp & paper mill closures
in the longer term will result in the Coast being a net exporter of chips.
Coast Fibre Balances – Low and High Scenarios
In the Low Scenario (Table 2-21) and High Scenarios (Table 2-22), the changes in
the log supply and the demand from the solid wood mills produces swings in the
volumes of log exports. This occurs because Provincial export regulations protect
log supplies for domestic mills and only surplus logs can be exported. Under both
the Low and High Scenarios, significant chip imports are necessary in the first five
years of the forecast to feed the Coastal pulp & paper mills.
BCUC IR 1.19.7 Attachment 4
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Table 2-21 Coast Low Scenario Fibre Balances Fibre Supply / Demand 2007 2008 2009 2010 2011 2016 2021 2026
Log Supply (000 m3) 26,386 26,630 26,150 25,533 25,989 23,785 22,976 22,583Log Utilization 21,468 21,204 20,604 20,030 19,268 17,151 15,955 14,971Regional Log Balance 4,918 5,426 5,546 5,503 6,721 6,634 7,021 7,612Log Imports (Exports) -4,098 -4,785 -4,679 -4,503 -5,816 -5,902 -6,238 -6,770 Log Balance 820 641 867 1,000 905 732 783 841
Woodchip Output (000 m3) 10,498 10,386 10,142 9,512 8,782 7,231 6,766 6,389Pulp & Paper Mill Chip Input 12,751 12,629 12,519 12,121 9,992 5,802 5,843 5,846Regional Chip Balance -2,252 -2,243 -2,377 -2,609 -1,210 1,429 922 543Chips Imports (Exports) 2,643 2,699 2,647 2,777 1,516 -656 -803 -442 Chip Balance 391 456 270 168 306 773 119 101
Total Fibre Balance 1,210 1,097 1,137 1,168 1,211 1,504 902 942
Under the High Scenario (Table 2-22) domestic log utilization increases relative to
the log supply so the volumes of exports drop in comparison to the Base Case over
the long term. Nevertheless log export volumes will still be significant well into the
future.
Table 2-22 Coast High Scenario Fibre Balances Fibre Supply / Demand 2007 2008 2009 2010 2011 2016 2021 2026
Log Supply (000 m3) 28,795 29,972 30,048 30,084 30,904 30,013 27,770 27,289Log Utilization 22,237 22,674 23,989 23,588 23,194 23,463 24,219 25,251Regional Log Balance 6,558 7,298 6,058 6,496 7,710 6,550 3,551 2,037Log Imports (Exports) -5,168 -6,024 -4,957 -5,446 -6,263 -5,780 -3,155 -1,792 Log Balance 1,390 1,274 1,101 1,050 1,448 769 396 246
Woodchip Output (000 m3) 10,817 11,033 11,573 10,959 10,412 10,407 10,630 10,977Pulp & Paper Mill Chip Input 12,790 12,705 12,596 12,196 10,065 8,821 8,862 8,865Regional Chip Balance -1,972 -1,672 -1,023 -1,237 347 1,586 1,768 2,113Chips Imports (Exports) 2,472 2,198 2,386 2,343 1,534 -561 -1,470 -1,636 Chip Balance 500 526 1,363 1,106 1,881 1,025 298 476
Total Fibre Balance 1,890 1,800 2,464 2,156 3,328 1,794 694 722
Coast Fibre Balances – No-Beetle Forecast
The No-Beetle Forecast for the Coast (Table 2-23) shows a generally well balanced
fibre situation. The temporary uplifts in AACs from the beetle epidemic that created
a larger log supply under the Base Case are limited to the eastern sections of the
North Coast whereas the rest of log supply on the Coast is unaffected.
BCUC IR 1.19.7 Attachment 4
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Table 2-23 Coast No-Beetle Fibre Balances Fibre Supply / Demand 2007 2008 2009 2010 2011 2016 2021 2026
Log Supply (000 m3) 26,498 26,467 26,934 26,858 26,636 25,808 25,157 24,720Log Utilization 21,807 21,346 21,856 21,563 20,714 19,521 18,513 18,008Regional Log Balance 4,690 5,121 5,078 5,296 5,923 6,286 6,644 6,712Log Imports (Exports) -4,122 -4,399 -4,568 -4,763 -5,328 -4,727 -4,887 -4,975 Log Balance 569 722 510 532 595 1,559 1,757 1,737
Woodchip Output (000 m3) 10,639 10,443 10,666 10,127 9,342 8,286 7,883 7,678Pulp & Paper Mill Chip Input 12,751 12,629 12,519 12,121 9,992 6,604 6,646 6,648Regional Chip Balance -2,111 -2,186 -1,853 -1,994 -650 1,681 1,237 1,030Chips Imports (Exports) 3,033 3,150 3,852 3,286 2,662 677 -820 -232 Chip Balance 922 964 1,999 1,291 2,013 2,359 417 798
Total Fibre Balance 1,491 1,686 2,510 1,824 2,608 3,918 2,174 2,535
2.3.5 Deciduous Fibre Balances
The deciduous fibre balance is fairly tight in BC (Table 2-24 because timber supply is
limited; deciduous species are a very minor component of the Province’s forest
inventory and very little silvicultural efforts have been (and likely will be) expended on
these species.
Table 2-24 BC Deciduous Fibre Balances Fibre Supply / Demand 2007 2008 2009 2010 2011 2016 2021 2026
Log Supply (000 m3) 4,094 4,094 4,099 4,090 4,090 4,087 4,087 4,082Log Utilization 3,556 3,683 4,046 4,083 4,159 4,237 4,237 4,237Domestic Log Balance 537 411 53 7 -69 -150 -150 -155 Log Imports (Exports) 0 0 -0 3 79 153 148 148Log Balance 537 411 53 10 9 4 -2 -6
Woodchip Output (000 m3) 2,836 2,954 3,293 3,328 3,399 3,472 3,472 3,472OSB and P&P Mill Chip Input 2,695 2,813 3,153 3,187 3,259 3,331 3,331 3,331Domestic Balance 141 141 141 141 141 141 141 141Chips Imports (Exports) -62 -62 -62 -62 -62 -62 0 0Chip Balance 78 78 78 78 78 78 141 141
Total Fibre Balance 616 489 131 88 87 82 139 135
In the Interior (Table 2-25) about 60% to 65% of the demand for deciduous fibre
comes from OSB plants, primarily those in the Northern Interior Region.
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Table 2-25 Interior Deciduous Fibre Balances Fibre Supply / Demand 2007 2008 2009 2010 2011 2016 2021 2026
Log Supply (000 m3) 3,577 3,577 3,582 3,573 3,573 3,575 3,580 3,580Log Utilization 3,058 3,184 3,547 3,584 3,660 3,737 3,737 3,737Regional Log Balance 520 394 35 -11 -87 -162 -157 -157 Log Imports (Exports) 8 8 8 11 87 162 157 157Log Balance 527 401 43 0 0 0 0 0
Woodchip Output (000 m3) 2,656 2,774 3,113 3,148 3,219 3,291 3,291 3,291OSB and P&P Mill Chip Input 2,640 2,758 3,097 3,132 3,203 3,275 3,275 3,275Regional Chip Balance 16 16 16 16 16 16 16 16Chips Imports (Exports) 0 0 0 0 0 0 0 0Chip Balance 16 16 16 16 16 16 16 16
Total Fibre Balance 543 417 59 16 16 16 16 16
The balance of the demand is mostly from pulp mills also located in the Northern
Interior; there is very little demand for hardwood lumber or other products.
Restricted supplies of deciduous timber will limit the growth of the OSB and
hardwood pulp industries. In the longer term, minor log imports from Alberta will be
required to meet demand.
The deciduous wood industry on the Coast is very minor (Table 2-26) and is limited
to a few small sawmills, most of which operate intermittently depending on hardwood
lumber markets. The economics of harvesting deciduous species (mainly alder and
maple) is often marginal. Kruger’s tissue plant in New Westminster is the principal
user of hardwood chips (mostly cottonwood from the Company’s plantations in the
South Coast Region).
Table 2-26 Coast Deciduous Fibre Balances Fibre Supply / Demand 2007 2008 2009 2010 2011 2016 2021 2026
Log Supply (000 m3) 516 516 517 517 517 512 507 503Log Utilization 499 499 499 499 500 500 500 500Regional Log Balance 18 17 18 18 17 12 7 3Log Imports (Exports) -8 -8 -8 -8 -8 -9 -9 -9 Log Balance 10 9 10 10 9 4 -2 -6
Woodchip Output (000 m3) 180 180 180 180 181 181 181 181Pulp & Paper Mill Chip Input 55 55 55 55 56 56 56 56Regional Chip Balance 125 125 125 125 125 125 125 125Chips Imports (Exports) -62 -62 -62 -62 -62 -62 0 0Chip Balance 62 62 62 62 62 62 125 125
Total Fibre Balance 72 72 72 72 72 66 123 119
BCUC IR 1.19.7 Attachment 4
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2.4 Wood Chips and Residues
2.4.1 Whole-log Chipping
Residual chips from sawmills and whole-log chips from chipping plants are
essentially the same products but the costs of whole-log chips usually exceeds those
of residual chips (Table 2-27). This calls into question the economics of whole-log
chipping.
Table 2-27 Chip Costs
Despite the product being the same, pulp & paper mills have been able to use their
market power to segregate the chip market into two tiers for pricing. The mills pay
higher prices for whole-log chips than residual chips and use the supplies produced
by whole-log chippers during periods of residual chip shortages. The mills thereby
pay only higher prices for marginal supplies and avoid passing these higher prices
on to the residual chip producers, which are by far their main sources of chips.
The use of whole log chippers varies inversely with the production of residual chips.
Two years ago very few whole-log chippers were operating in the Interior as pulp &
paper mills could source nearly their entire supply of chips from sawmills, which were
running at or near full capacity. Today with poor lumber markets and sawmills taking
downtime, residual chip production has been lowered and whole-log chippers have
increased production.
Whole-log chips make up a larger portion of the chip supply on the Coast since
pulplogs form a larger part of the timber profile on the Coast than in the Interior.
The economics and future for whole-log chipping is generally poor as AMEC’s chip
price forecast shows that prices will drop in real terms in tandem with declining pulp
Phase Low High Avg.Tree-to-truck $/m3 10.00 20.00 15.00Hauling 8.50 15.00 11.75Roads 1.00 7.00 4.00Administration 4.00 7.00 5.50Silviculture 3.00 4.00 3.50Stumpage 0.50 5.00 2.75Chippers 7.00 11.00 9.00Total Mfg. Costs 34.00 69.00 51.50 Cost $/BDU 88.20 179.00 133.60
Residual Chip Prices:2001-2006 $/BDU 83.40 110.75 93.29Whole-log / Residual 106% 162% 143%
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prices (Section 3-2). Producers won’t be able to reduce their whole-log chipping
costs to the same extent and the Consultants foresee whole-log chip production
dropping by about 50% over the 20-year outlook.
2.4.2 Chip Price Forecast
Table 2-28 summarizes the chip price forecast for residual chips in the Interior
(Spruce – Pine – Fir) and Coast (hemlock - balsam). The prices are in constant
dollars per bone dry unit (BDU). The chip prices were forecast (in constant 2005
Cdn$) using formulas tied to the projected pulp prices (2007 through 2011) and a
long-term market trend line for 2012 to 2026 with simulated cycles. The formula
pricing mechanism applied rates of 9.5% to 13.5% to Canadian dollar pulp prices.
The rates varied according to the outlook for chip balances; in tight situations the
rates were increased reflecting the improving market power of chip producers and
decreased when supplies were more plentiful.
Table 2-28 Chip Price Forecast
Chip prices on the Coast have usually been higher than the Interior as there are chip
shortages on the Coast. This situation is expected to reverse over time as Coastal
pulp & paper output and chip consumption decline relative to the Interior.
Figure 2-45 shows the projected trends in pulp and chip prices (constant 2005
Cdn$).
Year Interior Coast2007 107 1112008 97 1002009 96 992010 87 872011 69 712016 61 582021 73 612026 54 49
Prices in $/BDU
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Figure 2-45
2.4.3 Residue Supplies and Demand
Figure 2-46 shows the projections of residue supplies and demand. The residue
supplies are tied to the amount of logs utilized by the solid wood industry and they
include sawdust, shavings and bark. Demand for residues include volumes used by
the pulp & paper mills and other users. The other users are pellet plants, board
plants, biomass power plants and sawmill energy systems. They currently consume
approximately 5.4 million m3 per year1 and this level of consumption is maintained
through out the projections.
1 Source: The Pulp and Paper Task Force, Utilization of MPB Fibre for Power Generation and Potential Impacts on BC’s Pulp and Paper Sector, June 2007.
Pulp & Chip Prices: Actual and Forecast
0
100
200
300
400
500
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2001 2003 2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025
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Chip Interior RH Axis
Chips Coast RH Axis
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Figure 2-46
The decline in Coastal residue demand is directly related to the lower use of chips
(decling pulp production) by Coastal pulp & paper mills. Interior pulp & paper mills’
use of residues is expected to remain fairly constant unless they utilize more
residues for surplus power generation.
The above chart shows that the Interior will have a surplus of residues but this
situation will change in about ten years; balances will then be tight and shortages are
expected to develop by 2022. This all assumes that the demand from other users of
residues remains the same.
AMEC’s analyses predict regional averages but residue surpluses and deficits will
vary considerably within smaller areas or by mill locations. Transportation costs are
high relative to the prices of residues and so economics restrict the volumes that can
be moved between areas.
The Coast is currently in a residue deficit position and pulp & paper mills must import
residues from the Interior. As pulp & paper production declines on the Coast in
future years, AMEC anticipates that the deficit will turn into a small surplus, but this
also assumes that consumption by other users does not change.
Residues - Supply & Demand
0
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8,000
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2007 2009 2011 2013 2015 2017 2019 2021 2023 2025
cub
ic m
etre
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Interior Residue Supplies
Coast Residue Supplies
Interior Residue Demand
Coast Residue Demand
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3.0 BC PULP AND PAPER INDUSTRIES OUTLOOK
3.1 Competitive Aspects – An Overview
3.1.1 Comparative Softwood Fibre Costs
After 2000, BC’s competitive cost position for softwood fibre began to improve,
moving from the mid range of international costs, to the lower mid-range by 2002.
An apparent abundance of softwood fibre for pulping in most regions, coupled with
exchange rate devaluations vis-à-vis the US and Canadian dollars (e.g. Chile,
Australia, New Zealand, Nordic) resulted in a relatively static US dollar world
average cost until the fourth quarter of 2002. Since then, the gradually weakening
US dollar, more than anything else, led to a 20% increase in the global average
cost for softwood fibre by the end of 2004.
In 2005, a weakening pulp market combined with market driven high levels of
softwood lumber production and a domestic BC residual chip surplus, drove chip
prices down to the point where BC had the lowest softwood fibre costs of all of the
world’s major pulp producing regions – even lower than Chile which is the
benchmark country for low softwood fibre cost (see Figure 3-1).
Figure 3-1 Comparative Cost Trends for BC Softwood Fibre for Pulping (US$/ODt)
0
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60
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2001 2002 2003 2004 2005 2006 1st half2007
US
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BC Interior
Chile
World Avg.
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However, in the period 2006 to date, pulp markets have strengthened while lumber
markets weakened resulting in the elimination of BC’s chip surplus. At the same
time, the value of the Canadian dollar improved remarkably vis-à-vis its US
counterpart so that by the mid point of 2007, fibre costs in BC were up 36%. By
way of comparison, the World Average increase was 11% over 2006. The only
other major pulp producing region with a similar increase was the US Pacific
Northwest (USPNW, Table 3-1).
Chile has now regained its traditional position as the low cost producer of softwood
fibre while the costs on the BC Coast have moved from the bottom of the least cost
quartile up to the World Average. The BC Interior has however managed to
remain in the lower mid-range of international softwood fibre cost.
Table 3-1 Comparative Softwood Fibre Costs for the Major Pulp Producing Regions (US$/ODt)
Country / Region 2006 Average 2007 1st Qtr. Change from 2006 Average
Western Europe 141 159 (+13) Sweden / Finland 146 146 0 Ontario / Quebec 136 127 (-7) Japan 125 121 (-3) US Pacific NW 91 119 (+31) World Average 92 102 (+11) BC Coast 75 102 (+36) U.S. East 88 88 0 BC Interior 64 87 (+36) US South 80 85 (+6) Chile 67 70 (+4)
Source: WRI, AMEC
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3.1.2 Electricity Costs
BC’s electricity costs remain among the most competitive (lowest) in the world.
Database information on industrial power rate comparisons under uniform
conditions, but excluding discounts for interruptibility or other load management, is summarized in Table 3-2. Second half 2006 exchange rates
were used to convert to US$ from other national currencies. It should be noted
that there can be wide ranges within a region, e.g., the US Northeast has a range
from US$40/MWh in Maine, which has a significant pulp and paper industry, to
US$(110-130)/MWh for Rhode Island and Connecticut, neither of which has any
pulp and paper industry to speak off.
Table 3-2 Official Average Regional Electricity Costs for Large Industrial Customers at Second Half 2006 Exchange Rates
Industrial Electricity Rates, US$/MWh CANADA
British Columbia $35.37 Alberta $59.44 Saskatchewan $51.15 Manitoba $31.13 Ontario $81.75 Quebec $41.01 New Brunswick $53.62 Nova Scotia $61.29 Newfoundland $49.74
USA Midwest $47.56 Northeast $93.33 South $54.93 West $52.14
EUROPE Austria $92.90 Belgium $117.38 Finland $81.35 France $75.07 Germany $130.69 Italy $150.52 Netherlands $94.28 Norway $79.16 Spain $74.32 Sweden $65.38 United Kingdom $195.63 Switzerland $82.59
OTHER Australia $56.85 Brazil $32.19 Chile $67.11 New Zealand $54.31 South Africa $29.54
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The competitive power costs in Western Canada are one of the main factors for
the significant capacity in electrical energy intensive grades, such as:
• TMP based newsprint and mechanical printing papers – all machines in
Western Canada rely on this energy intensive pulp, with only a very minor
deinked pulp component added to satisfy specific US customers.
• Bleached market CTMP – Western Canada (the provinces of BC, Alberta
and Saskatchewan) has the largest share of market CTMP in the world.
Specifically, out of a total of 24 market CTMP lines in the world, with a total
capacity of 9,500-10,000 MT/day :
- 15 are in Canada (11 in the West and 4 in Quebec)
- of the11 Western mills, 6 are in BC
- Canada’s share of global market CTMP capacity is 73%
- Western Canada’s share of global market CTMP capacity is 54%
- BC’s share of global market CTMP capacity is 25%.
Energy competitiveness notwithstanding, it should be noted that overall or global
competitiveness may shifts when raw material composition changes. As an
example, the increased use of deinked fibre (which requires only about 15% of
the TMP/CTMP energy) in newsprint during the last 10-15 years has allowed
high power cost regions in the USA to produce competitive cost newsprint.
A second example is bleached CTMP competitiveness. On exactly the same
basis, i.e. CTMP-to-CTMP comparison, BC is one of the most competitive
regions in the world (see later section on competitive pulp and paper production
costs). However, low wood cost, Southern hemisphere regions (notably Brazil,
Chile, and Indonesia) can produce bleached hardwood kraft pulp with generally
superior papermaking properties at a lower overall cost than BC market CTMP.
Furthermore, these pulps can be offered in the global market at competitive
prices while still providing a satisfactory return to their suppliers. Unfortunately,
this is not always the case for Canadian CTMP mills, since:
• Their manufacturing costs are generally higher than the costs of modern
bleached eucalyptus (or other, e.g. mixed tropical species) bleached
hardwood kraft pulps. A generic comparison of variable manufacturing costs
is presented in Figure 3-2.
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• Market prices for bleached hardwood CTMP are generally about 10% lower
than bleached eucalyptus kraft pulp.
Figure 3-2 Brazilian Eucalyptus Bleached Kraft vs. BC Hardwood CTMP Generic Manufacturing Cost Comparison
In summary, although they enhance competitiveness of electrical energy
intensive mechanical pulps and printing papers, low power costs alone are not
enough to guarantee a strong competitive position. Therefore, the industry’s long
term viability will continue to be strengthened by competitive power costs. In
relation to this, and recognizing the inevitability of rising (purchased) energy
costs, BC pulp and paper producers are taking steps to maintain and improve
their competitive edge, often in conjunction with BC Hydro.
3.1.3 Kraft Pulp and Papers
Kraft mills: BC kraft mills continue to be an area of weakness, with little or no
realistic possibility for improvement in the foreseeable future. Poor financial
results are compounded by the negative impact of the Mountain Pine beetle
epidemic on the quality and cost of the pulpwood raw material. BC kraft mills,
which supply about 20% of global bleached softwood market pulp, and which
were the pride of the BC forest industry in the 1960s and 1970s, have become a
major concern and even a burden in some cases. BC’s softwood kraft pulp
industry has undergone a significant capacity rationalization during the last five
years, and capacity is expected to continue declining. BC mills are old and
0
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Brazil BleachedEucalyptus Kraft
BC BleachedHardwood CTMP
Pro
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ost
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$/A
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T
Labour &Supplies
Energy
Chemicals
Wood
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generally intermediate-to-high cost. Most mills require major investment to
ensure continuing viability, and (especially the three Vancouver Island mills) are
challenged by fibre availability.
Table 3-3 shows the technological age (i.e. it includes the effect of major
rebuilds) distribution of 14 (includes Catalyst, Campbell River sawdust and
unbleached pulp, as well as West Fraser Timber, Kitimat unbleached kraft)
operating BC kraft mills. Only two mills can be considered to have a
technological age less than 20 years.
Table 3-3 BC Kraft Mill Technological Age Distribution
Mill Age Number of Kraft Mills
20 or more years 12 Less than 20 years 2 Total 14
BC’s kraft pulp capacity declined from 6.1 to 5 million MT/year between 2002 and
2006 and the trend is expected to continue (see long term forecast Section 3.8).
There is, however, one caveat or risk factor to this premise, namely that the
phenomenal hunger of China for papermaking raw materials (also in Section 3.8)
could result in Chinese acquisition and investment in BC. A rumour to that effect
involving two BC kraft mills has been making the rounds recently.
Kraft papers: There are two basic types of kraft papers:
• Bleached, essentially coated and uncoated woodfree P&W papers, plus
coated/white board – With the shutdown of BC’s only woodfree P&W paper
mill (Domtar, Annacis Island) 1-2 years ago, BC has exited the woodfree
P&W field. Furthermore, the province has limited white board capacity at
Catalyst, Elk Falls, and Canfor’s Prince George Pulp & Paper. The former is
a White Top Liner (e.g. pizza delivery boxes white on the outside and
unbleached on the other), while the latter produces a mix of white and
unbleached packaging paper/board products. With no significant regional/
local packaging paper and paperboard demand, and limited export potential
for such a small manufacturing base, BC is likely to remain a minor player, in
light of low cost manufacturing of these grades by other regions, including
Southeast Asia in recent years.
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• Unbleached – These are sack grades (including supermarket bags), which
have been on the decline due to plastic bag substitution, and some specialty
(e.g. extensible) kraft grades. Although the future for the former
(conventional kraft/bag) grades did not appear rosy in recent years, with
demand declining about 4-5% per year in North America (losing close to 30%
of annual consumption between the late 1980s and mid-2000s), the recent
and current “green revolution” may partially reverse the fortunes for this
sector (e.g. displacing plastic bags, which some municipalities in the USA
and Canada are banning). Nevertheless, with the possible exception of some
specialty grades, the outlook for growth is not promising.
3.1.4 Mechanical Pulps and Mechanical Printing Papers
Production of mechanical pulp based papers has traditionally been one of BC’s
areas of strength. The primary reasons are the strong softwood fibre and highly
competitive power costs (see earlier sections). One of the recognized
disadvantages of the Coastal region (as opposed to the Interior) has been the
relatively high chromophore count in coastal softwoods, resulting in somewhat
darker unbleached mechanical pulp (and therefore a greater challenge to
achieve desired high brightness levels). However, Catalyst Paper, through a
combination of a large (50-100%) share of interior wood chips, optimizing
hydrogen peroxide bleaching of mechanical pulps, and the use of special mineral
pigments, has been quite successful in achieving the highest brightness level
mechanical printing papers in some of its coastal mills.
The second challenge for any mechanical pulp and printing papers producer still
remains what has been called the “Achilles’ heel” of TMP, namely high electrical
demand, running to 2,500-3,000 kWh/tonne for some high quality products.
Implementation of some of the energy reduction technologies for mechanical
pulping has recently begun at the commercial scale. Intense research activity,
which began during the 1970’s with the large scale commercialization of TMP,
continues. This includes studies at the UBC Pulp & Paper Centre, as well as the
Pulp & Paper Research Institute of Canada. Based on historical experience,
there are prospects for reducing TMP specific energy (kWh/tonne), however we
do not expect that large specific energy reductions, of the order of 50% or more,
are achievable in the foreseeable future. Rather, potential specific energy
reduction of the order of 10% or so would represent more realistic expectations.
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In summary, there are technological developments that will enhance
competitiveness of mechanical pulping and papers made from it. Of course, the
mills’ operational position would be greatly improved by replacing old (some of
them dating from 1975) TMP lines with modern ones, which generally produce a
higher quality pulp at about 5-10% lower specific energy input. However, the
cost savings for an investment of the order of $125 million for a new line work out
to about $3-$5 million per year, i.e. a payback period of several decades does
not justify the investment, unless another organization (e.g. BC Hydro) defrays
part of the initial capital cost.
Regarding the papers themselves, the shift away from newsprint (declining
market size) and towards increasingly higher value uncoated and coated
groundwood printing paper products will continue to at least 2015-2020. [Note:
Beyond 2015-2020 some of the higher value paper end uses, notably magazines
and catalogs, may begin to decline in demand, causing a corresponding
reduction in higher value print grades.] This is the primary option for BC
newsprint and (lower grade) uncoated groundwood mills to maintain
competitiveness in an increasingly difficult market. Moving up the quality chain
generally implies two things, namely:
• Higher brightness. As noted above, the Coastal region has a greater
challenge than the BC Interior (or the rest of North America) due to its darker
wood species. Nevertheless, it has been demonstrated by Catalyst Paper
during the last 4-5 years that the BC Coast can be a competitive producing
region for the highest brightness mechanical printing papers (using BC
Interior wood chips as the dominant raw material for TMP in high brightness
grades).
• Higher finish (glossier, smoother sheets). This is achieved by using higher
amounts of mineral pigment filler and finishing (soft nip calendering)
technology.
In summary, BC mills will continue to improve competitiveness in mechanical
printing papers by moving to higher value products. In doing so, there will be two
opposing trends in specific energy per tonne of paper product:
• Substitution of fibre with mineral pigment will tend to drive specific energy per
tonne of paper down (lower fibre processing).
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• Higher TMP/CTMP quality, demanded by the higher value products, will tend
to drive specific energy up.
The outcome (higher or lower overall specific energy) will depend on the paper
grade being made, and it is not possible to provide a universal trend. In
particular, the basis weight (weight per unit area of paper) has a dominant
influence, since it affects the amount of fibre required to produce a given area of
paper (remember that paper machines run to speed limits generally imposed by
their drive system, and perhaps dryer section design). For example, converting a
machine producing 600 tonnes/day from 45 grams per square metre (gsm)
newsprint to 34 gsm telephone directory, in principle will bring about a roughly
proportionate reduction in daily TMP requirements, i.e. about 20% reduction.
Therefore, assuming a TMP specific energy of 2.2 MWh/tonne, a 20% reduction
from 600 to 480 tonnes of TMP required will result in 260-270 MWh/day.
3.2 Cost Competitiveness of Key Pulp and Paper Products
Manufacturing, and in particular delivered, cost is a critical competitiveness
aspect of commodity products production and marketing. In this section we
review cost-competitiveness issues of key BC pulp and paper products,
beginning with a brief background to, as well as an overview of, the cost model.
Competitive cost analysis is an important method of determining a producer’s
overall competitiveness relative to other mills manufacturing the same product.
The analysis is usually developed by product type to rank a producer against
competitors within a defined market segment. This type of analysis generally
serves to benchmark a producer’s cost relative to competitors so as to provide a
baseline for strategy development. Market leaders usually have the lowest costs
in their respective market segments and the assessment of competing
companies’ and mills’ cost competitive position is most important when
considering a pulp and/or paper manufacture’s financial performance and
behaviour in the market. It is also important to understand cost competitiveness
when analyzing short-term market fluctuations in pulp prices but especially when
determining a mill’s longer-term viability and strategies.
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Temanex Paper Manufacturing Cost Model Structure
The paper cost analysis is based on defining mill level variable cash operating
costs. It involves:
a) Using the Temanex paper manufacturing cost model/software.
b) Combining (as input data to the software), print grade paper machine size,
furnish composition and manufacturing technology with unit manufacturing
costs (wood, chemicals, recovered paper, electricity, supplies/consumables,
labour) and exchange rates. Freight costs are included for those grades
which are widely distributed in a relatively uniform manner throughout a
specific large geographical market. In BC’s case this only applies to coated
mechanical, and it is the result of approximately 65-70% of North American
coated paper printing activity concentrated in the US Midwest and Northeast.
Excluded from the cost estimate are the following fixed and variable costs:
• Capital, depreciation and related financial charges.
• Head office, sales and mill administrative charges. These include salaried
positions at the mill that are not direct O&M (operating and maintenance)
charges, insurance, municipal taxes, sales commissions, and so on.
The basic manufacturing cost model without freight (which is calculated
separately for specific products as needed) includes the variable cost inputs
summarized in Table 3-4. In keeping with standard commodity products practice,
to ensure apples vs. apples comparison, all regional production costs are
converted to US$/MT basis.
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Table 3-4 Manufacturing Cost Model Inputs
PRODUCTION DATA COST DATAMachine & Related Data Width, speed, production rate
Exchange Rates Labour & Supplies Per tonne of paper and/or pulp
Raw Materials Pulp Yield Pulp moisture
Wood chips and/or recovered paper Purchased pulp Purchased pigments/coating materials
Paper Data Basis weight, moisture, furnish composition, process technology
Inputs and unit costs as required
Pulping & Bleaching Chemicals Pulping chemicals Bleaching sequences and bleaching chemicals application rates
Pulping, deinking and bleaching Conversion (papermaking)
Energy Power & fuel
Electricity/Fuel Purchased/Self-generated
3.2.1 Newsprint Machines
Newsprint is a relatively regional grade, in that BC production is primarily shipped
to Western North America, while Quebec and Ontario production goes mainly to
the US Northeast and Midwest. As a result, freight as a competitive cost
component is not a major issue for this grade, therefore it is not included in the
delivered cost-competitiveness comparisons. Nevertheless, it should be noted
for completeness that freight costs for newsprint shipped from BC have a
weighted average in the region of US$(75-80)/MT.
In 2006 there were 79 newsprint machines operating in North America, at least
for a portion of the year (this is down from 133 machines in 1992 and 85
machines in 2005). Figure 3-3 summarizes the cost vs. cumulative capacity
position of the 79 newsprint machines ranked from low (most competitive) to high
(least competitive) cost. BC machines are identified as large, blue open squares.
It is seen that there are both low as well as high cost producers among the seven
BC machines which produced, at least for some of the time, newsprint in 2006.
The high cost ones are the primary candidates (and in fact are in the process of
being converted) for conversion to higher value uncoated mechanical products.
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The 35-40% appreciation of the euro against the US dollar during the last 4-5
years is largely responsible for the relatively high average cost of Western
European LWC machines (roughly in the range US$800-US$825 per metric
tonne) compared to North American ones (roughly in the range US$650-US$700
per metric tonne). However, the cost range from low to high is much narrower for
the European machines, showing a more uniform cost structure.
3.2.5 Bleached Softwood Kraft Pulp (BSKP)
Whereas Temanex carried out all the other cost competitiveness analysis, this
segment was carried out by AMEC, as AMEC’s database has particular strength
in this area, as a result of AMEC’s long standing market pulp mill experience and
contacts. Unlike the paper grades analyzed above, which are regional in North
America, market pulp is a true global commodity. Therefore BC mills compete
with mills from Europe, South America, and possibly other regions in the global
market. Some 75 BSKP producer mills worldwide were compared against
corresponding BC mill costs. Although these mills produce different grades
within the broader BSKP classification (Northern Softwood, Southern Pine,
Sawdust pulp, etc.), they all generally compete against one another in commodity
grades. The mills in this analysis are considered to be representative of the
global industry and include all the largest producers. In total about 20.6 million
tonnes of BSKP capacity was included in this analysis. Only market pulp mills
have been studied in this analysis, pulping operations that are integrated into on-
site or affiliated paper machines have been excluded.
AMEC’s model for estimating the competitive cost curve includes all cash
manufacturing cost items involved in the production of pulp. Manufacturing cost
estimates include all variable and fixed cost items and are developed using the
following five classifications: fibre, chemicals, energy, operating materials and
supplies, wages and salaries, and overhead and administration.
AMEC maintains a database of key information on each of the mills in this
analysis. This information has been collected from public sources – annual
reports, company websites, trade journal mill profiles, mill directories, etc. This
information is combined with AMEC’s technical and financial experience and
cross-checked with the Fisher Database. From this information overall material
and energy balances are developed for each of the mills in the analysis.
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The material balances provide a basis of the variable cost calculations. The raw
material unit consumption, that is required for the production of each metric ton of
pulp, is determined in the balance. Against these consumption figures AMEC
applies regional unit cost information such as wood, chemicals, purchased
energy, and labour rates. When possible AMEC spot checks our estimated costs
with actual mill information data to determine if fundamental changes must be
made to our models to more accurately estimate costs.
Wages and salaries are generally the largest fixed cost item. AMEC has
estimated this cost item based on public information and the interpretation of mill
size, age, configuration, and equipment by our consultants who have experience
with similar mills. These staffing estimates are then applied to regional wage and
salary levels that we maintain and cross check with available actual information.
For mills with more than one pulping line and for mills producing various grades
of pulp the average cost of production across the mill has been used in this
study. Note that our estimates assume that all mills are running under normal
operating situations and that no excessive market related downtime is taken.
Figure 3-9 shows the global market BSKP cost vs. cumulative capacity curve.
Figure 3-9 Global BSKP Production Cost vs. Cumulative Capacity Curve
GLOBAL Market BSKP Competitive Cost Curve(Q2 2007)
0
100
200
300
400
500
600
700
0 5,267,270 10,534,540 15,801,810
Cumulative Industry Capacity '000 ADt/a (Quartile Divisions)
US
$/A
Dt (C
ash
Cos
t Exc
ludi
ng D
eliv
ery)
20,653,000
BC Bleached Softwood Kraft Pulp Mills
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The following points should be noted:
• The median cash manufacturing cost for all BSKP mills in this analysis,
excluding delivery, is estimated to be US$462/ADt, the range of mills’ total
cost is from US$256/ADt for the lowest cost mill to US$619/ADt for the
highest cost mill.
• The average total mill level cost of all BC mills is US$418/ADt, and the mills
range from a low of US$338/ADt to a high of US$552/ADt. The BC mills are
generally middle range cost producers of BSKP, positioned in the second and
third quartiles of the cost curve according to our estimate.
3.2.6 Market Bleached CTMP
Figure 3-10 provides the global market bleached softwood CTMP cost vs.
cumulative capacity curve, showing the two BC Interior mills as being the lowest
cost producers, based on their twin advantages of relatively low 2006 wood chip
costs and low power costs in comparison with global competitors.
Figure 3-10 Global Market Bleached Softwood CTMP Production Cost vs. Cumulative Capacity Curve
$200
$300
$400
$500
$600
0 1,000 2,000 3,000 4,000 5,000
Cumulative Capacity, ADMT/Day
Pro
du
ctio
n C
ost
, US
$/M
T
Two BC mills identified as blue open squares
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Similarly, Figure 3-11 provides the corresponding global cost vs. cumulative
capacity curve for hardwood market bleached CTMP. Again, the two BC Interior
mills are the lowest cost producers (but still somewhat higher than a modern
bleached eucalyptus kraft pulp mill – see earlier Figure 3-2).
Figure 3-11 Global Market Bleached hardwood CTMP Production Cost vs. Cumulative Capacity Curve
3.3 Some Manufacturing Cost Sensitivities
3.3.1 Specific Electrical Energy Demand
Specific energy is expressed in kWh/tonne of pulp or paper product, and it is
important to define clearly what product is being referred to. For example, it
takes about 2,200 kWh/MT of newsprint grade TMP, and an additional 500
kWh/MT to run the paper machine. So for 100% TMP newsprint the total
newsprint specific energy consumption is 2,700 kWh/MT.
Table 3-5 summarizes kWh/MT for the major BC pulp products which are the
focus of this study. The following points should be noted:
$250
$350
$450
$550
0 1,000 2,000 3,000 4,000 5,000 6,000
Cumulative Capacity, ADMT/Day
Pro
du
ctio
n C
ost
, US
$/M
T
Two BC mills identified as blue open squares
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• The range of integrated TMP/CTMP reflects mill equipment (e.g. old refiners
dating from the 1970s tend to use more energy than more modern, 1990s,
versions) and operational philosophy differences.
• The broad range of kraft mill purchased energy demand reflects the fact that
some mills are near self-sufficiency, while others may purchase most of their
power from the grid.
• The broad range of market bleached CTMP largely reflects the wide variety of
end products in which the CTMP is utilized, ranging from high freeness (lower
specific energy) board and tissue applications to lower freeness (higher
specific energy) print grade applications.
Table 3-5 Purchased Electrical Energy Demand of Major Pulps Produced in BC Pulp & Paper Mills
Purchased Specific Energy, kWh/MT Pulp End Use Paper
Products Range Low-High Typical
Integrated TMP/CTMP Newsprint 2,000-2,400 2,200
Integrated TMP/CTMP
Mechanical Specialties (Coated & Uncoated)
2,400-2,800 2,600
Integrated Kraft Print Grades, Kraft Papers, Linerboard
100-800 200
Market Bleached Softwood Kraft
Miscellaneous Grades 100-1,000 250
Market Bleached CTMP Softwood
Miscellaneous Grades 1,800-2,800 2,350
Market Bleached CTMP Hardwood Miscellaneous Grades 1,600-2,400 2,000
Table 3-6 summarizes paper machine (i.e. excluding pulping energy summarized
in the above table) kWh/MT for the major BC paper products which are the focus
of this study.
Table 3-6 Paper Machine Electrical Energy Demand of Major Paper Products Produced in BC Pulp & Paper Mills
Purchased Specific Energy, kWh/MT Paper Range Low-High Typical
Newsprint 500-550 525 Uncoated Mechanical Specialties 525-575 550 Coated Mechanical 550-650 600
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3.3.2 Purchased Electrical Energy Cost
Differences in purchased specific energy demand of different market pulp and
finished paper products result in different sensitivities to electrical energy cost.
Newsprint: Using data from the earlier pulp and paper product cost-
competitiveness sub-section (3.2), Figure 3-12 provides the electrical energy cost
sensitivity of BC newsprint machines expressed as electrical energy cost as a
percentage of mill level manufacturing cost. Machines with electricity cost below
about 20% share use some deinked fibre as opposed to practically 100% TMP.
Figure 3-12 Electricity Cost Share of BC Newsprint Machine Manufacturing Cost
Directory: There are three directory machines in BC, all at the Catalyst Crofton
paper mill. In this case, although the specific energy of the TMP component
used in directory production is greater than for TMP going to newsprint (see
earlier table on pulp specific energy), the cost share is lower because there is a
minimum requirement of 40% deinked fibre in the majority of North American
directory. As a result, electrical energy as a percentage of mill level directory
cost is 16-17% for all three machines.
0
5
10
15
20
25
30
A B C D E F
Machine ID
Ele
ctri
city
Co
st A
s %
Of
To
tal M
ill
Co
st
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Soft nip calendered: There are two soft nip calendered machines in BC, one
each at Catalyst Paper Elk Falls and Powell River mills. Their overall production
costs are higher than newsprint, and they use some bleached kraft and filler
pigment, therefore the electrical energy share of total costs is somewhat lower
than for 100% TMP newsprint. As a result, electrical energy as a percentage
of mill level soft nip calendered cost is 22% for one of the two machines
and 24.5% for the other.
Market bleached softwood kraft pulp: Kraft mills self-generate significant
amounts of their electrical energy requirements. Figure 3-13 provides the
purchased electrical energy cost sensitivity of BC kraft mills expressed as
electrical energy cost as percent of mill level manufacturing cost. The share in
this case is significantly smaller than for the paper grades discussed above.
Figure 3-13 Purchased Electricity Cost Share of BC Market Bleached Softwood Mills’ Manufacturing Cost
Market bleached CTMP: CTMP mills consume a significant amount of
(purchased) electricity. Figure 3-14 provides the electrical energy cost sensitivity
of BC softwood and hardwood market CTMP mills expressed as electrical energy
cost as percent of mill level manufacturing cost. The data in this case are
provided in ranges, since both species are used in the production of a variety of
CTMP’s with varying specific energy requirements. The share, especially of the
0
2
4
6
A B C D E F G H I J
Kraft Mill ID
Pu
rch
ased
Ele
ctri
city
Co
st A
s %
Of
To
tal M
ill C
ost
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softwood grades, is in this case the highest of the pulp and paper grades
analyzed here, with the hardwood pulps having somewhat lower sensitivity than
softwoods.
Figure 3-14 Purchased Electricity Cost Share of BC Market Bleached CTMP Mills’ Manufacturing Cost
3.3.3 Exchange Rate Fluctuations
As summarized in the earlier Table 3-4, the pulp and paper products cost
analysis includes the following major cost components:
• Raw materials: Wood, wastepaper (for recycling), mineral pigments (in the
case of coated and pigment-filled papers).
• Chemicals: Pulping and bleaching.
• Energy: Power and fuel.
• Labour: Operating and maintenance for most grades; plus mill management
overheads for bleached softwood kraft analysis in this study.
• Supplies: Refiner plates, paper machine clothing (felts and drainage fabrics),
pulp or paper roll wrapping materials, glues, and so on.
Since virtually all of these are priced based on a given country’s (e.g. Canada) or
region’s (e.g. European Union country’s using euro as the currency) currency,
but pulp and paper product prices are denominated almost exclusively in US$, it
20
22
24
26
28
30
32
34
Softwood Hardwood
Ran
ge
Of
Ele
ctri
city
Co
st A
s %
Of
To
tal M
ill
Co
st
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is standard, logical and rational practice to convert all manufacturing cost data to
US$ basis, in order to avoid apples vs. oranges comparisons. Exchange rate
fluctuations, therefore, have a significant influence on a mill’s pulp or paper
products’ cost-competitive position.
Figure 3-15 shows the annual average exchange rate trend for the Canadian
dollar against the US dollar.
Figure 3-15 US$:Can$ Average Annual Exchange Rate Trend
The nearly 50% increase in Canadian dollar strength since 2002 would have
resulted in a proportionate increase in Canadian pulp and paper product costs
expressed in US$/MT of product, a really devastating increase, and the primary
reason for the poor financial performance (including heavy losses) of most
Canadian pulp and paper companies. More recently, as shown in the above
chart, the Canadian dollar appreciated by about 7% between its 2006 average of
0.88 US dollars and 0.95 US dollars in August, 2007. For completeness, Table
3-7 provides the sensitivity summary of key BC products to a 10% change in
Canadian to US dollar exchange rate shift.
0.640.71
0.770.83
0.88 0.90.95
0
0.2
0.4
0.6
0.8
1
2002
2003
2004
2005
2006
2007
-YTD
Augus
t
Aug-0
7
US
$ E
xch
ange
Rat
e vs
. Can
adia
n
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Table 3-7 Exchange Rate Sensitivities of Key BC Pulp & Paper Products
Approximate Increase In BC Mill Costs From 10% Appreciation Of Canadian vs. US Dollar
Product Base Case Exchange Rate [US$:Can$ = (0.85-0.88)]
Typical Product Cost, US$/MT
Incremental Product Cost From 10% Can$
Appreciation vs. US$, US$/MT
Newsprint $400 $(35-40) Directory Paper $525 $(48-52) Soft Nip Calendered $400 $(35-40) Lightweight Coated $625 $(58-62) Market Bleached Softwood Kraft $400 $(35-40)
Market Bleached CTMP Softwood
$275 $(24-27)
Market Bleached CTMP Hardwood
$300 $(25-30)
3.4 Electrical Energy Self-Generation Update
As part of the BC pulp and paper mill baseline production data collection for the
previous full year (2006), the simple (to encourage response) email questionnaire
included questions D summarized in the table below. [Note: The client, BC
Hydro, requested, in the project terms of reference, that the survey questionnaire
include the two questions (section D of questionnaire) summarized below.]
D. Electrical Energy 2006 Self-Generation & Outlook To 2010
Electrical Energy Generation MWh In 2006 (or Yes/No)
Special Comments (if any)
Electrical energy generation in 2006? Planning for higher electrical energy generation next 2-4 years?
Not all mills have self-generation (e.g. no self-generation at CTMP market pulp
mills), and not all mills which do have self-generation responded to this question
(in fact 2-3 mills did not respond to the entire questionnaire), but Table 3-8
summarizes the responses of mills which responded to these questions.
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Table 3-8 BC Pulp Mill Power Self-Generation In 2006 And Short-To-Medium Term Future Outlook (To 2010) For More Self-Generation [Information Received From Responding Mills]
Electrical Energy Future PlannedGeneration - 2006 GenerationMWh (MW in one
case)MWh (MW in one
case)
West Fraser Timber Quesnel 28.5 MW In 2 to 4 yearsPotential project in 2 to 4 years
Canfor Pulp Prince George 106,913 yes Very preliminaryCanfor Pulp Prince George 328,000 yes Expect about 25% Canfor Pulp Prince George 366,000 yes Very preliminaryMercer International Castlegar Yes yesDomtar Kamloops yes yesTembec Inc. Cranbrook 286,782 yesWest Fraser Timber Kitimat None 19 MW in 2007Howe Sound P&P Port Mellon 432,633 yes
Pope & Talbot Nanaimo 257,358 yesPending generator rewind & process review
Catalyst Paper Campbell River 196,020 noCatalyst Paper Crofton 247,182 yes
Company City COMMENTS
3.5 Productivity and Technological Age Comparisons
In addition to the cost-competitiveness analysis carried out in the earlier Section
3.2, competitiveness benchmarking which includes specific productivity and
technological age parameters provides additional competitiveness
comparisons, which provide further insight on a given machine’s or mill’s
competitive position. This section includes basic competitiveness parameter
comparisons for BC and North American print grade machines and market pulp
mill lines. After reviewing the data, as well as the corresponding summary
reports for Power Smart (project rolled into this one), we concluded that
productivity, expressed in MT/day capacity, divided by machine technological
age provided the most representative generic (excluding cost analysis carried out
earlier) competitiveness benchmarking parameter for paper machines, and line
productivity in MT/day capacity for market pulp lines.
3.5.1 Newsprint
Figure 3-16 summarizes the North American newsprint machine position for all
79 machines operating in 2006. Two BC machines are in the lower
competitiveness region (and in fact they are being shifted to high value products),
while the other machines hold intermediate to high competitiveness positions.
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3.5.4 Market Bleached CTMP
Figure 3-21 summarizes the Capacity:Age ratio of 24 global bleached CTMP
lines operating in early 2007. In this case we are using actual mill age, as there
is no specific distinguishing technological age characteristic to incorporate in
defining technological age.
Six out of the 24 global market CTMP lines are in BC, representing 25% of global
capacity. The low (1-3 years) age of the two most recently installed lines in
Europe (Utansjo, Sweden and Kunda, Estonia) boosts their capacity:age ratio
rather abnormally high. This results in some apparent distortion of the chart
which makes older lines appear even less competitive than they really are – BC
mill lines are in fact in the intermediate-to-high competitiveness range.
Figure 3-21 Global Market CTMP Line Capacity:Age Ratio Competitiveness Ranking
3.5.5 Market Bleached Softwood Kraft Pulp (BSKP)
Figure 3-22 shows similar Capacity: (Technological Age) ranking for 77 global BSKP
dryer lines. It should be noted that in this case technological rather than actual age
is used. There are 18 BSKP dryer lines in BC market BSKP mills representing close
to 20% of global capacity for this product. In this case, about two-thirds of BC’s
market BSKP dryer lines are low competitiveness, with the remaining one-third
intermediate (and perhaps 1-2 lines intermediate-to-high) competitiveness.
0
100
200
300
400
0 2,000 4,000 6,000 8,000
Cumulative Capacity (MT/Day)
Mac
hin
e C
apac
ity:
(Tec
h A
ge)
, (M
T/D
ay)/
Yea
rs
BC mill CTMP lines identified as blue open squares
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Figure 3-22 Global Market Bleached Softwood Kraft Dryer Line Capacity:(Technological Age) Ratio Competitiveness Ranking
0
200
400
600
800
0 10,000 20,000 30,000 40,000 50,000
Cumulative Capacity (MT/Day)
Mac
hin
e C
apac
ity:
(Tec
h A
ge)
, (M
T/D
ay)/
Yea
rs
2 4 2 2 2
BC mill BSKP dryer lines identified as blue open squares(numbers above a point show more than one line)
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3.8 Pulp and Paper Products in BC
3.8.1 Background Summary of Recent Developments
The Canadian (including BC) pulp and paper industry has come under increasingly
intense pressure during this decade, largely as a result of the following:
• Demand decline for product in key sectors, notably newsprint.
• Significant component of outdated, low competitiveness capacity in both
market pulp and papermaking facilities (see earlier competitiveness summary
section).
• Significantly stronger Canadian dollar against the US dollar in which global
commodity products, including pulp and paper ones, are priced. The result is
that in the absence of productivity increases, Canadian production costs,
expressed in US dollars, have escalated more or less in unison with the rising
Canadian dollar. However, market prices are still denominated in US dollars,
therefore profitability margins have shrunk significantly (and in fact turned
negative in many cases).
Consequently, a significant share of outdated pulp and paper capacity has been
shut down as part of efforts to improve corporate performance, or simply due to
bankruptcy in the worst cases. This has reduced Canadian pulp and paper
capacity and production/shipments, as summarized in Figures 3-24 and 3-25.
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Figure 3-24 Canadian Bleached Softwood Kraft Capacity and Shipments Recent Trend
Figure 3-25 Canadian Newsprint Capacity and Production/Shipments Recent Trend
BC’s pulp and paper industry has not escaped the pain, as can be surmised from
the following capacity closures during this decade (not a complete list but one
which focuses on key shutdowns):
1. Catalyst Paper, Powell River mill kraft mill.
2. Catalyst Paper, Port Alberni mill machine #3.
6,000
6,500
7,000
7,500
8,000
2000 2001 2002 2003 2004 2005 2006
Cap
acit
y &
Sh
ipm
ents
, 000
MT
Capacity
Shipments
7,000
7,500
8,000
8,500
9,000
9,500
10,000
2000 2001 2002 2003 2004 2005 2006
Cap
acit
y &
Sh
ipm
ents
, 000
MT
Capacity
Production/Shipments
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3. Domtar, New Westminster uncoated and coated woodfree paper mill.
4. Catalyst Paper, Port Alberni mill machine #4.
5. Catalyst Paper, Port Alberni mill stone groundwood mill.
6. Western Pulp, Squamish bleached softwood kraft mill.
3.8.2 Major Drivers for Change
The major drivers which have been inducing changes in the BC pulp and paper
industry for the last 5-10 years, and are anticipated to continue shaping the
industry’s development for the next 15-20 years, are summarized in the following
sub-sections. Some of these drivers are evolutionary (e.g. demographic trends),
while others are relatively recent new or emerging developments (e.g. Internet
impact on advertising industry trends, emerging environmental awareness).
Mature, Declining Market Sectors and Digital Substitution
This was briefly discussed in Section 1.2 with respect to newsprint. A conceptual
illustration of future issues and concerns for higher value papers is presented in
Figure 3-26 focusing on mechanical printing papers, which are the highest
tonnage and most electrical energy intensive products manufactured in BC.
Figure 3-26 Historical North American Demand Trends for Newsprint, and Future Outlook Scenarios for Higher Value Mechanical Printing Papers
70
80
90
100
110
120
130
1975 1980 1985 1990 1995 2000 2005 2010 2015 2020 2025
Dem
and
Ind
ex
Paper A(2005=100)
Paper B(2005=100)
Newsprint(1980=100)
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What the chart shows is that newsprint sector peak demand was achieved
around 1990, followed by decline, due to sector maturity, thereafter. Two distinct
future market evolution scenarios are also presented for two different higher
value papers, such as coated and uncoated mechanical specialties. These show
that demand for certain higher value papers (example paper A) is likely to
continue growing, both as a result of “organic” growth, as well as displacement of
less competitive products, such as newsprint. Supercalendered/soft nip
calendered papers (made on two Catalyst Paper machines – #2 at Elk Falls and
#10 at Powell River) are one type of such a product, which will likely continue
growing, possibly to the end of the forecast horizon for this project. Coated
mechanical grades, on the other hand (made on machine #5 at Catalyst Paper,
Port Alberni), are more likely to follow a trend similar to the one for newsprint, but
peaking around the year 2015 (example paper B in the chart).
The main driver for the demand slowdown of print grades is digital substitution
(Internet), coupled with demographic trends. A key demographic trend which
accelerates the transition from paper to digital communication over the longer
term, is the decreasing share of the North American population which is relatively
more comfortable with printed paper than with the digital communication option.
In order to illustrate and quantify the magnitude of changes to come, we analyze
below shifts in both the share and actual number of people between a base year
and a future year in the second half of the 20-year forecast horizon for this
project. As a working example 1995 (the beginning of the Internet introduction
decade) was chosen as the base year, and 2020 was selected as the future year
(roughly halfway through the second half of this project’s 20-year horizon to
2026). Two population age classes were differentiated according to level of
comfort or preference of printed vs. digital communication. This was done by
setting, somewhat arbitrarily but reasonably, 1975 as the birth year separating
those with a high level of printed paper comfort (born before 1975), from those
who grew up with and are much more comfortable with digital communication
and less so with paper (born 1975 or after). Table 3-13 shows the sharp decline,
between 1995 and 2020, in both the percentage share as well as absolute
number of people in the North American population who were born before 1975.
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Table 3-13 North American Population Age Shifts 1995 to 2020
Living Population Born Before 1975 1995 2020 Percent (born before 1975) of total population 71% 41% Millions (born before 1975) 212 155
As the number of those born before 1975 shrinks through natural attrition (death),
there is a progressive decline in (printed paper readers) market size. In the
above example, the number of North Americans born before 1975 is seen to
shrink by 25-30%, from 212 to 155 million, between 1995 and 2020, a very
significant drop indeed.
Emerging, Second Environmental Movement
A new environmental movement, which is affecting market pulp as well as many
print paper end use sectors (especially unsolicited material such as catalogs),
has been gathering strength since the late 1990s. To understand its evolution
and outlook, we begin with a summary perspective of the major environmental
movement of the late 1980s and early 1990s, which we call here the first modern
environmental movement, then follow up with a review of key characteristics of
the current (second) environmental movement.
First (1990s) environmental movement. Two primary environmental issues
challenged the North American pulp and paper industry beginning in the early
1990’s, namely, the shift to ECF (elemental chlorine free) bleaching, and
increased wastepaper recycling.
The shift to ECF bleaching was necessitated by the need to reduce or eliminate
highly toxic dioxins/furans in the effluent discharged by chemical pulp mills. It
was adopted as best available technology (BAT), and mandated for all bleached
chemical pulp producing mills by the end of 2001 (replacing elemental chlorine
bleaching) by the U.S. Environmental Protection Agency and corresponding
federal and provincial bodies in Canada. For the time being, ECF bleaching will
remain the dominant chemical pulp bleaching option.
The 1990’s explosive growth in paper recycling on the other hand was, in our
(Temanex) opinion a “knee jerk” reaction in North America. The reason is that,
unlike many other paper producing regions, this region (also Scandinavia, Brazil,
Chile) has been blessed with high quality and relatively abundant forest resources.
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Unfortunately, a few highly publicized events around 1989-90, in particular concern
that the continent was running out of waste disposal sites, created a paper recycling
hype. These developments were fuelled by encouragement from well meaning, but
not always well informed, individuals and organizations, and drove wastepaper
recycling strongly in the 1990s, without due consideration of cost-benefit issues
and sensitivities. The result in many instances was financial ruin of many recycling
mills. BC companies had the forethought to avoid such mistakes, with investment
in only one major recycling operation (now part of Catalyst Paper), necessitated by
the Yellow Pages Publishers Association demand for a minimum 40% post-
consumer recycled fibre content in directory paper by the end of the 1990s.
Second (current) environmental movement. This is an increasingly important
and still emerging socio-economic development, which will affect pulp, paper and
print end use sector evolution right through to the end of the forecast horizon of
this project, 2026. We begin by comparing key differences with the first (1990s)
environmental movement, which will show the much more structured and better
organized evolution of the new movement. Specifically, the new movement began
modestly during the late 1990s, at about the time most of the environmental gains
of the first movement (ECF and paper recycling) had matured. The current
movement drivers take a much broader approach, focusing mainly on more
responsible resource utilization. Furthermore, non-governmental organizations
(NGO’s) are leading or driving developments. The approach followed by these is
to develop and implement structured, quantitative, and relatively complex
environmental impact systems, which are still evolving. In the process, the
quantitative assessment of resource utilization and environmental impact of
manufacturing practices has shifted from relatively arbitrary, single-parameter
target focus (e.g., achieving 55% paper recovery target by a given year, or 40%
minimum deinked fibre in directory paper) to multi-parameter models. These
models use ranking to produce an aggregate environmental position of pulp/paper
product and mill, based on weighting a number of key parameters, including origin
(forest) of wood chips used in pulp production; percentage of recycled fibre in the
paper; generation of greenhouse gases and effluent chemicals; and so on.
In addition, the strategy for compelling paper producers to accept these systems
has also shifted. It went from a relatively broad, but lacking specificity, focus in
the 1990s to more focused targeting of the paper or printed product distributor,
right to the final reader. This approach has produced substantial returns, with
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many large corporations getting on board and moving to a leading, or pro-active,
role. This new environmental sensitivity and responsibility trend gathered significant
momentum in 2005 and 2006, and it is expected to continue so in the future, with
environmental ranking and certification systems becoming increasingly more
sophisticated, and including all major aspects of environmental impact, namely
origin of wood fibre, recycled fibre content, paper manufacturing process impact
on the environment (amount and type of energy consumed, discharges, and
related), even impact on the community.
In conclusion, it is clear that the new environmental movement is upon us and
gathering momentum. It is better organized compared to the fragmented
approach of the early 1990s. Furthermore, it targets those along the value chain,
from wood to printed product, who are most sensitive to environmental issues
and the perception of environmental impact or friendliness of a given product. BC
producers have been sensitive to these emerging trends, but there are still some
issues, challenges, and perhaps opportunities to come in the future.
Shift to Higher Value Products
The ongoing shift to higher paper (especially mechanical printing grades) product
quality will continue, largely at the expense of newsprint, and perhaps because of
declining newsprint demand. First will be the shift to uncoated mechanical and
subsequently to coated grades. However, investment requirements for
conversion of a paper machine to coated paper production are very significant
($200-$300 million). The industry’s financial performance and the overall
investment climate in BC, must improve in order to make such large capital
outlays attractive (and capital for them available). In addition to maximizing the
product performance/cost ratio and long term industry viability, this shift
maximizes the value which is added to the wood raw material.
There are three related developments, which reduce the dependence on wood
raw material and will in the longer term reduce average specific energy demand
for paper manufacture. These developments can be summarized as:
• Reduced average paper basis weight, a gradual trend which has been
underway for decades in response to the need to reduce raw material and other
costs per unit area of paper. For the first time ever in 2006 more than 50% of
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North American newsprint was produced below 48.8 grams per square metre
(gsm) weight, and this trend is expected to continue.
• A second factor in the case of mechanical printing papers is reduction of the
low yield (percent of fibre extracted from a given weight of wood) and higher
cost (vs. TMP) kraft pulp in the paper raw material mix, also to reduce costs.
• Finally, increased utilization of mineral pigments for quality and cost-
effectiveness maximization is the third factor. As mineral pigments displace
wood fibre, electrical energy demand in paper production is expected to
decline. However, initially (the stage BC’s mechanical printing papers industry
has been over the last few years), electrical energy demand actually increases,
as mills find it necessary to increase specific energy application in TMP refining
to produce a stronger pulp. The reason is that mineral pigment addition
reduces paper strength, all other things being equal, therefore stronger
mechanical pulps (i.e. higher specific energy input) are required to ensure that
actual paper strength does not deteriorate to unacceptable (low) levels as a
result of incremental mineral pigment addition.
Figure 3-27, extracted from a recent Catalyst Paper annual report, summarizes
the rising electrical energy intensity (energy consumed per tonne of product) at
each of the company’s four BC mills. [Note: The data represent total, i.e. both
purchased and self-generated, energy consumption.]
Figure 3-27 Total (Purchased plus Self-generated) Electrical Energy Intensity at Catalyst Paper’s BC Mills
1.4
1.6
1.8
2.0
2.2
2.4
2.6
2.8
3.0
3.2
2002 2003 2004 2005
Ele
ctri
cal E
ner
gy
Inte
nsi
ty, M
Wh
/AD
T
Powell RiverPort AlberniElk FallsCrofton
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BC's major pulp and paper production and export products are still (bleached)
market kraft pulp, followed by commodity newsprint and bleached market CTMP.
However, whereas 10-12 years ago there were 14-15 newsprint machines in BC,
we are now down to 5-6 machines. Some machines were shut down, while
others were converted to uncoated and coated mechanical papers. [Note: In
most other paper grades, e.g. paperboard, sack kraft, tissue/hygiene products
and construction grades, BC is a relatively small player, mostly targeting the
regional market, and it is expected to remain so in the future. Therefore, the
discussion will focus on the three major production/export grades, bleached kraft,
CTMP and newsprint.]
The thrust of new, higher quality print grade development has been towards ever
higher brightness uncoated (and to a lesser extent coated) mechanical printing
papers, as summarized by the trend of maximum achievable brightness by
decade in Figure 3-28.
Figure 3-28 North American Uncoated Mechanical Maximum Brightness by Decade
Uncoated mechanical printing grades with a brightness of 75% or higher are
called superbrights. BC’s leading mechanical printing papers producer,
Catalyst Paper, is one of the leaders in highest brightness mechanical printing
papers development activity in North America (and the world). Apart from
improved profit margins, these grades, which can reach 83%+ brightness, have
been successful in penetrating the large (currently around 12.5 million MT/year)
55
60
65
70
75
80
85
90
1970's 1980's 1990's 2000's
Max
imum
Bri
ghtn
ess,
%
Future Potential?
Range (Low-High)
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market share growing. As far as the rest of the world is concerned, Latin
America and the Middle East are occasional but insignificant markets for BC kraft
paper and paperboard, but with few prospects for export growth as a result of:
• Scandinavian producers dominating Middle Eastern imports;
• Latin American producers (Brazil, as well as Chile in the future) increasing
regional self-sufficiency.
In summary there are few market drivers for BC producers to expand capacity of
these papers other than through machine optimization and/or the production of
niche market products (e.g. extensible kraft, white top linerboard, and other).
3.8.7 Other Paper and Paperboard Products
About 300,000 tonnes of "other" grades of paper are produced on the South
Coast. These are tissue, specialty hygiene products, recycled and virgin fibre
paperboard, and construction (roofing felt) grades. The tissue is sold entirely in
the domestic market, with most of this remaining in BC. Approximately 25% of
the other paper and paperboard manufactured in BC is exported to the Western
US, but the greatest volume is sold in BC and Alberta. Further expansions are
unlikely in the short to medium term. One possible exception is tissue, where
Western Canada’s one tissue mill (in New Westminster, BC) only partially fulfills
Western Canadian market needs.
3.8.8 Wood Pulp
The total pulp capacity in the year 2006 in BC stands at 8.3 million tonnes (down
from just over 9 million MT in 2002). Figure 3-34 gives the summary breakdown
by major pulp grade.
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Figure 3-34 BC Pulp Capacity Breakdown in 2006 (Total = 8.3 million MT)
SGW=Stone Groundwood; BKP = Bleached Kraft; UBK=Unbleached Kraft; CMP=Chemimechanical Pulp; RFI=Recycled Fibre
The majority of pulp production in BC is bleached softwood kraft (BKP), followed
by TMP/CTMP and unbleached kraft (UKP). Expectations for capacity changes
to the year 2026 are included in Table 3-16.
Table 3-16 Expected Changes in BC Pulp Capacity to 2026 (‘000 MT/yr)
2006 2007 2008 2009 2010 2011 2016 2021 2026 Chemical 4,998 5,078 5,078 5,078 5,078 4,658 3,182 3,182 3,182 Mechanical/ Chemimechanical
3,037 3,007 3,072 3,072 3,072 3,072 3,002 3,073 3,073
Secondary Fibre 270 270 270 270 270 270 270 270 270 Total 8,305 8,355 8,420 8,420 8,420 8,000 6,454 6,525 6,525
BC Market Pulp
BC is a major supplier of market pulp. In 2006 BC producers shipped a total of
4.8 million tonnes of market pulp. About 82% of this was bleached softwood kraft
pulp, in which BC shipments represent 18-20% of global supply. The remainder
was mostly market CTMP (both hardwood and softwood) with a 15% share, and
finally sulphite and unbleached kraft with 2% share of total BC shipments.
TMP/CTMP34%
CMP1%
UBK7%
BKP53%
RFI3%
Sulfite1%SGW
1%
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The main grades of pulp marketed are as follows:
• Bleached Softwood Kraft, BSKP, Northern (Interior) and Coastal Grades
(largest component).
• Bleached Chemi-thermomechanical (BCTMP) – softwood and hardwood.
• Bleached Sulphite (BSP) – one mill at Port Alice which has been shut down
twice in the last 4-5 years and restarted for the second time in May, 2006.
• Unbleached Kraft (UBK) – this is a very small component.
While these pulps are essentially sold all over the world, the geographical
position of market pulp mills within BC (Coast vs. Interior) does influence
shipments destination, as illustrated in Figure 3-35 for Canfor (Interior mill
production) and Catalyst Paper (Coastal mill production)
Figure 3-35 Canfor and Catalyst Paper Market Pulp Shipments Breakdown by Destination
Table 3-17 summarizes the estimated breakdown of market pulp shipments to
the various regions for BC, compared with Eastern Canadian and US producers.
0% 20% 40% 60% 80% 100%
Canfor
Catalyst
% Share By Destination
Americas Far East/Other Europe
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Table 3-17 Estimated Distribution of North American Market Pulp Shipments by Purchasing Region (Percent)
Destination Origin North
America Western Europe
Asia (incl. Japan)
Other Total
BC 25 25 45-50 5 100 Eastern Canada 40 10 10-15 18 100 USA 35 25 15-20 25 100
The short term outlook, starting in late 2006 and continuing through at least 2007
is very good for market pulps, especially BC’s dominant bleached softwood
grades with strong and rising shipments and (nominal dollar) prices – see Figure
3-36.
Figure 3-36 Weighted Average Northern Bleached Softwood Kraft Pulp Price Trend July, 2004 to July, 2007
As noted earlier, Asia Pacific is the region which will exhibit the largest increase
in net import requirements between now and 2026. With Southeast Asian needs
growing faster than those of Europe, the proportion of BC mill shipments to Asia
will continue to rise. Even though the Southeast Asian region has relatively
abundant plantation hardwood resources, the region has a very limited supply of
softwoods. [Note: Again, please note that by the second half of the forecast
horizon, i.e. the period 2016-2026, the vast Russian softwood resource is
expected to be exploited commercially to a significant degree, including
industriaisation and the production of bleached softwood kraft pulp.]
550
570
590
610
630
650
670
690
710
730
750
770
790
Jul
Oct
Jan
Ap
r
Jul
Oct
Jan
Ap
r
July
Oct
Jan
Ap
r
July
US
$/M
T
2004 2005 2006 2007
Linear Trendline
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Over the longer term, the combination of mostly negative factors which have
applied over the last few years will continue to influence the supply of BC market
pulp. The primary ones are relatively poor economics and incremental wood
availability, as well as old mills that require tens (and sometimes hundreds) of
millions of dollars for upgrading. Compounding these will be the adverse impact
of the BC Interior Mountain Pine Beetle infestation on wood chip supply, quality
and cost. These factors are expected to discourage new investment and
accelerate the shutdown of some low competitiveness mills. Further
compounding these problems, the long term pricing trend line for market pulps
indicates a decline – see earlier section on newsprint and bleached kraft pulp
long term price trends.
The greatest growth potential in future market pulp shipments from BC will be to
Asia and, to a lesser extent, Europe, while exports to the USA will slow down and
stagnate, as US paper/board production slows, while self-sufficiency and
wastepaper recovery and recycling rates continue to rise. The fast growing
Asian market will require increased quantities of imported fibre to support the
expansion of the regional paper and paperboard industry in keeping pace with
the high regional economic growth rates.
In summary, the competitive quality, which the exceptionally strong BC market
softwood kraft pulps possess, will continue to provide an edge in the market.
Although hardwood and deinked pulp growth rates have been higher, the
reinforcing properties of bleached softwood kraft place them in an excellent
position to capitalize on evolving industry and market trends. The major specific
trend is the need to compensate for potential strength losses as paper weight
decreases, and mineral pigment as well as recycled fibre usage (both of which
weaken paper) increases.
At the same time, margins for BC market pulp producers will continue to be
eroded due to increasing environmental protection and outdated equipment
maintenance costs, declining selling prices, and a strengthening Canadian dollar.
Bleached market CTMP, much like other market pulps, has been riding the
strong pulp market wave of 2006-07. For the time being, it appears as though
the strong market will continue, however, it should be noted that when the pulp
market softens CTMP grades suffer relatively larger demand declines than
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bleached kraft pulp grades, i.e. a greater negative impact on the bottom line. In previous studies similar to this one, our expectation was that one of the BC Interior market CTMP mills would integrate forward into uncoated or coated mechanical pulp production. With the dramatic, and unexpectedly large, decline in North American newsprint demand of the last 6-7 years, and the potential for peaking and subsequent demand decline of higher value mechanical printing papers in the longer term (see conceptual Figure 3-26 in this section of the study), this scenario has become increasingly unlikely to occur.
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utilized as the major input parameter, in actual practice a stochastic uncertainty
carries greater weight, since when a kraft mill shuts down other regional mills
step in and fill in some of the orders.
Tables 3-22 and 3-23 summarize the 2006-2026 forecast most likely (base) case,
low, and high scenarios.
Table 3-22 BC Pulp Production Forecast Scenarios
Low Base Case High2,002 2,068 2,068 2,0682,006 2,485 2,485 2,4852,007 2,532 2,584 2,6362,008 2,641 2,695 2,7492,009 2,489 2,566 2,6212,010 2,411 2,512 2,5662,011 2,381 2,506 2,5602,016 2,452 2,637 2,7692,021 2,415 2,654 2,8392,026 2,363 2,655 2,894
Low Base Case High2,002 5,036 5,036 5,0362,006 4,726 4,726 4,7262,007 4,742 4,839 4,9362,008 4,654 4,749 4,8442,009 4,658 4,802 4,9122,010 4,461 4,646 4,7542,011 3,985 4,195 4,2932,016 2,972 3,196 3,3562,021 2,908 3,196 3,4202,026 2,844 3,196 3,484
Mechanical Pulp Production, ‘000 tonnes/yr
Chemical Pulp Production, ‘000 tonnes/yr
Scenario
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Table 3-23 BC Paper/Board Production Forecast Scenarios
Low Base Case High2,002 2,127 2,127 2,1272,006 2,100 2,100 2,1002,007 2,035 2,076 2,1182,008 2,040 2,082 2,1242,009 1,918 1,977 2,0372,010 1,855 1,932 1,9902,011 1,806 1,901 1,9582,016 1,991 2,141 2,2482,021 1,948 2,141 2,2912,026 1,908 2,143 2,336
Low Base Case High2,002 1,009 1,009 1,0092,006 929 929 9292,007 901 919 9372,008 893 911 9292,009 892 920 9482,010 858 894 9202,011 867 912 9402,016 315 339 3562,021 309 339 3632,026 302 339 370
Newsprint & Mechanical Printing Papers
Other Papers Production, ‘000 tonnes/yr
Scenario
Scenario
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to make an oral presentation. That did not mean,
however, that they would not be prevented from making a
written submission to the Commission on these matters.
THE CHAIRPERSON: Thank you, Mr. Fulton.
MR. WEBB: Good morning. Mr. Fussell is here today on
behalf of B.C. Hydro to give the same presentation that
was given in Victoria and in Prince George. This has
already been entered as Exhibit 4-3. Mr. Luzstig is not
here. Urgent matters required him to return to
Vancouver yesterday and he sends his apologies to the
Commission that he could not be here. Mr. Fussell will
be giving the full presentation, and has already been
sworn.
THE COURT: Thank you.
COLIN FUSSELL, Resumed:
MR. FULTON: Mr. Bemister has indicated to me that there
are copies of the presentation at the back of the room,
so if people do not have them, he'll hand them out at
this point.
EVIDENCE IN CHIEF BY MR. WEBB:
MR. WEBB: Q: Mr. Fussell, if you would please introduce
yourself and state your position at B.C. Hydro.
MR. FUSSELL: A: My name is Colin Fussell. I work in the
rates department of B.C. Hydro.
MR. WEBB: Q: Thank you.
MR. FUSSELL: A: Good morning. I'm going to first go
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through the Heritage Contract that B.C. Hydro is
proposing and then proceed with the stepped rates.
The Heritage Contract locks in the value of
existing low cost generation assets for an extended
period of time. The initial period set out in the
contract is ten years. The energy plan, action plan
that sort of set out the Heritage Contract is Policy
Action Number 1 and it requires a legislated Heritage
Contract to preserve the benefits of B.C. Hydro's
existing generation. Policy Action Number 2 says B.C.
Hydro ratepayers will continue to benefit from
electricity trade.
The Terms of Reference for the Heritage
Contract Inquiry further defined the key assumptions.
Based on these B.C. Hydro defined its objectives for the
Heritage Contract Proposal.
The Heritage Resources are set out as part of
the Terms of Reference. They are set out in Schedule A.
They include the Peace and Columbia system, coastal
system, the Burrard thermal, Rupert and Fort Nelson
thermal plants, and they also include some obligations
that are required under the -- existing obligations that
are required for B.C. Hydro to continue with. And these
include such things as this obligation to provide energy
to City Seattle Light in lieu of raising the Ross Dam.
The Heritage Beneficiaries include all
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customers, all of B.C. Hydro's customers as set out in
Schedule B. They also include customers of Aquila, and
they also include New Westminster. When I say "Aquila",
Aquila would get the benefits through their power
purchases from B.C. Hydro.
The energy quantity used to define the
Heritage Contract as required in the Terms of Reference
is average water conditions.
The annual trade income over $200 million
will flow to the government through B.C. Hydro. So all
the benefit under $200 million goes to the customers.
Secure reliable supply. The Heritage
Contract will allow B.C. Hydro to provide secure and
reliable electricity for all current and future. B.C.
Hydro ratepayers. In effect, the Heritage Contract
should not cause a degradation in system reliability.
Low electricity rates. In effect it should
provide for B.C. Hydro to provide the capability of the
Heritage Resources on the basis of their embedded cost.
Embedded cost is basically the same basis on which we
currently set revenue requirements for B.C. Hydro. The
contract should allow B.C. Hydro to maximize the value
of generation capability of the resources within B.C.
Hydro's control and allow B.C. Hydro to minimize the
cost of acquiring resources for ratepayers. Over all,
system optimization today and in the future.
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When B.C. Hydro put together the contact, I
mean, the main focus that we had in sort of designing
the contract was that overall system optimization, sort
of existing system optimization and future system
optimization should be preserved. Overall system
optimization will allow the continuing service to
domestic customers in the least cost. From an operating
perspective, optimization allows the coordination of
Heritage Resources, IPP purchases and market purchases
so that the least opportunity cost supplies are used
first.
Example of when we speak of least cost
opportunity cost, for example if running fuel through
Burrard is more expensive than running natural gas
through ICP, ICP should be used first before Burrard.
It also would allow B.C. Hydro, when you are thinking
from an operations perspective and an optimization
operations perspective, we would look at the value of
water and see whether it was more useful to use that
water to generate today versus storing it and using it
tomorrow. If we think the opportunity cost is higher
in the future than it is today, then we would typically
store the water.
And from a planning and acquisition
perspective, in looking at the future purchases that
B.C. Hydro would undertake to provide service to the
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domestic customers, it's clearly going to look at how
those purchases fit in with the existing resources to
make sure that when we purchase that resource and add it
to the existing base of the Heritage Resources that the
overall result is the least cost.
The regulatory structure from which the
Heritage Contract is being constructed, it's basically
being set out as an agreement between B.C. Hydro
generation and distribution lines of business. The
Heritage Beneficiaries in aggregate receive the benefit
of the Heritage Contract through B.C. Hydro's overall
revenue requirements. I'll just touch on that a little
bit later. The Heritage Beneficiaries receive the full
benefit of the generation of the Heritage Resources and
the first call on all available resource capacity.
Effectively, the domestic customer will have first call
on the total flexibility of the system in serving the
domestic load.
The Heritage Payment Obligation is the actual
cost to deliver Heritage Electricity required to meet
the needs of domestic customers. In effect, when B.C.
Hydro goes for a revenue requirement, B.C. Hydro would
be putting forward what it thinks the required costs to
maintain and operate the Heritage Resources and that
figure would be used in the revenue requirement.
Neither the Heritage Reference Price that's put forward
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in the material that's being presented by B.C. Hydro,
the $25.30 per megawatt hour, nor the average energy,
the 49,000 gWh, feed into the Heritage Payment
Obligation under B.C. Hydro's proposal. The reference
cost information has been included in the proposal and a
forecast will be provided in B.C. Hydro's 2004 Revenue
Requirement filing.
So when B.C. Hydro goes forward for a Revenue
Requirement next year, assuming B.C. Hydro's proposal is
accepted, B.C. Hydro would be looking at the actual cost
of providing energy from the Heritage Resources.
Neither the 49,000 nor the $25.30 per mWh would be used
in that application.
The Heritage Deferral Account, to account for
differences between the actual Heritage Obligation and
the forecast set at revenue requirements, helps to
stabilize rates. What B.C. Hydro is proposing is a
deferral account. In effect in the Revenue Requirement
we would put forward what we think is the appropriate
costs associated with the Heritage Resources. A
deferral account would be set up to measure the
difference between that forecasted cost and the actual
cost that would be determined after the fact. And those
differences would be carried forward, and depending,
they could a credit or a debit with respect to the cost
that would be carried forward in the future revenue
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requirement hearings.
All trade income up to $200 million per year
will accrue to ratepayers. Ratepayers are protected
against negative trade outcome. In effect if trade, for
some reason there is a negative associated with trade
activities, that doesn't affect future rates. The
customers are protected against any negative trade
outcome.
Under the proposed definition of trade
income, it's unlikely the amount will exceed $200
million. Within that definition B.C. Hydro, any surplus
water within the system is not included in the
electricity trade income. That would be transferred to
Powerex to make a sale at a market price, so the direct
benefit of that goes back to the ratepayer. So you
won't in effect see where in the past B.C. Hydro has
defined trade as effectively you were bringing trade
income based on zero cost of providing the surplus
water. That is no longer the situation, at least under
B.C. Hydro's proposal.
So in summary, B.C. Hydro's proposal is a
Heritage Contract, a Heritage Deferral Account that will
come into play during the Revenue Requirement Hearing,
and a trade income allocation. And the trade income
allocation, at least the definition of trade income is
such that B.C. Hydro believes that in almost all
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situations the full benefit of trade will flow back to
the ratepayer.
The Heritage Contract, itself, includes an
energy supply obligation of 49,000 gWh per year. It
provides bundled service of energy, capacity and
ancillary services. In effect the Heritage Contract
allows the full flexibility of the system to service
domestic customers, and the full benefit of the Heritage
Resources goes to the ratepayer.
The Heritage Deferral Account will mitigate
the volatility of actual costs to supply of Heritage
Electricity, and of course the big volatility that you
see within the Hydro system is the availability of
water, and that can swing costs plus or minus $300
million per year.
Trade income, the definition clearly
separates trade activity from the benefit of water
conditions and allocates all trade income from zero to
$200 million to the ratepayer.
B.C. Hydro believes its proposal meets the
objectives of the Energy Plan, it provides for secure
and reliable supply. Low Rates. It provides low rates
by passing on the full benefit of the Heritage Resources
and embedded costs, and by allowing the full
optimization of all B.C. Hydro's resources, and that
includes the existing Heritage Resources as well as
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future purchases.
I'll just quickly go through the B.C. Hydro
Stepped Rate Proposal which is, the Stepped Rate
Proposal is defined within the Energy Plan within Policy
Action Number 14 which says:
"Under new rate structures large electricity
consumers will be able to chose a supplier
other than the local distributor."
In effect the stepped rate introduces retail access for
large electricity users.
Policy Action 21:
"The new structure will provide better price
signals to large electricity consumers for
conservation and energy efficiency."
The Stepped Rate example that is put forward
on the next page, on page 15, you can see a Tier 2 rate
at the higher rate, and within the Energy Policy, the
Tier 2 rate is to represent the cost of new supply. The
other important thing is you have a historic consumption
level, and in effect this would be the average
consumption a customer has used over the last three
years, and that's referred to as the customer baseline
load or CBL.
And then you have Tier 1 rate. I'll just
touch on those quickly. The Stepped Rate in B.C.
Hydro's understanding of the Energy Policy is mandatory.
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In other words, the group of customers that the rate is
to apply to won't have an option as to whether they are
billed on it. They will be billed on it. It is bill
neutral and bill neutrality means that if the customer's
consumption doesn't change, in other words he consumes
at his customer baseline load, his bill will not change.
And it's margin neutral. Margin neutrality
means that B.C. Hydro's income will not change if a
large customer changes his consumption. In effect, if a
customer were to reduce, a large customer were to reduce
consumption in reaction to the rate, there would be not
cost shifts to other customers.
But first I'd like to touch on the Tier 2
rate, the Tier 1 rate, the Tier 1/Tier 2 split, retail
access, and the treatment associated with increased
productive capacity and for reduced production capacity.
Starting with the Tier 2 rate, the Energy
Policy requires that the Tier 2 rate be equal to the
cost of new supply. B.C. Hydro buys and sells energy
in the export market to meet domestic load on an ongoing
basis, on a continual basis. So in looking at this B.C.
Hydro believes that the appropriate measure of Tier 2 is
the cost of market purchases or market sales. And the
reason B.C. Hydro has chosen Tier 2 is the fact that it
will manage any changes within -- as a result of
introducing this rate, you know, decreased consumption
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would be handled through market transactions. The
changes will be managed through that.
As a result of choosing a Tier 2 rate tied to
market changes, the result will be that there will be
the income, B.C. Hydro income neutrality principle, at
least our understanding of a requirement for income
neutrality, will be met. In effect adopting this cost
of new supply as the appropriate measure to use with
Tier 2 will minimize cost shifts to other customers.
The Tier 1 rate -- first of all I just say
the Tier 2/Tier split, what we are proposing is a 90/10
split. Again by adopting a 90 cent split it's a
relatively conservative split, but it will, at least for
the introduction of the rate, allow B.C. Hydro to
introduce a relatively simply rate with very little
administrative rules. It will also -- it's probably
reasonable for encouraging large customers to undertake
any DSM or conservation investment. It's an acceptable
level, in our view, to the extent that it minimizes the
potential to result in cost shifts to other customers.
Now, having chosen the Tier 2 rate, and the
Tier 1/Tier 2 split -- I'm sorry. Yeah, I think that's
right. Having chosen the Tier 2 rate, the Tier 1/Tier 2
split, the Tier 1 rate just falls out arithmetically and
it's set to ensure that the existing customer will not
see any bill change at his CBL consumption level. And
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typically the numbers that sort of are put forward
within the application is that the Tier 2 would be in
the order of 6 cents, the Tier 1 would be in the order
of 2.2 cents. The current rate is the average rate for
1821 or the transmission customers today is
approximately 2.6 cents.
With respect to retail access, B.C. Hydro is
recommending that retail access not be implemented until
the appropriate ancillary service rates are determined
after BCTC assumes responsibility for the wholesale
transmission service.
BCTC, of course, is the British Columbia
transmission company. It is a new Crown corporation
that has been set up following the Energy Plan, to take
over the operations of the transmission system.
Currently B.C. Hydro operates a transmission system
under what is referred to as the wholesale transmission
service tariff. When BCTC takes over, it will be filing
a rate application and it will be making changes to that
tariff. As a result, B.C. Hydro is suggesting that
retail access be postponed until BCTC takes over the
tariff and makes whatever changes it sees necessary.
Otherwise to introduce retail access for transmission at
this time would probably create some uncertainty because
nobody would be sure, you know, a year or so down the
road, what tariff provisions they may be operating
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under.
I'll just quickly look at the rate treatment
for new investment. The treatment of new investment
isn't part of the Energy Plan, but I think it's very
important. If you look at that rate, you know, a 6 cent
rate for Tier 2 and a 2.2 cent rate for Tier 1 and you
look at new investment in an existing plant, on its own
that rate would clearly discourage additional investment
compared to where you are today, because the current
rate is 2.6 and a Tier 2 rate is 6 cents, which is
clearly, I think in our view, discourages investment.
So what we're suggesting within the proposal
is that new plants, if a new plant came forward, put
some investment in place, that this rate for the new
plant, at least during its teething period would be the
sort of the average rate paid by all customers at their
CBL level. Currently that's approximately 2.6 cents.
So that average rate would apply until they've gone
through the teething period and they are on a basis that
we could establish a CBL. After we had enough
information to establish a CBL, the new plant would then
be put on the stepped rate.
With respect to an existing plant where
people are adding new facilities and increasing their
consumption, what we are suggesting is that if the
consumption were to increase more than 10 percent over
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its CBL level, the actual CBL will be adjusted upward to
include the increased consumption. The result of that
is that any increased consumption as a result of new
productive capacity put into an existing plant would be
billed at the average rate.
So you have sort of -- at least beyond the 10
percent CBL level for an existing plant and a new plant,
they will both be treated, new investment at both the
new and existing plant would be treated on the same
basis.
With respect to treatment for reduced
production, now, if reduced production at an existing
plant results in more than a 10 percent decrease in
consumption, then the CBL will be adjusted downward to
reflect that reduced consumption. That's as a result of
a reduced consumption, you know, just basically where a
plant has taken production out of service.
However the reduced consumption at a plant as
a result of conservation investment by the customer, the
CBL will not be adjusted. The affect is that the
customer would receive the full benefit of any DSM
investment at the Tier 2 rate or the 6 cents in my
example
And that completes my presentation, thank
you.
MR. WEBB: Thank you, Mr. Fussell. Mr. Fussell is
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particularly for people who are not used to the system,
but I'm hoping that that will be helpful for those who
follow Ms. Parsons in terms of answering questions -- or
asking questions.
THE CHAIRPERSON: Thank you.
CROSS-EXAMINATION BY MR. SECORD:
MR. SECORD: Q: Gilbert Secord is my name. I live at
Peachland, British Columbia. I am a member of, a
director of the Kootenay Okanagan Electric Consumers
Association. I have quite a few questions I'd like to
direct -- I might be out of order. If I am, please say
so.
On page 11 of your summary in the Energy
Plan, I'm directing this to B.C. Hydro, you say the
Heritage Contract energy supply obligation of 49,000
gigawatt hours per year, is that an amount of energy
that is now being used by the B.C. consumers?
MR. FUSSELL: A: No, B.C. Hydro's load is a little bit in
excess of 49,000. It's approximately, I think, the last
time I think it was approximately 52,000 gWh.
MR. SECORD: Q: And what are they capable of supplying?
B.C. Hydro's own facilities, what are they capable of
supplying?
MR. FUSSELL: A: I'm not sure exactly. When you say
"capable of supplying", I mean, if we were to sort of
run Burrard thermal flat out under average water
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conditions, it would be something in the order of 50,000
gWh.
MR. SECORD: Q: Okay, what is B.C. Hydro doing regarding
planning for additional generation? Now, I may be --
I've read this book, I was also a part of Dr. Jaccard's
British Columbia Task Force on Electricity Market Reform
and I have a copy here of his final report, and what he
has done here, what he has said here which was not --
which was not sanctioned by any of the stakeholders that
attended these hearings, and there was some 17
stakeholders, none of them endorsed this report. Now,
our provincial government has come along and recycled
this report into, electrically, into this Energy Report.
And what that Energy Report is telling me is that B.C.
Hydro cannot develop any more generation facilities.
MR. FUSSELL: A: That's generally what's said in the
Energy Policy, yes.
MR. SECORD: Q: So as I see it, within five years we, in
British Columbia, are going to be in the same position
as California was two years ago unless we are prepared
to pay the price, the market price whatever that happens
to be at the time.
MR. FUSSELL: A: I don't think that follows. I mean what
the Energy Plan says is that B.C. Hydro when it needs
additional resources will have to buy those resources
from private developers. And so effectively you would
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have the revenue requirement associated with the
Heritage Resources which are based on the same -- are
set the same as you have today, and added to that you
would have the additional cost of new resources, and
depending on how those costs are allocated through
rates, if they were all averaged together for example,
the rate will go up, but it certainly isn't going to
approach anything like you've seen in California where
you had retail access and the rates were set, all the
rates and all the costs associated with generation were
set at a market price. It will be quite different from
that.
MR. SECORD: Q: How can you guarantee that?
MR. FUSSELL: A: Well, that's what is set out in the
Energy Plan for at least the next ten years. I can't do
any more --
MR. SECORD: Q: Yes, it is, but the other question I ask
you, is you have 49,000 gigawatt hours that you are
going to -- will be part of the Heritage Contract, five
years from now if that increases to 59,000 gigawatt
hours, we are going to be on the open market buying that
extra ten gigawatts unless B.C. Hydro starts developing
some more of their own facility. B.C. Hydro is owned by
the people of British Columbia and most definitely
should be planning their additional generation
requirements into the future, and not be looking to rely
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on another source of energy.
MR. FUSSELL: A: Well, again, I can't really comment on
that. All I can comment on is -- I mean, my only
comment is that that's what is set out in the Energy
plan is that B.C. Hydro is not to develop its own
resources. It is to buy those resources from private
developers.
MR. SECORD: Q: Okay, that's generation of electricity.
MR. FUSSELL: A: That's for additional generation
resources.
MR. SECORD: Q: Well, let's move onto transmission then.
MR. FUSSELL: A: Yes.
MR. SECORD: Q: Who is going to be responsible for
installing any new transmission that is required?
MR. FUSSELL: A: That, the actual planning of the
transmission facilities will be undertaken by the B.C.
Transmission Corporation.
MR. SECORD: Q: And they will also be required to provide
access to the IPPs, the Independent Power Producers.
MR. FUSSELL: A: The IPPs already have access.
MR. SECORD: Q: Okay, but they are being -- they are being
asked to build new generation. They have said that they
will build new generation.
MR. FUSSELL: A: I guess. I don't know. I mean that
would seem to be a reasonable assumption given the
energy plan.
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MR. SECORD: Q: During the election they were prepared to
put up 2 billion -- or a billion dollars worth of
construction money for new generation. That was my
understanding and I stand corrected on that.
But if that is the case, they are going to
want to access to put that energy into the system, and
if they are paying 10 cents a kilowatt in California,
you can rest assured we are going to be paying 10 cents
a kilowatt for that energy here which is over and above
our requirements of 49,000 gigawatt hours per year.
MR. FUSSELL: A: I think that would depend on the basis
that B.C. Hydro were to buy that energy. I mean
effectively if B.C. Hydro went out for an RFP, for a
request for proposals from various IPPs in order to buy
some additional energy, they would become -- I mean we
would be basically buying, I presume, from the least
cost proposals, and certainly at the moment we wouldn't
be expecting that cost to be in the order of ten cents.
It's probably more like in the order of 6 and a half
cents, 7 cents, something in that order.
MR. SECORD: Q: In the past, the rates in the Pacific
Northwest have been set at COB, which is the California
Oregon Border, and that's where California got into a
big problem.
MR. FUSSELL: A: When you say "rates" certainly B.C.
Hydro's rates haven't been set based on COB.
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MR. SECORD: Q: No, but if you are buying electricity on
the open market, those rates are set at COB.
MR. FUSSELL: A: COB is a trading centre for the Pacific
Northwest.
MR. SECORD: Q: Yes.
MR. FUSSELL: A: For the wholesale electricity market, I
agree.
MR. SECORD: Q: And if we run out of power and we don't
have any, we have to got to COB to buy it, we are going
to be paying COB's price, if that's ten cents, twenty
cents, whatever it is for a kilowatt hour.
MR. FUSSELL: A: And at the moment the average price over
the last year was probably about 5 cents at COB.
MR. SECORD: Q: Okay.
MR. FUSSELL: A: I mean, the market varies, has varied in
the past quite dramatically, I agree. You know, two
years ago when you were in California the costs were up
in the order of 15, you know, to 30 cents a kilowatt
hour.
MR. SECORD: Q: Well, all I can say at this point in time
is from our organization's perspective, is that we see
British Columbia in the same position as California was
two years ago within five years and maybe less than
that.
MR. FUSSELL: A: Well, certainly there's nothing in the
Energy Plan that suggests that there's going to be
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general retail access and that prices are going to move
towards market prices. There's nothing in that that I
see suggests that.
MR. SECORD: Q: Yes, but if you own a generation plant,
you are going to sell that energy to the place where you
can get the best price for energy, are you not? I'm not
talking about you as an individual --
MR. FUSSELL: A: As an IPP.
MR. SECORD: Q: Yes.
MR. FUSSELL: A: If I were an IPP. Certainly I'll sell it
to the best price but if I come forward and under
contract to B.C. Hydro that commits the output of that
plant to B.C. Hydro at a fixed price, over the period of
the contract, then they are not free to sell it at the
highest market price. They have to sell it to B.C.
Hydro under the terms of the contract.
And for example, our recent RFPs with respect
to, I think, customer based generation were in the order
of 5.5 cents to 6 cents and those generators are now
under obligation to provide B.C. Hydro the full output
of those plants at that price, in spite of the fact that
maybe a year from now the COB price may be ten, eleven,
twelve cents.
MR. SECORD: Q: How many contracts do you have with IPPs
to provide you with a fixed rate for power?
MR. FUSSELL: A: All of them that we purchase are on a
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fixed rate basis.
MR. SECORD: Q: For how long?
MR. FUSSELL: A: Somewhere between ten and twenty years,
I'm not sure of the exact -- that familiar with all the
contracts but they vary in that term.
MR. SECORD: Q: Okay. For this part of the questioning I
haven't got anything more to say other than the fact
that what I've said. I believe the people of British
Columbia should wake up to the fact that what's happened
in California can happen here. And I'll ask some more
questions of the Commission later. Thank you.
MR. FUSSELL: A: Thank you.
THE CHAIRPERSON: Mr. Secord, I noted that you haven't
made a request of Commission counsel to make a
presentation.
MR. SECORD: No, I haven't.
THE CHAIRPERSON: Would you like that opportunity?
MR. SECORD: I don't have a prepared presentation, I could
only talk off the top of my head, but it would be about
these two items here, one is the Jaccard report and the
other is the Energy Plan.
THE CHAIRPERSON: Well, I'd like to provide that
opportunity to you if you wish to take it.
Alternatively if you would prefer, you can make
submissions to the panel in the form of an argument if
you wish at the end of the proceedings. So whatever
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your preference is.
MR. SECORD: Okay, well, I'll -- I definitely want to say
something about this. I know I'm talking to the wrong
people. The people that made this -- the people that
made these decisions are in Victoria and unfortunately I
don't believe they understand what they have done.
However I'm going to speak to it anyways, and I believe
that the people here should understand.
THE CHAIRPERSON: So I'll leave my invitation with you,
and you may -- you can come back to the mike at any
point and let me know what your preference is.
MR. SECORD: Okay.
THE CHAIRPERSON: Thank you.
MR. FULTON: Mr. Secord had mentioned that that was his
questions for Mr. Fussell, but he did have questions for
the Commission and I just wanted the floor to know that
the Commission doesn't answer questions in these
proceedings. It's the proponent's application and the
proponent who is to answer questions or intervenors
making presentations.
THE CHAIRPERSON: Thank you.
MR. FULTON: Are there any other questions from the floor
for Mr. Fussell?
There are no further questions of Mr.
Fussell, Mr. Chairman.
THE CHAIRPERSON: You may be excused, thank you.
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(WITNESS ASIDE)
MR. FULTON: The next presentation, Mr. Chairman, will be
from Highland Valley Copper, and the speaker will be Mr.
Dal Scott, who is the superintendent of mill engineering
for Highland Valley Copper. Mr. Scott has a
presentation and I will distribute that now. I've
provided the Hearing Officer with a copy for marking as
an exhibit. I have copies for the panel, and I will
pass back copies to the rest of the room.
And there are a limited number of coloured
copies, so people will need to sort out who has the
coloured copies and who has the black and white.
THE CHAIRPERSON: Sounds like a good responsibility for
the Hearing Officer.
MR. FULTON: Right. Mr. Scott, do you wish to be sworn or
not?
MR. SCOTT: I don't know what's customary in one of these
proceedings.
MR. FULTON: Well, we do prefer people to be sworn if they
wish so --
MR. SCOTT: Okay, I'll be sworn.
DAL SCOTT, Affirmed:
MR. FULTON: Mr. Scott, you are the superintendent of mill
engineering of Highland Valley Copper.
MR. SCOTT: A: That is correct.
MR. FULTON: And as I understand it, Highland Valley Copper
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is part of the Joint Industry Electricity Steering
Committee?
MR. SCOTT: A: That's right.
MR. FULTON: You are here today though speaking on behalf
of Highland Valley.
MR. SCOTT: A: That's right.
MR. FULTON: You have a presentation that you wish to make
to the Commission?
MR. SCOTT: A: Yes, I do.
MR. FULTON: Would you proceed with that presentation then
please.
MR. SCOTT: A: Thank you very much.
EVIDENCE IN CHIEF:
MR. SCOTT: A: I'd like to thank the Commission for the
opportunity to speak today. Highland Valley is in the
Thompson Okanagan Kootenay part of the province so we
thought that it would be appropriate to make a
presentation today to describe our operation, to show
that we are large user of electricity and to indicate
that we support the position of the Joint Industry
Steering Committee as will be presented in the hearings
in Vancouver.
So that I would hope that at the end of the
presentation today the Commission and the people that
are here today have a little bit better understanding of
who Highland Valley Copper is and how electricity prices
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influence us. And that we have been a consumer, or a
conserver of electricity over the past 30 years and have
reduced our electrical consumption accordingly.
I'd like to talk to the slides as shown on
what we've given to you. We produced them yesterday
afternoon. We had one cartridge in my office so we did
as many colour copies as we could, and if you have a
colour copy, fine. But unfortunately we didn't have any
more cartridges.
Highland Valley Copper is a large open-pit
mining operation located near Kamloops in the south
central British Columbia. We are B.C. Hydro's fourth
largest industrial customer on Rate Schedule 1821. We
are the largest copper mine in Canada. We have 946
people that work directly for the operation. They live
in Kamloops, Logan Lake, Ashcroft, Cache Creek and
Merritt.
We've had total revenues last year of 360
million. This is lower than normal because copper
prices in the last few years have, on real terms, been
lower than the price copper was back in 1929 or the '30s
and the last major depression.
The current mine life is to mid-2009 with a
possible extension to the end of 2012, but the extension
isn't viable at current copper prices.
The next line shows the economic impact of
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our operation. We spend $260 million at our operation,
and it includes a $76 million payroll to people that
live in Kamloops, Logan Lake, Ashcroft, and Merritt. We
paid last year about $50 million taxes to three levels
of government. This will drop in the future. The taxes
to the provincial government will drop maybe $10 million
this year, and we are very appreciative of that.
Our capital expenditures last year were about
$20 million and we spent $20 million hauling our
concentrate to Ashcroft by truck and by train to
Vancouver to the Vancouver Wharves to our terminal where
we store the concentrate and load it on ships.
One of our capital expenditures last year,
our contract with Vancouver Wharves, if they have to
improve their facilities to meet new environmental
standards, we have to pay those costs and we've -- last
year and this year, were spending $7.2 million in the
City of Vancouver to upgrade Vancouver Wharves
concentrate handling facilities so the dust can't escape
from their facilities.
The total of those costs here in B.C. are
$300 million and the overall economic impact on the
province of a 2 and a half multiplier is about three-
quarters of a billion dollars a year.
On the next line we indicate that electricity
cost is 14 percent of our operating costs. Last year we
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spent $37 million on electricity including the
provincial sales tax of 7 and a half percent. That's
charged to industrial customers that residential
customers don't see.
The next slide shows our energy consumption
and production during the last six years, and this slide
is to show that our overall demand in energy consumption
has gone down since 1997 and our production has gone up
significantly.
On the column on demand at peak at 2000 at
128 MVA and in 2002 it has fallen to 124.3. That may be
partly due to the weather in that we have large overland
conveyor systems that have one inch thick conveyors that
when it's 40 below it uses a lot of horsepower to bend
those conveyors around the pulleys, and we've had two
warm winters in the last two years. So part of the
reason the demand has come down on an average for the
whole year was we had two relatively mild winters in the
last two years.
In energy consumption, we peaked at 162
gigawatt hours a year. That's 162 million kilowatt
hours. But our throughput has increased from 1996 from
116,000 tonnes a day up to 136,600 so that our
production has gone up during those years.
We have also indicated on the right-hand side
of the page that we were down for four months in 1999.
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Our place became uneconomic. We worked with the job
Protection Commission and it took four months for the
people who worked at our mine to agree that they wanted
to agree to the terms of the Job Protection Commission
before we started up again.
In 2000 and 2001 we had our two older mill
lines down where we replaced the mills, and the
electrical equipment that drives the mills, the MCC
equipment, because they were 30 years old and we wanted
reliable equipment to the end of mine life, so we
disassembled the mills and replaced them with new parts,
and we replaced all our electrical motor control
equipment at the same time. So when Colin, as he got
into the detail in his spiel today on CBLs, we would
expect that the time when these mills were done were
anomalies that wouldn't be adjusted as the CBL is
determined for industrial customers per their proposal
for B.C. Hydro.
The next slide shows that our productivity
has increased with time. As the price of copper has
gone down, we've worked hard to remain competitive and
we've been able to do so at current electricity prices.
When the provincial government first started
looking with their electrical policy research committee,
they were talking about doubling the price of power here
in B.C. and were that to happen, we wouldn't be here,
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and the three-quarters of a billion dollars worth of
economic activity that flows to this province through
B.C. Hydro wouldn't be here today either.
The next slide shows a comparison of mill
throughput, mill availability. You can see with time
partly because we put in new mills in the A and B line,
the up time on our mills, or the availability of our
mills, has increased with time from 91.5 up to 94.22
percent. We are running our facilities longer and more
efficiently, partly because the mills are working more
of the time, and our kilowatt hour per tonne
consumption, our energy intensity has dropped during
this period of time from 22 and a half to 19.66 to
19.04, the bottom line on this chart.
Our electrical load factor in 2002 was 87.3
percent. We are a high load factor customer. We are a
good customer for B.C. Hydro. The wires, the
transformers and the generators that feed us are running
87 percent of the time compared to 65 percent for other
rate classes.
The next slide shows power consumption
intensity. In 1973 when Lornex was built, one of our
larger predecessor operations, we used power, at the
bottom of that chart, of 28.82 kilowatt hours per tonne.
By 2000 it dropped to 19.28 and by 2002 it dropped
further to 19.03. It's an indication that our mine has
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become considerably more efficient at using the
electricity over time through energy conservation
projects, the first of which was done in 1973, the year
after Lornex Mining Corporation started business in the
Highland Valley.
We've been mining copper, or our predecessors
who are members of the partnership started mining in
Highland Valley in 1962 which was the year that B.C.
Hydro was formed. So we've been in business producing
wealth for the province of British Columbia as long as
B.C. Hydro has.
You'll note that, the third line down in
"Crushers and Conveyors" the energy intensity in that
area increased with time. We spent $150 million
installing an in pit crushing and conveying system that
pulls the ore out of the valley pit to our mills and as
the pit got deeper and as time went on we used more
energy in the crushing and conveying system. In doing
so we were able to cut the number of trucks we used in
half and cut our diesel consumption in half from about
32 million litres a year down to the order of 16 million
litres a year.
This figure doesn't work out, or we can't
claim this under the Kyoto Protocol because we did this
two years earlier than the protocol kicked in. But I'm
just trying to indicate that as a large industrial
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customer, energy conservation and the use of energy is
very important to us. If we hadn't done the steps that
we've done in the past, we wouldn't be here today.
The next line just shows an overall view
which doesn't really show up very good here. About two
years ago or in 2001 we looped our reclaimed water line
from our tailings pond back to our mill where we
installed 2.6 kilometres of 42-inch pipe. The next
slide shows a picture of the pipe being installed. It's
a large pipeline that's a similar size to Westcoast
Transmission or gas lines out on the flat lands use.
The pipe you see there is pipe that was left over from a
gas pipeline project in Epsco's yard so we were able to
buy it a good price.
The project cost 2.9 million to install,
there was 2.6 kilometres of pipe. It was made possible
by a $.9 million Power Smart incentive grant by B.C.
Hydro. It was a good project. It was installed on
schedule or ahead of schedule, within budget. The head
losses were slightly better than projected.
The projected power savings in that area were
20 gigawatt hours a year. Our actual savings last year
when combined with a couple of other Power Smart -- or
not Power Smart projects, but energy efficiency projects
that the mine did itself, resulted in 36.7 gigawatt
hours a year in savings in 2002.
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And I just wanted to make the point that as a
large industrial customer, we look at energy very
importantly and we spend money in a manner to save
power. And that was before the Energy Plan was
implemented.
On the next two slides we'd like to show you
a couple of further potential uses that we can make at
the mine so that the Commission is aware of them.
The dam that you see in the foreground there
is our lower tailings dam, the LL dam. It's probably
the third largest dam in the province, it's not quite as
high as the Portage Mountain dam, WAC Bennett dam, but
it probably has more material in it. We use it to store
reclaimed water that's recycled to our milling
operation. And at the top of the hill in the distance
you can see a light spot which is a raw water reservoir.
We pump water from the tailings pond to the reservoir
where it flows by gravity back to our milling operation,
and we have storage in both places. And we have 20,000
horsepower pumping in the system that pumps from the
tailings pond to the reservoir.
Those 20,000 horsepower can be used for 16
megawatts of demand management potential for PDC type
programs that Hydro have had in the past.
We've extended our ethernet system from the
mill down to the dam. We have supervisory control and
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data acquisition computers tracking instantaneously
what's going on in this area, and there's potential to
provide 16 megawatts of spending reserve to B.C. Hydro
should they want to use their hydraulic turbines and
their dams to produce power, instead of just spinning
reserve. So there is that potential there.
And we also have potential to shift 20
megawatts from peak periods during the day to off-peak
periods at night if time of use rates are introduced.
So we just wanted to indicate that those are
real things that can be done should B.C. Hydro take the
opportunity to create rates in the future to accomplish
those types of things.
We are using the same slide again where we
indicate that we have a 12,000 horsepower pump house on
the Thompson River that pumps against 3,000 feet of head
or 900 metres of head against a .5 metre pipeline. We
have a dam, a reservoir, a penstock, and a pump house or
Pelton wheel facility that can be reconfigured with all
the physical elements in place, except the Pelton
wheels, to provide a high head pump storage facility
that could be used in the future for people here in B.C.
All that's required is the regulatory environment that
will allow it to happen. They physical assets are
there, the pumphouse is tied in a 10 MVA sub to B.C.
Hydro's 138 kV powerline, so there is no connection
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charges needed or facilities needed, it's all there just
waiting to happen.
So in conclusion, I'd like to indicate that
we've been actively involved in energy conservation
projects since 1973 and continue to be actively
involved. We have a number of projects that we are
working on this year. We've had good experience working
with current B.C. Hydro industrial Power Smart incentive
program. When Hydro was talking about using a shopping
credit we indicated that we were opposed to that
approach because we think that their existing Power
Smart incentive program works good.
We believe that rates are blunt instruments;
that targetted Power Smart, customer-based generation
programs and IPP programs can make things happen in
times of capital constraint where even their second tier
rate won't work.
We are currently installing metal halide
lights in our pit service building. There is 199
lights. It's going to cost $60,000 to install the metal
halide lights; they cost of $500 each. And when we did
a discounted cash flow setup on those lights, we looked
at it at current rates and we said, "Well, if we are
buying power at a second tier and it was twice the
existing rates, which would be 7 cents a kilowatt hour,
it still wouldn't have made economic sense to install
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the lights. But with the Power Smart grant it did. So
I just wanted to make that point.
We have the potential to install a small
hydro and pump storage scheme using existing facilities
without increasing our environmental impact at closure
of mining operations, and we would hope that by 2011
there would be open and equal access to low cost
opportunities to purchase power here in the province,
and open and equal access to opportunities to sell the
stored power at high prices when market opportunities
exist. And if that happens, then this power project
would happen.
We are an active member of the Joint Industry
Electricity Steering Committee. I chair the committee.
We strongly support the position taken by the Joint
Industry Electricity Steering Committee on Heritage
Contract, Stepped Rates and Access Principles, as will
be presented in the hearing. And we do not believe that
the second tier should be based on mid-Columbia market
prices which I understand was what Colin was saying
today, but it didn't come out that way in their
presentation. I think they were saying that it was
based on their cost of purchasing power, but I'm not
sure of that -- so.
I've read what's in their testimony before
the Commission and heard what was said today, and we
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like the way Hydro is moving, but we don't think they
are quite there yet.
We believe that a two step rate in which the
first tier is set on the cost of Heritage hydro assets
and that the second tier is based on the current cost of
hydro thermal assets and the cost of all other
electricity provided by B.C. Hydro will provide rates
that provide the certainty, suitability and
predictability that industry needs and requires.
And that ends my presentation. I'd like to
thank you very much for the opportunity to make it.
MR. FULTON: Mr. Scott, do I take it, given your position
with the JIESC that you will be a member of the JIESC
panel in Vancouver?
MR. SCOTT: A: I will be at the hearings and we haven't
tied down exactly what the story will be there at this
time.
MR. FULTON: In Vancouver if people who are here today who
will be in Vancouver have questions of the presentation
that you've made today, I take it that you will be
available to answer those questions?
MR. SCOTT: A: Yes.
MR. FULTON: Mr. Chairman, if the presentation might be
marked Exhibit 34.
THE HEARING OFFICER: Marked Exhibit 34.
THE CHAIRPERSON: Thank you.
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(PRESENTATION OF HIGHLAND VALLEY COPPER MINE BY MR. DAL
SCOTT MARKED EXHIBIT 34)
MR. FULTON: And if there are people here who will not be
in Vancouver who have questions of Mr. Scott, if they
would ask questions now. Does anyone from the floor
have a question?
Yes, sir, if you could come forward and
identify yourself for the record.
CROSS-EXAMINATION BY MR. WALSH:
MR. WALSH: Q: My name is Pearce Walsh and I'm a
consultant mostly working now in the deregulated
electricity market in Alberta. Mr. Scott, I've got a
question for you. It's my understanding that B.C.
Hydro's proposed Tier 2 rate is going to be based on
kind of a one-year market index which is as I understand
is going to be kind of a fixed forecast price for one
year ahead. And I just wondered, looking at some of
your power consumption, especially you talked about your
grinding operations which seemed to consume most of your
kilowatt hours per tonne, would it be preferable for
Highland Copper, if that Tier 2 rate was set on a more
real time market price based rate, you might have some
flexibility on your operating of your mine to shut down
some portions of the mine when the price went above a
kind of a pre-set level?
MR. SCOTT: A: We run our mine like an Overweightea Mega
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Market. We are basing -- where it's based on volume
and when you start shutting facilities down due to high
market prices, the facility would rapidly become
uneconomic.
MR. WALSH: Q: Thank you.
MR. FULTON: Are there any other questions from the floor?
There are none, Mr. Chairman.
THE CHAIRPERSON: Thank you. The panel doesn't have any
questions, Mr. Scott, but I'd like to make this comment:
In Victoria we heard from Norske and in Prince George we
heard from Kemess Mines, and you've made a presentation
this morning, and as Chair of the JIESC, I would be
appreciative if you extended our appreciation to the
participants in the regional sessions. They have
improved the regional sessions and I think have been of
value to not only the Commission panel but the members
of the public who attended. So thank you very much for
taking the time to be here this morning, and we look
forward to seeing you in Vancouver.
MR. SCOTT: Thank you very much.
(WITNESS ASIDE)
MR. FULTON: Mr. Chairman, we are beyond the time that we
usually take our morning break. We have at least two
more presenters to come, and so I'm in your hands in
terms of what your wishes are in terms of proceeding or
taking a short recess.
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THE CHAIRPERSON: My preference would -- excuse me. The
Commission panel would prefer to continue if that's fine
with the hearing officer and the court reporter? Okay.
We'll proceed.
MR. FULTON: Okay, then the next presenter is Mr. Rod Carle
who is with the Interior Municipal Electrical Utilities.
Mr. Carle.
ROD CARLE, Affirmed:
MR. FULTON: Mr. Carle, would you state your position with
the Interior Municipal Electrical Utilities?
MR. CARLE: A: Yes. I'm the current chairperson of the
Interior Municipal Electric Utilities, the IMEU,
currently the electric utility manager for the City of
Kelowna.
MR. FULTON: All right, and you are authorized this morning
to speak on behalf of the IMEU?
MR. CARLE: A: Yes, I am.
MR. FULTON: You have a presentation that you wish to make
to the Commission?
MR. CARLE: A: I have an oral submission, a few hard
copies but it was deemed to be oral to the transcript.
Thanks.
MR. FULTON: Thank you. If you then would like to proceed
with your presentation.
EVIDENCE IN CHIEF:
MR. CARLE: A: Thank you. Good morning, Mr. Chairman.
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It's nice to see you back here in the Okanagan.
Commissioners Hall and Bradley, glad to see that you
could make down into our nice warm city this morning.
I'm here to represent the Interior Municipal
Electrical Utilities Group who is composed of the
electric utilities owned by the following
municipalities: The City of Kelowna, the City of Nelson
or Nelson Hydro, the City of Penticton, the City of
Grand Forks, the District of Summerland, and investor
owned Princeton Light & Power.
Collectively the IMEU serve over 250,000
citizens and have sales of approximately 850 gigawatt
hours to about 45,000 customers, providing revenues of
approximately $50. The IMEU members who have been
long-time wholesale customers for 80 plus years,
contract with Aquila Networks Canada for their supply of
electricity. Part of Aquila's wholesale power contracts
with the municipalities are supplied by B.C. Hydro.
The customers served in our areas are
primarily residential and commercial. The IMEU members
have a long history of tradition of providing customers
with low cost reliable electricity and quality customer
service. The IMEU members are proud of the dedication
and commitment they have made to their customers. It is
with motivation, the IMEU group has undertaken to
present its views on the British Columbia Hydro and
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Power Authority Stepped Rates and Access Principles
Inquiry to the BCUC Commission.
The IMEU have been present as an observer at
most of the Commission stakeholder inquiry workshops and
totally supports, as it always has with its power
provider Aquila, the regulatory oversight by the BCUC.
The IMEU do not wish to formally pursue the issues
before the Commission today, but only want to make the
Commission aware if its general comments prior to the
Commission's formal hearing process scheduled to be held
in Vancouver on July 29th.
Firstly the IMEU supports the Province of
British Columbia with the direction it is going with its
new Energy Plan. The IMEU agree with and support the
four cornerstones of the Energy Plan which are low
electricity rates and public ownership of B.C. Hydro,
secure reliable energy supply, more private sector
opportunities and environmental responsibility.
Secondly, the IMEU believe -- and there's
been limited discussion to date on this item, is the
length of the term for the Heritage Contract should be
considerably longer. We understand the terms of
reference suggested an initial minimum of ten years with
an automatic renewal. IMEU believe this Heritage Power
that belongs to all the paying customers of B.C., which
we are indirectly one of them, should somehow be more
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assertively recognized. Therefore the IMEU believe this
entitlement of the low embedded cost of power should
always stay with the customers in perpetuity.
The IMEU recommend the initial term of the
contract, in order to preserve this entitlement right,
should be for a minimum of fifty years with no
termination period notice, and not the minimum ten years
as originally suggested. This guaranteed longer term
would alleviate any worries from paying customers or
ratepayers who may perceive that their entitlement may
be gone after the initial ten-year term.
As an observation on the processes to date,
the IMEU have reviewed the Commission and stakeholders'
public hearing issues list and recognize the Commission
does not have an easy task laid out before it.
Timelines are tight, and a number of issues are very
complex, as you've heard throughout some of the sessions
earlier today.
The IMEU supports Aquila's position that it
is a vertically integrated electric utility and one that
does have a hybrid relationship with B.C. Hydro. As you
are aware, Policy Action 21 clearly does focus on end
users, and these are people, who as a matter of policy,
ought to be given the opportunity to operate in an
economically efficient manner. As Dal has spoken
earlier, he's -- you know, these are the types of
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customers that really want that opportunity and should
have that opportunity.
The IMEU understand B.C. Hydro has always
indicated to all its stakeholders and customers that all
they really want at the end of the day is for their
customers to have low-cost reliable electricity and good
customer service. The IMEU have a long tradition of
providing the same and would find it very hard not to
support any utility that wants a similar outcome.
As always, the IMEU want to thank the BCUC
and B.C. Hydro panel for allowing them to participate in
this Regional Energy Plan hearing. The IMEU hope any
general comments that they have put forward will be
passed onto the province, and the IMEU will continue to
observe throughout the formal hearing process, and if
any issues arise or cause concern, the IMEU will make a
full written submission argument adhering to the
Commission's regulatory timetable and schedule.
Respectfully submitted, from the IMEU, myself
Rod Carle. Thank you.
MR. FULTON: Thank you, Mr. Carle. Are there any questions
from the floor of Mr. Carle?
No questions from the floor, Mr. Chairman.
THE CHAIRPERSON: Thank you. Mr. Carle, I appreciate you
being here this morning. I know that we are in your
hometown, and it's great to have you here. And I'm also
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looking forward to seeing you next week, assuming you're
are going to be their representative, IMEU is going to
be there. So the Commission panel does not have any
questions for you this morning, either. I do think that
your contributions will be very valuable, so if you
chose to submit argument, we certainly would be
appreciative of that. So thank you.
MR. CARLE: A: Thank you, Mr. Chairman.
MR. FULTON: Before you stand down, Mr. Carle, just so that
the record is complete, do I take it that you will be
available in Vancouver to answer questions on your
presentation today for those who are participating in
Vancouver and were not here today, or B.C. Hydro and
Commission staff for example whose main participation
will be in Vancouver?
MR. CARLE: A: Certainly I will be in Vancouver for the
first week. Second week is pending, depending on what
the schedule is, and if there is any need we would
certainly like to try and address any of those concerns
in the first week.
MR. FULTON: All right. So what I will do as Commission
counsel, Mr. Chairman, is ensure that Mr. Carle is
slotted into a time during the first week of the
proceedings so that if people have questions of him at
that time directed towards the position of the IMEU,
that those questions are asked next week.
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Secord was going to make, Mr. Chairman, that otherwise
concludes the presenters for this regional session.
MR. SECORD: I'm just going to be speaking off the top of
my head, is that all right?
THE CHAIRPERSON: Yes.
EVIDENCE IN CHIEF OF MR. SECORD:
MR. SECORD: A: In light of what was said by this lady
here, obviously she was not made aware of Dr. Jaccard's
report which was done -- the study was done in 1997.
The report was wrote in 1998. Dr. Jaccard's report
basically tells you that B.C. Hydro will be -- he wanted
B.C. Hydro split up into four units, Customer Service,
Distribution, Transmission and Generation. That was his
recommendation in his report.
His report was his report only. The
stakeholders did not approve of it, and there was 17
stakeholders. I was an alternate to one of those
stakeholders.
Dr. Jaccard also recommended using natural
gas for generation of electricity. Our organization has
studied this extensively. We have been following the
news on what's available on natural gas, and if natural
gas is used ultimately we are going to reap the benefits
or the costs. And I've heard an energy report from the
United States, this was about two months ago, where they
had an energy consultant on. He said the price of
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natural gas in the States is going to triple this coming
winter, the reason being electricity is being generated
with natural gas. If they shut that down then there
would be no shortage of natural gas. So our stand as an
organization has been that we are opposed to using
natural gas for the generation of electricity.
This report here, Energy For Our Future, A
Plan for British Columbia is nothing more than Dr.
Jaccard's report recycled. And because this energy
report was produced, there was no -- to my knowledge
there was no public input into it. It's got no
transparency at all. It was wrote and I have
convictions about who was that wrote this report for the
government, and I'm absolutely opposed to the proposals
that are in here and one of the reasons being that the
private sector, and I'm not putting the private sector
down, in all due respect to the private sector, they are
in business to make money. But we have the Bennett dam
and then there's also a future location for power at
Site C on the Peace River.
Site C would be nothing without the Bennett
dam, but private sector, the government has said that
B.C. Hydro us not going to be allowed to build any more
generation, in this report. That site is owned by --
they own the land, B.C. Hydro owns the land, as I
understand it, or we've been able to ascertain that they
CANFOR CORPORATION
INFORMATION CIRCULAR
April 28, 2006
The following chart shows sales of Kraft Paper produced by PGP&P for the last three years, classified by salesregion.
Kraft Paper Sales by Geographic Region (tonnes)Geographic Region
Year Total Sales North America Europe Asia
2005 *************************************** 127,252 89,503 (70%) 33,137 (26%) 4,612 (4%)2004 *************************************** 139,820 106,934 (77%) 22,522 (16%) 10,151 (7%)2003 *************************************** 121,370 92,551 (76%) 18,433 (15%) 10,386 (9%)
Customers
Pulp
The Mills have long-standing relationships with the majority of their customers, some for as long as 40 years. Allof the largest customers have evergreen supply agreements with lengthy notice periods and ramp down clauses shouldeither party wish to terminate the agreement.
In 2005, the Partnership’s top 10 customers purchased approximately 650,000 ADMT of pulp, or 65% of thePartnership’s total pulp sales. The Partnership’s largest customer accounted for 26% of its total pulp sales and was theonly customer which accounted for more than 10% of the Partnership’s total pulp sales.
Due to the high quality of its pulp, the Partnership has rarely had any difficulty in selling all of its production. As aresult, its main marketing focus has been on optimizing the technical fit and geographic/customer mix to maximize millnets over the business cycle.
The Partnership adopts a conservative approach to extending credit to customers in order to minimize the risk ofbad debts. Most overseas sales require a letter of credit and are fully insured, with the exceptions being large, globalcustomers with strong credit ratings. Due to this conservative credit policy, the Partnership has experienced no bad debtexpense in its sales over the last 3 years.
Kraft Paper
Similar to the pulp business, the Kraft Paper customer base is characterized by many long-standing relationshipswith evergreen contracts.
In 2005, the Partnership’s top 10 Kraft Paper customers purchased approximately 93,000 tonnes of Kraft Paper, or73% of the Partnership’s total Kraft Paper sales. The Partnership’s largest customer accounted for 20% of its total KraftPaper sales and only two additional customers accounted for more than 10% of the Partnership’s total Kraft Papersales.
The Partnership adopts a similar conservative approach to extending credit to Kraft Paper customers in order tominimize the risk of bad debts. Due to this conservative credit policy, the Partnership has experienced no material baddebt expense in its Kraft Paper sales over the last 3 years.
Human Resources
The Partnership employs approximately 1,250 people throughout the organization and approximately 75% of theseemployees are hourly employees covered by collective agreements with the Communications, Energy andPaperworkers Union (‘‘CEP’’) and the Pulp, Paper and Woodworkers of Canada (‘‘PPWC’’). Negotiations with theCEP and the PPWC for the renewal of the agreements covering the pulp and paper operations were successfullyconcluded and ratified in 2003 for terms of five years expiring on April 30, 2008.
The agreements provide for wage increases totalling 11% over the five-year term.
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The following chart summarizes, for each Mill, the number of employees, collective agreements in effect and thepercentage of the workforce governed by these agreements.
%Mill Employees Union Unionized Agreement Expiry
Northwood ********************************** 500 CEP, Local 603 80% April 30, 2008Intercontinental******************************* 300 PPWC, Local 9 80% April 30, 2008PGP&P ************************************* 400 PPWC, Local 9 75% April 30, 2008
CEP, Local 1133Sales and Marketing ************************** 45 N/A 0% N/A
Capital Expenditures
Capital expenditures in connection with the Mills can be categorized into two types: sustaining and discretionary.Sustaining capital expenditures are additions to or replacements of assets required to maintain the operationalcomponents of the Mills at their current capacity. Discretionary capital expenditures are earnings enhancing projectsundertaken to increase productivity, reduce costs or increase operating capacity.
During the last three years, an average of $43 million has been spent annually on capital expenditures at the Mills,of which $8.3 million were sustaining capital expenditures and the remainder were discretionary capital expenditures.Management estimates that in order to maintain the Mills in good working order, future sustaining capital expenditureswill average approximately $34 million per year, before adjustment for inflation, which will be funded out of operatingcash flow of the Partnership.
Estimated sustaining capital expenditures include an annual reserve of $4 million per year for the next 20 years tofund significant capital projects including the reconstruction of a recovery boiler at Northwood at a cost (in 2004dollars) of $55 million.
The following table summarizes capital expenditures by the Mills over the past three years:Year Ended December 31,
2005 2004 2003
(unaudited)(in thousands of dollars)
Capital ExpendituresSustaining********************************************************** 3,845 11,954 9,221Discretionary ******************************************************* 39,225 48,464 14,087
Total capital expenditures *********************************************** 43,070 60,418 23,308
Discretionary capital expenditures over the past three years were made principally in connection with theCogeneration Project. Completed at a cost of $115.4 million, less $45.8 million recovered from BC Hydro under theCogeneration Agreement, the Cogeneration Project is expected to provide 1,070 MWh of electricity per day andoperating cost savings of approximately $21.5 million per year. The Partnership will consider future discretionarycapital expenditures which generate an attractive return and are accretive to Distributable Cash, and expects to fundsuch discretionary capital expenditures out of operating cash flow of the Partnership, draws under the New CreditFacilities, or from a combination of these sources.
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Operating Cash Costs
Fibre is the single largest component of the Mills’ total operating cash costs and, due to the plentiful supply ofwood in the region where the Mills operate, provides the Mills with a significant competitive advantage. The followingchart shows fibre costs for the Mills compared to other operating cash costs.
Year EndedDecember 31,
2005 2004 2003
(unaudited) ($ per ADMT)
PulpFibre cost ********************************************************************* 172 207 183Adjusted fibre cost(1) ************************************************************ 126 N/A N/AOther cash costs(2) ************************************************************** 303 301 310Adjusted other cash costs(3) ******************************************************* 282 N/A N/ATotal operating cash costs ******************************************************** 475 508 493Adjusted total operating cash costs(1)(3)********************************************** 408 N/A N/AKraft PaperTotal operating cash costs ******************************************************** 718 770 744
(1) The adjustment for cost of fibre gives effect to the pricing formula in the Fibre Supply Agreement as though it had been in effect for woodchips consumed from January 1, 2005. See ‘‘— Fibre Supply — Fibre Supply Agreement — Summary of Cost Savings’’.
(2) Includes labour, chemicals, energy, maintenance, overhead and other cash costs.
(3) The adjustment for other cash costs gives effect to the productivity increase and energy savings from the Cogeneration Project as though it hadbeen completed and fully operational by January 1, 2005. See ‘‘— Energy — PGP&P — Cogeneration Agreement — Summary of CostSavings’’.
Fibre Supply
General
When running at full capacity, the Mills’ annual fibre requirements are expected to be approximately 2.4 millionODTs of wood chips and 565,000 ODTs of hog fuel. The availability of wood chips for purchase and processing in thecentral interior of British Columbia depends in large part on the timber supply in the Prince George Timber SupplyArea (‘‘PGTSA’’). Historically, the annual allowable cut levels in the PGTSA have been sufficient to supply all of thefibre requirements of the Mills. In order to control the mountain pine beetle infestation in the area the Ministry ofForests has increased the annual allowable cut in the PGTSA by approximately 30%. This increase in the AAC isprojected to remain in effect for at least the next eight to ten years, resulting in an increase in the already abundantsupply of wood chips. The Partnership anticipates this surplus of fibre will result in very competitive fibre pricing overthe short and medium-term and estimates that the average price of delivered wood chips will provide the Mills withsome of the lowest fibre costs in the world and a significant competitive advantage relative to eastern Canadianproducers.
The Mills’ annual fibre requirement of 2.4 million ODTs of wood chips is satisfied through purchases fromsawmills in the region. The Mills obtain approximately 1.8 million ODTs of wood chips from 10 Canfor sawmills inthe region and approximately 1.1 million ODTs from other sawmills. The Mills trade or resell any wood chips obtainedin excess of their requirements to other facilities.
Fibre FlowODTs
(millions)
Purchases from Canfor ******************************************** 1.8Purchases from other sawmills ************************************** 1.1Sales/trades ***************************************************** (0.5)
Total usage****************************************************** 2.4
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The Mills have a wood chip supply consisting primarily of lodgepole pine and white spruce. The wood chipspecies percentages are variable by Mill, depending on the supply sources directed to each Mill. Wood chips are storedin co-mingled piles at each of the Mills, with the exception of any wood chips derived from balsam fir, which are storedseparately at PGP&P and used principally in the production of unbleached pulp and paper. Wood chips from eachspecies are combined and processed to produce a premium reinforcing market NBSK Pulp and for use by PGP&P inproducing Kraft Paper.
Fibre Supply Agreement
On the Effective Date, the Partnership will enter into the Fibre Supply Agreement with Canfor under whichCanfor will supply the Partnership with agreed annual quantities of the residual wood chips and hog fuel produced atspecified sawmills in the Prince George Forest Region.
If Canfor discontinues operation of, or reduces production on a long term basis at, any of the specified sawmills,the Partnership has the right to replace the lost volume from other Canfor sawmills which are closest in terms oftransportation efficiency to the Mills. Canfor will have the first right of opportunity to sell to the Partnership any woodchips required by the Partnership in excess of the agreed maximum annual quantity on the same commercial termsincluding price, as set out in the Fibre Supply Agreement. If the Partnership requires additional annual quantities ofwood chips due to an increase in the capacity of the Mills, the Partnership is required to first offer to purchase theadditional wood chips from Canfor on the same commercial terms as those set out in the Fibre Supply Agreement. ThePartnership will also have the first right to acquire additional wood chips from any sawmill facility subsequentlyacquired or constructed by Canfor in the Prince George Forest Region, subject to any commitments affecting anacquired facility which are in effect or required by the vendor as a condition of the acquisition. Canfor has the right, onprior written notice, to require the Partnership to purchase wood chips from Canfor in excess of the agreed maximumannual quantity. If, as a result, the Partnership is required to terminate or cancel other supply agreements in order totake the additional Canfor wood chips, then the price that Canfor is entitled to receive will not be greater than the pricepaid pursuant to the other supply agreements which were terminated or cancelled.
The price (the ‘‘Base Price’’) to be paid by the Partnership for all wood chips supplied by Canfor under the FibreSupply Agreement in each month in the term of that agreement will be a price per ODT based upon a three monthaverage rolling Mill Net determined in accordance with the following:
Three Month Average Base PriceRolling Mill Net (‘‘AMN’’) Calculation
=G$500.00 (AMN × 7.25%) – $5.00H$500.00 (AMN × 7.25%)H$600.00 (AMN × 7.75%)H$750.00 (AMN × 8.25%)
The three month average rolling Mill Net calculation will be based upon actual sales in each month of fullybleached, semi-bleached and unbleached kraft pulp averaged by weight. The price paid by the Partnership will beadjusted periodically to reflect prices prevailing on the open market. The price paid by the Partnership will also beadjusted for wood chip quality and to reflect any changes in the actual freight cost for delivering the wood chips to theMills if Canfor elects to supply wood chips from Canfor sawmills other than the Canfor sawmills specified in the FibreSupply Agreement. The Partnership will also be entitled, upon giving three months’ prior written notice, to requestCanfor to supply the Partnership with pulplogs or other pulpwood harvested by or on behalf of Canfor from itswoodlands operations, at market prices in the Prince George forest region.
Canfor will also supply the Partnership with agreed annual quantities of hog fuel produced from specified Canforsawmills located within the Prince George forest region. If Canfor discontinues operations at any of the specifiedCanfor sawmills, Canfor must use its reasonable efforts to supply the Partnership with hog fuel from other Canforfacilities so as to maintain the quantity of hog fuel supplied to the Partnership. Canfor will also have the right, on notless than six months’ prior written notice to the Partnership, to reduce the quantity of hog fuel delivered from thespecified sawmills. If Canfor exercises this option, the Partnership will be entitled to acquire hog fuel from otherCanfor sawmills which are closest in terms of truck hauling to the Mills in order to replace the displaced quantity ofhog fuel, to the extent hog fuel is available from the other Canfor sawmills. The price to be paid by the Partnership toCanfor for hog fuel supplied under the Fibre Supply Agreement will be the prevailing market price, which is currentlynominal.
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Summary of Cost Savings
The same wood chip pricing formula as set out in the Fibre Supply Agreement was phased in during the thirdquarter of 2005 for wood chips purchased by the Pulp Business from Canfor and other suppliers. The actual averagecost to the Partnership of wood chips during 2005 was $80.78 per ODT, while the average cost to the Partnership ofwood chips during 2005 using this pricing formula would have been $59.05 per ODT, resulting in an average saving of$21.73 per ODT. Had this pricing formula been applied to the total 2.4 million ODTs of wood chips consumed in thePulp Business during 2005, the total cost of wood chips consumed in the year would have been reduced byapproximately $51.2 million.
Other Fibre Supply Arrangements
The Mills currently have short and long term chip supply agreements with 18 different suppliers, other thanCanfor, supplying a total of 1.1 million ODTs on an annual basis. These agreements are for periods ranging betweenone and 18 years and each permits the Mills to purchase wood chips available at a specified sawmill, subject to certainmaximums. These agreements do not provide for minimum volumes, which protects the Mills from being required topurchase wood chips in excess of their requirements.
Pricing for wood chips purchased under these agreements is based on the same formula as used in the FibreSupply Agreement, subject to adjustment for chip quality. Similar to other pulp producers, the Mills have chip qualityincentive programs for suppliers designed to reduce off-grade pulp. The program is designed to ensure the highestquality of wood chips is supplied by reducing bark and chip fines as well as defining the preferred classification mix ofwood chips. Wood chip quality measurements are, in most cases, the responsibility of the supplier, with the Millsentitled to conduct audits.
In addition to the supply of hog fuel under the Fibre Supply Agreement, the Partnership will be able to source hogfuel from a variety of suppliers, as hog fuel currently has limited value at the source and is usually sold in the region forthe cost of transportation to the Mills.
The Partnership expects that the Fibre Supply Agreement, together with supplemental agreements with otherparties for the supply of wood chips, will satisfy all of its anticipated fibre requirements to operate the Mills at currentor reasonably projected levels of operation.
Energy
Northwood
Northwood generates approximately 83% of its electrical power requirements and purchases the remaining 17%from BC Hydro. Northwood’s steam production is approximately 70% from black liquor from the kraft pulpingprocess, 18% from hog fuel and 11% from natural gas.
Intercontinental
Intercontinental historically produced approximately 53% of its electrical power requirements and purchased theremaining 47% from BC Hydro. With the completion of the Cogeneration Project, Intercontinental expects to produceor acquire from PGP&P a total of approximately 85% of its electrical power requirements and purchase the remaining15% from BC Hydro. Intercontinental’s steam production is primarily from black liquor and hog fuel, with only 5%being generated through natural gas.
PGP&P
Historically, energy used for the production of pulp and paper at PGP&P was provided through purchasedelectricity and burning natural gas, hog fuel and internally generated black liquor. Most of these fuels were burned inboilers to produce steam that is used in mill processes.
Cogeneration Agreement
In October 2003 BC Hydro entered into an agreement (the ‘‘Cogeneration Agreement’’) under which it agreed tocontribute $46 million, through its PowerSmart Program, to construct an electrical cogeneration facility at PGP&Pdesigned to produce 48 MW of electricity (the ‘‘Cogeneration Project’’). In addition to the construction of theelectrical cogeneration facility, the Cogeneration Project included the modification of two of the three boilers at
E-18
PGP&P and the addition of wood waste and ash handling systems to enable a more efficient use of energy generatedfrom black liquor and significantly higher steam production from hog fuel.
The Cogeneration Agreement requires the Cogeneration Project to be operated for a period of 15 years from itscompletion at an average annual electricity output of 390 GWh, to supply the electricity requirements of PGP&P andIntercontinental up to a maximum of 1,070 MWh per day. If there is a suspension or curtailment of, or other conditionaffecting, the operation of Intercontinental or PGP&P which reduces the forecast annual electricity requirement of thesetwo mills below 390 GWh, BC Hydro may require, for a period specified in a written notice given by it, that theCogeneration Project be operated to generate up to 1,070 MWh of electricity per day and that the excess electricity bedelivered to BC Hydro without any further payment by it. That obligation does not apply once the Cogeneration Projecthas generated 390 GWh in any year. Otherwise, electricity generated at the Cogeneration Project in excess of therequirements of the two mills may be sold to third parties including BC Hydro and its subsidiary, Powerex Corp. TheCogeneration Agreement also provides that if the Cogeneration Project generates less than 390 GWh in any year andthe shortfall cannot be made up by excess generation of up to 39 GWh in prior years or excess generation in thesubsequent year, BC Hydro is entitled to be paid an amount equal to $3.27 million multiplied by the ratio of theuncorrected shortfall to the annual requirement of 390 GWh.
The Cogeneration Project was completed in June 2005 and is currently generating an average of 950 MWh ofelectricity per day, which is 89% of the targeted generating capacity of the facility. Completion of the CogenerationProject has also resulted in a significant increase in steam production and the elimination of 77% of natural gas usage insteam generation.
Summary of Cost Savings
Production rates at the PGP&P mill in 2005 were curtailed during and after the construction and installation of theCogeneration Project and before the additional precipitator was completed, in order to operate within allowable airemission standards. Much of the impact of the cost of lost production was offset by energy cost savings, for a netestimated loss in 2005 resulting from installation of the Cogeneration Project of $1.1 million.
However based on 2005 energy rates, had the Cogeneration Project been fully operational from the beginning of2005, the cost savings for the year would have been $22.6 million. These annual savings are primarily generated fromthe elimination of annual consumption of 390,000 MWh of purchased electricity, based on a price of $36.53 per MWhand the elimination of annual consumption of 787,000 gigajoules of purchased natural gas, based on a price of $8.05per gigajoule. The following table shows the breakdown of the total estimated cost savings.
Annual CostCategory Description Savings
($ millions)
Electricity Elimination of 390,000 MWh of purchased electricity ************************** $14.3
Natural Gas Elimination of 787,000 gigajoules of purchased natural gas********************** $ 6.3
Maintenance Reduction in annual maintenance cost *************************************** $ 0.8
Production Increase in production rates************************************************ $ 2.1
Hog Fuel Additional hog fuel costs************************************************** $ (2.0)
Annual cost savings ****************************************************** $21.5
Add back net productivity loss in 2005 ************************************** $ 1.1
Total estimated cost savings for 2005 *************************************** $22.6
With the completion of the Cogeneration Project, PGP&P and Intercontinental are 92% self-sufficient in meetingtheir electricity requirements.
Chemicals
The Partnership has entered into a long-term supply agreement (the ‘‘Chemical Supply Agreement’’) underwhich it has agreed to obtain all of the Mills’ requirements for the principal chemical used in the production of pulp,sodium chlorate, exclusively from Chemtrade, a subsidiary of Chemtrade Logistics Income Fund, whose facilities arelocated adjacent to the Intercontinental Mill. The long-term supply agreement has a minimum annual purchaserequirement of 48,000 tonnes of sodium chlorate. Sodium chlorate is used for the production of chlorine dioxide, which
E-19
I N T E G R A T E D E L E C T R I C I T Y P L A NAn Update to the 1995 IEP
January 2000
p a g e 3
Integrated Electricity Plan
1.2.5 Role of Demand-SideManagement
BC Hydro introduced the Power Smart demand-
side management program in the mid-1980s
with the primary goal of encouraging cost-
effective conservation. Utility involvement was
seen to be needed in order to encourage
energy efficiency.
Over the past 10 years, substantial progress has
been made in changing customer attitudes
toward electricity use and in stimulating the
development and consumer demand for more
efficient appliances and equipment. A more
competitive market for energy-efficient prod-
ucts has now been achieved.
Today, the private sector is producing energy-
efficient products and providing energy
management services at competitive prices.
Customers are able to choose between invest-
ment in energy efficiency and purchasing
supply.
The load forecast considers cumulative and
future demand reductions attributable to
BC Hydro’s existing Power Smart programs.
BC Hydro will continue to encourage energy
efficiency by supporting energy-efficient stan-
dards and regulations and by providing energy
management services.
BC Hydro will also continue its community
energy planning activities which encourage
energy awareness in community and land use
planning.
1.2.6 Alcan Agreement
As part of the 1997 B.C./Alcan Agreement,
BC Hydro and Alcan confirmed that their Long
Term Energy Purchase Agreement (LTEPA) was
still in effect and established Alcan’s continuing
supply obligations. Subsequently, BC Hydro
agreed that a portion of the remaining obliga-
tion could be assigned to other suppliers
including the Columbia Power Corporation
(CPC). This delivery would be supplied from the
170 MW Keenleyside project.
Also under the Agreement, the Province,
through BC Hydro, has committed to supply
Alcan up to 175 average MW if Alcan decides to
expand its smelter facilities at Kitimat. Alcan
may also recall the 147 MW (1225 GWh/yr)
currently supplied to BC Hydro under the LTEPA
for the purpose of serving a new smelter.
If new electricity resources were required to
serve a new smelter, these resources could be
acquired on a timeline equal to or less than
that required for the smelter.
1.2.7 Columbia Power Corporation andColumbia Basin Trust
In a joint venture initiative, the Columbia
Power Corporation and the Columbia Basin
Trust are pursuing the development of power
projects in the Kootenay region. These include
the Keenleyside powerplant which is currently
under construction. Keenleyside is a Columbia
River Treaty storage dam. BC Hydro has agreed
to take delivery of the output of the
Keenleyside project under the Alcan Long Term
Energy Purchase Agreement.
p a g e 5
Integrated Electricity Plan
The 1995 IEP identified a Four-Year Action Plan
to acquire or maintain the availability of new
projects and programs identified in the 20-Year
Table 2-1. 1995 IEP Action Plan - Current Status
Resources Action Current StatusGeneration
2 Status of 1995 IEP Act ion Plan
Alternative Technologies
(solar, wind, fuel cells, tidal)
Hydroelectric
Stave Falls Power plant
Revelstoke Unit 5
Seven Mile Unit 4
Resource Smart
Purchases
Alberta and U.S. Imports
Alcan
Downstream Benefits
Thermal
Burrard G.S.
Private Sector
December 1994Request for Proposals
Continue to collect information, provide quarterly reports and annual updates of resource summaries. Support information exchange, research and demonstration projects if cost-effective.
Continue licensing requirements and proceed with construction.
Continue the Environmental Assessment Act
licensing process.
Continue the Environmental Assessment Act licensing process.
Continue cost-effective efficiency improvements at existing facilities.
Purchase when cost-effective and/or needed.
Continue purchases.
Continue discussions with the provincial government. Purchase when cost-effective and/or needed.
Install second selective catalytic reduction and associated upgrade work.
Continue investigation of repowering two modules and continue full repowering investigations.
Continue investigation of fuel supply.
Negotiate with proponents for possible purchase of up to 300 MW if contract terms and pricing are satisfactory.
Energy Futures Program established tofoster development of alternative energyresources.
In-service fall 1999
No significant work undertaken on theEnvironmental Assessment process, butkeep project in “shelf ready” status.
Environmental permits received; examiningadvancement of Seven Mile 4
Ongoing
Economic short-term market purchases andsales from US and Alberta are ongoing.
Purchases from Alcan under the Long TermEnergy Purchase Agreement are continuing.
DSBs are being marketed by Powerex onbehalf of the province but available toBC Hydro at market prices
Installation of the 6th and final SCR will becomplete by 2000.
Decisions on repowering deferred.
Agreement with BC Gas in place for firmgas transport commencing November 1999.
Island Cogen – in service mid-late 2000 Purcell W/W – in service fall 2000 Intercon W/W – deferred by Proponent Pt. Alberni Cogen – commercial negotia-
tions in progress
Outlook. The status of initiatives identified in
the 1995 IEP Four-Year Action Plan is summa-
rized in Table 2-1.
Integrated Electricity Plan
p a g e 1 0
Table 3-1. Capability of Existing and Committed Resources by 2003/04
Resources Capacity (MW) Energy Capability (GWh)Dependable * Firm*
Existing Hydroelectric1
Peace System 3280 15790
Columbia System 3710 14490
Others 2659 12800
Subtotal 9649 43080
Existing Thermal
Burrard2 950 7050
Rupert 46 180
Subtotal 996 7230
Existing Purchases3
Alcan LTEPA 147 1225
IPPs 212 1820
Subtotal 359 3045
New Purchases
Island Cogeneration Project3 240 2140
Port Alberni Cogeneration Project4 240 1995
Keenleyside (under Alcan LTEPA)3 170 750
Purcell Woodwaste3 14 90
Subtotal 664 4975
TOTAL 11668 58330
1Potential losses in plant capability due to Water Use Planning outcomes or increased plant capability due to future Resource Smart projects are notincorporated. Firm hydro energy capability is annual energy capability under period of lowest historical stream flow conditions. Dependable wintercapacity is based on 85% confidence level based on range of historical streamflow conditions.
2Includes firm gas transport and six upgraded SCR units at Burrard
3Binding Electricity Purchase Agreements in place.
4Negotiations in progress
* Some numbers have been rounded
p a g e 1 1
Integrated Electricity Plan
sixth unit is to be completed by the summer of
2000.Burrard is an important energy and
capacity resource in the BC Hydro system. It is
equivalent to 12 per cent of BC Hydro’s firm
energy capability. Burrard is a displaceable
resource and serves many roles. It is used for
transmission support and to optimize the value
of the electric system. It is also close to
BC Hydro’s major load centre enhancing secu-
rity of supply. The December 1998 agreement
with BC Gas to supply firm gas transportation
to Burrard allows BC Hydro to rely on Burrard
to meet system peak winter loads.
The Keogh generating station is a two-unit,
90 MW oil-fired plant near Port Hardy on
Vancouver Island built in the early 1970s. The
plant is no longer reliable and has high oper-
ating costs. Fuel storage capacity is limited.
Decommissioning of the plant is planned.
3.3.3 Update on Purchase Agreements
BC Hydro has entered into Electricity Purchase
Agreements with the IPP developers of the
Island Cogeneration Project (ICP) at Elk Falls
near Campbell River and Purcell Woodwaste
Project at Skookumchuck. BC Hydro has also
concluded a Key Principles Agreement to
purchase the output from the proposed Port
Alberni Cogeneration Project. Electricity
Purchase Agreement negotiations with the Port
Alberni project proponents are continuing.
Both ICP and Purcell are expected to be in
service by the fall of 2000. The Port Alberni
project is currently expected to be in service no
earlier than the fall of 2002.
BC Hydro has contracted to take delivery of the
output of the Keenleyside Powerplant starting
in January 2003 as part of its Long Term Energy
Purchase Agreement with Alcan.
3.3.4 Major Transmission SystemUpdate
Since the 1995 IEP, the plan for the bulk trans-
mission system has been impacted both by the
change in regional load forecasts and by several
new generation projects:
• The trend in deterioration of the HVDC terminal
station equipment confirms that both HVDC
Pole 1 and Pole 2 are expected to retire in stages
by the year 2007.
• HVDC Pole 1 transfer capability has already
been reduced for planning purposes. However,
operationally it is available in standby mode. Its
transfer capability is replaced by Island Cogen
and Port Alberni Cogen. The replacement of
HVDC Pole 2 transfer capability will need to be
addressed, including the unique reliability
requirements of the Vancouver Island system.
Options under consideration include the replace-
ment of the HVDC or additional generation
capacity on the Island.
• Refurbishment of the Creekside Capacitor
Station to maintain the transfer capability from
B.C.’s interior to the load center is proceeding;
• Installation of a new transformer at Selkirk
Substation is proceeding. This will provide
increased firm transfer capability for local
generation in that area.
3 .4 Planning Criteria
BC Hydro develops electricity plans for new
resource acquisitions to supply BC Hydro’s
existing and new domestic electricity require-
ments consistent with established energy and
capacity reserve criteria. Electricity plans also
p a g e 2 3
Integrated Electricity Plan
The Revelstoke and Mica projects would
provide new generating capacity, but would
not provide significant additional energy capa-
bility. The preferred sequence for adding these
units would be to add the fifth unit at
Revelstoke followed by the fifth unit at Mica to
maintain hydraulic balance between the two
plants.
Revelstoke Unit 5 would provide 60 GWh/year
of additional energy because of improved effi-
ciency compared to the existing Revelstoke
units. Revelstoke Unit 5 would enhance
BC Hydro’s opportunities to shape energy
output in peak demand hours.
The Peace Site C project is downstream of the
Peace Canyon generating station. It would
provide 900 MW of capacity and 4,570
GWh/year of firm energy.
On an ongoing basis, BC Hydro assesses oppor-
tunities for cost-effective efficiency and
operational improvements at existing genera-
tion facilities. These initiatives are referred to as
Resource Smart projects. This work is expected
to continue and resulting increases in output
will be incorporated into BC Hydro’s ongoing
planning process.
5.2.4 Woodwaste
Woodwaste projects include stand-alone elec-
tricity generation or cogeneration to produce
steam and electricity, such as at a pulp mill.
Woodwaste projects are assumed to cause no
net increase in greenhouse gas. It is currently
estimated that there is an additional 200 MW
Table 5-1. IEP Generation Resource Summary
GHG LocalEmissions Air
Cost tonnes/ Emissions OtherProject Capabil ity GWh kg/GWh Employment Comments
Installed Firm Energy Corporate Provincial Construction PermanentMW GWh Cost Cost NOX Particulates (prs-yrs) (# jobs)
Hydroelectric
Seven Mile 4 213 135 Low/Med Low 0 0 0 250 0 Addition to existing plant.
Revelstoke 5 Addition to existing plant.(Similar units: 500 60 Low to Med Low to Med 0 0 0 300 0REV6, Mica 5&6)
Small-Medium Hydro Land use: varies Estimated total 12–60 72–270 Med to High Low to Med 0 0 0 23–310 1–6 from 1 to 215 developable hectares per site.potential: 330 MW
Peace Site C 900 4570 Med to High Med to High 0 0 0 5700 25 Land use: 4,960 hectares.
Thermal
CCGT Cost based on G-series 2-on-1 640 5050 Low Low 337 32 15 180–265 15–21 Interior B.C. site.
CCGT Cost based on F-series 1-on-1 225 1760 Low to Med Low to Med 350 33 16 180–265 15–21 Interior B.C. site.
Woodwaste Estimated total developable 12–53 100–420 Med to High Med to High 0 varies varies 150-300 8-20 Land use: varies, typically potential: <15 hectares per site.200-300 MW
Integrated Electricity Plan
p a g e 2 4
to 300 MW of woodwaste potential in B.C. This
incorporates the expectation that the emer-
gence of other value-added uses for the
whitewood component of woodwaste will
affect the future amount of woodwaste avail-
able for electricity generation.
5.2.5 “New Green” Resources
Most of BC Hydro’s energy supply comes from
clean and renewable hydro. There is ongoing
national and international debate with respect
to what resources are considered to be “green.”
BC Hydro’s current working definition is that
new green resources include those which are
clean, are renewable, have low net environ-
mental impacts, are socially responsible and are
licensable. In B.C., some small hydro and wood-
waste projects are expected to fit the
definition, and be available at reasonably
economical prices.
5.2.6 Alternative Technologies
Alternative technologies are resource options
which have costs that are currently significantly
above the wholesale market price for electricity.
These include solar, wind, geothermal, tidal,
and fuel cells. It is recognized that the cost of
some of these resources could decrease as the
technology evolves and some may have
specialty small scale applications. BC Hydro’s
Energy Futures Program monitors the develop-
ment of these technologies and supports
opportunities for their future application in B.C.
For example, the Energy Futures Program
includes "wind prospecting" to improve the
estimated potential and the cost of this
resource in B.C. As the economies of these tech-
nologies improve, BC Hydro will include these
technologies into its ongoing planning process.
5 .3 Supply Resource Ranking
The B.C. energy resources options that could
provide major additions to meet future load
growth are natural gas, coal and large hydro.
The least cost of these is gas-fired combined
cycle combustion turbine technology. Combined
cycle combustion turbines have received broad
acceptance in the industry as the preferred
resource for new generation. This preference
stems from the improvements in their fuel use
efficiency, emission controls and abundance of
natural gas. Combined cycle projects also have
lower capital costs and short construction lead
times relative to other major new resource
options.
There are some small hydro and woodwaste
projects close to being cost competitive with
combined cycle and are considered to have no
greenhouse gas emissions. However, the poten-
tial contribution from these resources is
relatively small and insufficient to supply all of
BC Hydro’s new resource requirements.
Alternative energy technologies are not
currently cost effective for consideration as a
significant supply option for the BC Hydro inte-
grated system.
5.3.1 Resource Cost Uncertainties
Resource planning requires many assumptions
that are subject to uncertainty. Several uncer-
tainties related to future resource costs need to
be considered. As noted, CCGTs have been iden-
tified as a preferred resource option.
Accordingly, potential impacts of gas price
uncertainty and future greenhouse gas policy
measures need to be considered.
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o Vancouver Island Call for Tenders • Regulatory
Home > Planning & Regulatory > Acquiring Power > Customer Generation > Project Updates > Armstrong Woodwaste
Armstrong Woodwaste Cogeneration Plant
Forestry in B.C. creates valuable products for customers around the world. In the process of creating these products however, the unused woodwaste has become almost as valuable as a potential source of energy.
Riverside Forest Products Limited, one of BC Hydro's major industrial customers, is harnessing the power of wood waste, using it to create steam to produce electricity at its Armstrong plant. An initiative that began as an idea primarily for cost-effective on-site generation in 2001, quickly grew into a revenue opportunity for Riverside through BC Hydro's call for green customer-based generation in 2003.
The 20 MW Armstrong cogeneration plant began feeding power into the BC Hydro grid on July 1, 2003, with an agreement to provide approximately 120 GWh of power per year, enough to power about 15,000 homes.
"Through this electricity purchase agreement we can provide BC Hydro's customers with clean electricity provincially, but we can also have a positive environmental impact locally," says Michael Moore, Chief Financial Officer at Riverside. "We have also been able to de-commission our Lumby beehive burner in 2002 which contributed to the reduction of greenhouse gas and diverted wood residue from that facility to Armstrong as fuel for cogeneration."
Last Modified: Jun 15, 2004
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Source: BC Hydro Website: http://www.bchydro.com/planning_regulatory/acquiring_power/customer_generation/project_updates/armstrong_woodwaste.html Viewed 2008
REVIEW OF BC HYDRO'INDUSTRIAL POWER SMART
EXPENDITURES
PREPARED FORBC OLD AGE PENSIONERS ORGANIZATION ET AL.
Marvin Shaffer & Associates Ltdwith the assistance of
Constable Associates Consulting Inc.
April, 2004
Executive Summary
BC Hydro s estimate of conservation potential indicates the amount of cost-effective load displacement or other electricity saving measures that consumersare not expected to undertake on their own. BC Hydro s estimate of industrialconservation potential in 2015/16 represents 32% of the reference case forecastindustrial load. In other words , by BC Hydro s estimates , without any demandside subsidies or other measures , 32% of the industrial load wil be economicallyineffcient-it wouldn' t be required if industr implemented all cost-effectivetechnologies.
Competitive firms do not pass up cost-effective investments in conservation. Thefundamental reason for the large amount of ineffcient electricity consumption inthe industrial sector is the failure of rates to signal users the incremental cost orvalue of the electricity they consume.
BC Hydro sees the large amount of conservation potential as reason to spendhundreds of milions of dollars to ' acquire ' the conservation resource. Its PowerSmart plan, however, fails to consider or address the market failure underlying theindustrial sector potential-something the BC Governent's Energy Policyclearly wants done.
There are major problems with conservation resource acquisition strategies likeBC Hydro is planning. A recent econometric study found that because of selectionbias (free rider problems), savings were on average one fifth (costs per Mwhsaved five times) what utilties reported. Subsidized DSM encourages programparticipants to defer effcient conservation or assert the need for greater subsidythan actually required. Incorporating DSM expenditures into rate base createsperverse incentives for utilities to maximize subsidy and other costs regardless oftheir effectiveness. Economic theory and econometric studies both suggest thatpricing electricity closer to its incremental cost is likely to be far more effectiveefficient and equitable than subsidizing DSM.
BC Hydro s Power Smart plan for the industrial sector is not very effective (alarge percentage of the estimated cost-effective potential wil not be realized) nornecessarily effcient. It certainly is not equitable. Two recent load displacementprojects make clear that subsidized Power Smart projects can impose significantcosts on ratepayers. Based on the market value of the electricity saved, the netloss to ratepayers wil be at least $6.8 milion for the Weyerhaeuser project and$11.1 milion for the Canfor project. The net loss could be as much as $13.milion for the Weyerhaeuser project and $25.0 milion for the Canfor projectgiven the possibility that some of the purchased savings might have been realizedwithout any subsidy. Power Smart subsidies benefit recipients, but at the directexpense of all other ratepayers.
The problem is that the Power Smart plan does not address the fundamentalmarket failure that underlies the sub-optimal levels of load displacement andconservation in the industrial sector.
If effective , effcient and equitable conservation is truly the goal, BC Hydro mustdevelop rate proposals that signal users the incremental costs or value of theelectricity they consume. A simple two tier rate structure wil have some positiveimpact , but it wil be limited by the percentage of its customers ' loads subject tothe tier 2 rate. Alternatives that signal the incremental cost or value of electricityfor all of the customers ' loads, consistent with the BC Governent's energypolicy objectives , would be more effective.
What is required at this time is a rejection of the industrial Power Smartexpenditures in BC Hydro s revenue requirements application, and direction toBC Hydro to develop rate proposals and complementary strategies (faciltatingenergy advisory service and conservation financing) that wil achieve theindustral sector potential in an effcient and equitable manner.
Introduction
BC Hydro s Power Smart-related costs of service are estimated to total $62.5 milion infiscal year 2005 and $69.6 milion in 2006. By 2006 they wil have increased by almost50% since 2003 , an average increase of over 16% per year.
BC Hydro s Power Smart plan calls for $690 milion in new investment over the next tenyears. The amortization of these expenditures and associated costs of capital (interest andallowed return on equity) wil contribute to a continued increase in Power Smart costs ofservice in future years.
A large proportion of this Power Smart investment is to be directed to the industrialsector. BC Hydro s 10 year plan calls for $265 millon to be spent on load displacementand other industrial sector initiatives. This plus a pro-rata share of the $140 milion ofindirect and other portfolio level costs accounts for 48% of the total planned investment. Even if BC Hydro reduces industral sector investments by $60 millon, in accordancewith its preliminary assessment of the implications of stepped rates 3 the industrial sector
initiatives , including a pro-rata share of indirect costs, wil stil account for over 40% ofthe total planned expenditures.
The purpose of this evidence is to assess the rationale, impacts, effciency and equity ofthese expenditures , particularly in the context of the BC Governent's energy policywhich calls for new rate structures to provide incentive for industr to self generate andconserve.
Conservation Potential
Underlying the targets and the level and allocation of expenditures in BC Hydro s PowerSmart plan is its estimate of conservation potential. In its 2002 Conservation PotentialReview 5 BC Hydro reported a total economic potential of 12,462 Gwh by 2015/16. The
most likely achievable ' potential , recognizing barriers to implementation, was estimatedat 5 835 Gwh.
The industrial sector accounts for a large percentage of the estimated conservationpotential-by 2015/16 the industrial sector economic potential is estimated at 5 665 Gwh(some 45% of the total); the most likely achievable potential is estimated at 3 374 Gwh(almost 60% of the total).
It is remarkable how large the estimated conservation potential is in the industrial sector.By definition, conservation potential estimates the difference between the amount of
1 BC Hydro Revenue Requirements Application , Volume 1 , p. 4-2 BC Hydro Revenue Requirements Application, Volume 2 , Appendix I
, p.
21.3 BC Hydro Revenue Requirements Application, Volume 1 , p. 4-4 Policy Action
#21: New rate strctures wil provide better price signals to large electricity consumers forconservation and energy effciency, BC Ministry of Energy, Energy for our Future: A Plan for BC
, p.
33.5 BC Hydro Revenue Requirements Application, Volume 2, Appendix H.
electricity that industry would purchase without any demand side measures (the referencecase forecast load), and the amount industr would purchase if it implemented all cost-effective load displacing or electrcity saving measures. In effect, it is an estimate of theextent of ineffcient electrcity consumption. BC Hydro estimate of industrialconservation potential in 2015/16 represents 32% of the reference case forecast industrialload. In other words , by BC Hydro s estimates , without any demand side subsidies orother measures, 32% of the industral load wil be ineffcient-it wouldn' t be required ifindustr implemented all cost effective technologies.
BC Hydro listed a number of reasons why industrial customers might not implement costeffective load displacing or electricity saving technologies. It suggested industry has toconsider other factors, such as productivity, product quality, maintenance costslegislation and perceived risks. But the industrial sector is not like the commercialsector and certainly not like the residential sector. For the most part, it consists of firmsoperating in globally competitive industries that must minimize their energy and othercosts to survive and grow. This is particularly the case in the energy intensive pulp andpaper industr, which accounts for two-thirds of the industrial sector conservationpotential estimated in BC Hydro s 2002 Review. If a load displacing or electricity savingmeasure is trly cost-effective, it means it would be beneficial to undertake when allfactors including productivity, product quality, maintenance costs , capital costs and risksare taken into account. Successful , competitive firms do not pass up trly cost-effectivetechnologies.
The most fundamental reason why competitive firms in B.C. don t implement cost-effective load displacing or electricity saving measures is the failure of BC Hydroelectricity rates to signal to users the incremental costs or value of the electricity theyconsume-they don t give firms the financial incentive to invest optimally in self-generation or other load reducing measures. The industrial rate currently averages$34/Mwh. For its Power Smart planning, BC Hydro has indicated that the incrementalcost or marginal value of electricity is $55/Mwh. There is a $21/Mwh differencebetween what firms pay and what BC Hydro estimates the electricity is worth.
To BC Hydro , the large estimate of conservation potential is reason to devote hundreds ofperson years of staff time and hundreds of milions of dollars to industrial Power Smartinitiatives. But BC Hydro s Power Smart plan fails to address the fundamental reasonwhy the conservation potential exists. The conservation potential that BC Hydro hasestimated is not a measure of cost-effective conservation; it is a measure of the cost-effective conservation that industr wil not undertake on its own.8 It is a measure of the
failure of the electricity market to promote effcient behaviour-a market failure dueprincipally to rates not reflecting the incremental cost or value of electricity to BC Hydro.
6 Ibid.
, p.
17.7 BC Hydro Revenue Requirements Application , Volume 1 , p. 2-8 BC Hydro does not appear to recognize this very important difference in asserting that the "stepped ratedoes not impact the total economic conservation potential" (Response to BC Old Age Pensioners IR#l
90c). Stepped rates will reduce the total economic conservation potential (the potential requiring subsidy)because it will increase the conservation that industr will undertake on its own.
In its Energy Plan, the BC Governent clearly wants to address this market failure. Thereason it recommends implementation of stepped rates in the industrial sector is to giveconsumers the incentive to undertake conservation and energy effciency and
provide an incentive for large industrial or transmission rate customers to purchase fromIPPs or to self generate when they can do so less expensively than the utilty s cost ofnew supp y
BC Hydro s 2002 Conservation Potential Review and its 10 year plan did not considerthe impact of stepped rates or any pricing initiative that would better signal users theincremental cost or value of the electricity they consume. 10 Power Smart has not studiedthe effect that fallng real electrcity prices over the last decade have had on electricityconsumption, and the extent to which ineffcient pricing underlies the conservationproblem it is trying to address. Power Smart has not developed any report orrecommendations on how stepped rates could be implemented to maximize the incentiveto conserve, and furher reduce the need for staff and subsidy. ll For these reasons alone
the Review and Plan do not provide a reasonable or justifiable basis to commit to thelevels of expenditue in BC Hydro s Application.
Resource Acquisition versus Pricing Strategies
The provision of incentives and other support in BC Hydro s 10 year Power Smart plan isa classic planners ' approach to conservation. Conservation potential is viewed as aresource to be acquired much like new sources of supply.
The purchase of conservation is not, however, the same as acquiring a new source ofsupply. Conservation reduces BC Hydro s obligation to serve the displaced or otherwisereduced load. But the benefit of that to the utilty and its remaining customer load is notthe cost it would otherwise incur for incremental supply-it is the difference between thecost of incremental supply and the amount BC Hydro would have charged for it. 12 That
benefit only exists to the extent that rates do not reflect the incremental cost or value ofelectricity supply.
In a number of U. S. jurisdictions where restructuring has caused electricity markets tobecome more competitive and rates more reflective of the incremental cost or marketvalue of electricity, there has been a shift away ftom resource acquisition strategies.Utilties have neither the same abilty nor incentive to subsidize or ' purchase
9 BC Ministry of Energy, Energy for our Future: A Plan for BC
, p.
24 and 30.10 Response to IPPBC IR#I , 1.3. 1 and 133.11 Response to BC Old Age Pensioners IR#I , 1.90b.12 In a news release announcing an $18 million load displacement initiative in Kamloops , BC HydroSenior Vice President of Distribution was quoted as saying that its investment "provides a benefit-cost ratioof greater than 3: 1" . Similar and higher utility benefit-cost ratios are asserted in BC Hydro s Applicationbased on its estimate of the cost per Mwh of load displaced in relation to its estimate of the cost of newsupply. However, those benefit-cost ratios are grossly misleading. They misrepresent and greatly overstatethe benefit that BC Hydro (and its remaining customer load) actually realize.
conservation. 13 It is not just that competition has undermined the viability of utilitydemand side expenditues, it has reduced the justification for them. 14
In restrcturedmarkets where there is a non-avoidable charge to support conservation, the emphasis hasshifted to market transformation strategies-strategies aimed at eliminating barrers andencouraging the development of energy efficient products and viable energy servicecompanies. 15
In marked contrast to BC Hydro s Power Smart plan, the goal is long termmarket and behavioural change as opposed to immediate purchases of savings.
There are major reservations about subsidy-based demand side resource acquisitionstrategies. A number of studies conclude they are not nearly as effective or effcient asBC Hydro s plan would suggest.
A recent econometrc study used cross sectional and time series data for a large numberof U. S. utilties to estimate the impact of DSM expenditures on energy intensity. Thestatistically observed impact was roughly one-fifth what the utilties ' reported DSMsavings would suggest. As compared to an average utility estimate of $29 for the cost perMwh saved, the econometric results indicated costs of between $140 and $220 per Mwhsaved. 16 The authors attributed this to the selection bias or fTee rider problem being muchgreater than assumed in most utility evaluations. Consistent with previous studies , theyconcluded that much of the DSM subsidies were going to firms and households thatwould have undertaken effciency investments even without the program.
In his critique ofresource acquisition strategies , F. Wirl points out that the pool of DSMprogram participants is not a random sample , but rather is dominated by the householdsand firms closest to making effciency investments. They are the group that wil be mostattracted to subsidy programs , yet the most likely to have made some investment withoutthe programs. The comparson to non-participating control groups that utilities typicallyuse to estimate savings doesn t recognize this fact. Wirl also points out that the provisionof conservation subsidies in itself creates a 'moral hazard' problem. It encouragespotential program participants to strategically defer effcient conservation investments orassert the need for subsidy beyond what is really required. Also , for utilities that can
13 Similarly, in the BC natural gas sector, Terasen does not subsidize conservation. With gas commodityrates reflecting their market value, such subsidies would simply benefit the subsidy recipients at theexpense of all other ratepayers.14 See T. Brennan
, "
Demand Side Management Programs Under Retail Competition , Resources for theFuture Discussion paper 99- , October, 1998.15 See C. Blumstein et. aI.
, "
Who Should Administer Energy-Effciency Programs?", University ofCalifornia Centre for the Study of Energy Markets , Aug. , 2003.16 D. Loughren and 1. Kulick
, "
Demand-Side Management and Energy Efficiency in the United StatesEnergy Journal , 2004, Volume 25, No.
, pp.
19-43.17 Loughren and Kulick note that Train s analysis of industral DSM offered by Southern California Edisonin 1983 ("Incentives for Energy Conservation in the Commercial and Industrial Sectors , The EnergyJournal Vol. 9, No 13
, p.
I13- 128) implies "about 70% ofreported energy savings would have occurred inthe absence of DSM participation . Ibid.
, p.
23. They also note that Waldman and Ozog reached a similarconclusion in their study of DSM expenditures in midwest utilities (Southern Economic Journal 62(4),1996. pp.1 054- 1071).
incorporate DSM spending in their rate base, it can create a perverse incentive tomaximize spending for conservation regardless of its impact.
In its response to a recent Ontario Energy Board report on DSM, Ontario s Energy Probealso questioned the effectiveness of DSM subsidies. It noted that subsidized DSM can becounter productive by slowing the rate at which consumers would of their own accordinvest in conservation and by increasing purchases and use of energy-using appliances.Citing the results of a Gas Research Institute study on energy use by jursdiction, EnergyProbe stated that the available information suggests that gas DSM programs may havehelped Ontario from keeping up with the conservation improvements in neighbouring
" 19JUrlS lctlOns .
Economic theory and econometric analysis both suggest that measures that correctfudamental market failures are likely to be more effective, effcient and equitable thanresource acquisition subsidy programs. As one economist wrote It is important to keepin mind that (subsidizing) DSM is an inferior ' second best ' tool to policies that wouldbring electricity prices closer to marginal cost . 20 Providing appropriate price signalsavoids the selection bias , moral hazard and rebound effects of subsidized DSM. Iteliminates the need for project applications, negotiations and other basically wastefulbureaucracy. And it allows industr to do what it can do best-to effciently minimize itspurchases and use of electricity.
With respect to effectiveness , it is instrctive to note that the hundreds of milions ofdollars of incentives and other expenditues in BC Hydro s Power Smart plan arenexpected to capture all of the economic potential or even all of the 'most likelyachievable ' potential. By BC Hydro s estimates , even if the industrial sector expendituessucceed in achieving their target savings, almost 25% of the estimated conservationpotential in the industral sector in 2015/16 won t be realized.
Effciency and Equity-- Impacts of Two Recent Load Displacement Projects
In 2003 , BC Hydro announced two large Power Smart-subsidized load displacementprojects: an $18 milion contribution to Weyerhaeuser to support the installation of a 30MW turbo-generator at its Kamloops pulp mil (displacing 155 GWh of load per year forten years), and a $49 milion contribution to Canfor to support the installation of a 48MW turbo-generator at its Prince George pulp mil (displacing 390 GWh ofload per yearfor fifteen years).
18 F. Wirl
, "
Lessons from Utility Conservation Programs , Energy Journal , 2000 , Vol 21
, pp.
87- 108.19 Energy Probe s Analysis of ' Demand Side Management and Demand Response in the Ontario Electricity
Sector: Report of the Ontario Energy Board to the Minister of Energy , March 1 2004.20 T. Brennan
, "
Demand Side Management Programs Under Retail Competition , Resources for the FutureDiscussion paper 99- , October, 1998
, p.
15.21 By Hydro
s estimates , the unrealized conservation potential in the industrial sector in 2015/16 will be5665- 1818 = 3847 Gwh. The forecast load, taking the estimated savings into account will be 17821-1818=16003 Gwh.
The Weyerhaeuser Kamloops project has been discussed for years. Weyerhaeuserpurchased a refurbished 30 MW turbo-generator some time ago. The Power Smartincentive made the project suffciently attractive to proceed and it is now nearingcompletion. The Canfor Prince George project has also been discussed for some time.Canfor submitted the project to the 2002 Customer-Based Generation Call 22 but the
project was not short-listed. Now with the Power Smart incentive, the project is underconstrction.
BC Hydro justified the large subsidies for these projects on the basis of its estimates oftheir total resource cost, utility cost and ratepayer impact. BC Hydro stated that theseprojects are effcient (their total resource costs are less than the $55/Mwh it assumes forthe cost of alternative sources of electricity), their utility cost (ignoring lost revenues) areapproximately $ 15/Mwh and the impact on the ratepayers (the remaining load) ispositive , with a ratepayer impact (RIM) benefit-cost ratio for Canfor of 1.4.
BC Hydro did not provide detailed evaluations in support of these statements. Howeverthe utilty cost and ratepayer impacts can be roughly replicated based on an avoided costof $55/Mwh, an industrial rate averaging $36/Mwh and an assumed timing of thepayments and load displacement as shown in Appendix A. The total and levelized costand ratepayer impacts under those assumptions are shown in Table 1 below. Theyindicate levelized utilty costs of $17/Mwh and a ratepayer benefit cost-ratio of 1. 1 forWeyerhaeuser, and utility costs of $ 14/Mwh and a ratepayer benefit-cost ratio of 1.35 forCanfor.
Table 1
Benefits and Costs -- BCH Case(2003 NPV at 6% real, levelized value per Mwh in italics)
Weyerhaeuser Canfor
Utilty Cost (including $18 960 000 $51 610 000provision for overhead) $17. $14.Avoided Cost $60 970 000 $202,430 000
$55. $55.Lost Revenue $39 910 000 $132 500 000
$36. $36.
Ratepayer Net Benefit 100,000 $18,320 000$1. 90 $4.
RIM Benefit-Cost Ratio 1.11
22 See www.bchvdro.com/rx fies/info/inf03286.pdf.23 The utility cost and cost of alternative supply estimates are provided in the press releases announcing theprojects. The ratepayer benefit cost ratio is provided in Response to BC Old Age Pensioners IR#I1.89.0(b).
The problem with the assumptions required to replicate BC Hydro s results , however, isthat they overstate the benefit of the power that is displaced and ignore the possibilty thatWeyerhaeuser and Canfor would have instituted some conservation measures or installedthe turbo-generators without subsidies at some point in the future.
An objective measure of the avoided cost or value of incremental supply is the Mid-Columbia market price. This is the measure which BC Hydro has contractually agreed touse to calculate liquidated damages should Weyerhaeuser or Canfor use their projects toobtain market sales instead of supplying the savings to BC Hydr0 . It indicates the
amount BC Hydro could expect to pay to acquire additional supply or realize from themarketing of any additional surplus. As shown in Appendix B , BC Hydro s forecast ofthese prices , assuming a 2% inflation rate, suggests a real (2003$) levelized value of$47/Mwh for the flat profie of savings offered by these projects.
The Mid-Columbia price overstates the value of electricity supply in Prince George andKamloops. There are greater transmission costs and losses to deliver power from theselocations to BC Hydro s domestic load or market centres than from the Mid-Columbiaregion. As well, contractual provisions in the load displacement agreements allowing fora ' load balancing account' diminish the certainty of its supply at any time and its valuecompared to a firm purchase at Mid-Columbia. Nevertheless the Mid-Columbia priceforecast does provide a more accurate and objective estimate of the benefit of the loaddisplacement projects than the $55/Mwh that BC Hydro used.
In Table 2 below, the effect of basing avoided costs on the Mid-Columbia price forecastis shown. The results indicate significant net losses to ratepayers for both projects. Thenet loss for the Weyerhaeuser project is $6.8 milion; for Canfor the net loss is over $11milion. The reason for the net loss is clear. Based on the cost or value of power availablein the market, the benefit of the load displacement to BC Hydro and its remainingcustomer load is only $l1/Mwh, but BC Hydro is contrbuting $14 to $17 per Mwh toachieve it.
24 Response to BC Old Age Pensioners IR#I , 1.89.0e.25 Response to BCUC IR 1.2.23.26 It should also be noted that BC Hydro s $55 avoided cost estimate is a nominal value (Response to SierraClub IR#2.24.0). It is therefore not the appropriate figure to compare to a $36/Mwh industral rate tocalculate the benefit of load displacement. The $36 rate is expressed in real (2003$) terms. In nominalterms the industrial rate wil be $37/Mwh by 2005 if the rate application is approved, and can be expectedto increase at least with the rate of inflation as BC Hydro rolls in high cost sources of supply. As shown inAppendix B, adjusting BC Hydro s forecast of the costs of new supply for inflation yields an equivalent2003$ levelized value of approximately $49.60/Mwh, far less than the $55 required to replicate BCHydro s results.
Table 2
Benefits and Costs Based on Mid Columbia Market Value of Electricity(2003 NPV at 6% real , levelized value per Mwh in italics)
Weyerhaeuser Canfor
Utilty Cost (including $18 960 000 $51 610 000provision for overhead) $17. $14.Avoided Cost $52 100 000 $172 990 000
$47. $47.Lost Revenue $39 910 000 $132 500 000
$36. $36.
Ratepayer Net Benefit ($6,770,000) ($11 130 000)($6. 10) ($3. 02)
RIM Benefit-Cost Ratio
BC Hydro s evaluation assumes that without the subsidy, Weyerhaeuser and Canforwould not have implemented conservation measures on their own, even though understepped rates they would have had to pay the tier 2 market price for at least some portionof their purchases. That is not a reasonable assumption.
The pulp and paper sector has been identified by Power Smart as fertile ground forenergy conservation. As well , in the National Climate Change context the pulp and paperindustr has undertaken to reduce its greenhouse gas (GHG) emissions intensity by anaverage of 15 percent by 2008 to 2012 , the first Kyoto commitment period.
In Table 3 below, it is assumed that without the load displacement subsidiesWeyerhaeuser and Canfor would have implemented some conservation measures andreduced its electricity purchases by 10%. The net loss to ratepayers in this case increasesto almost $8 milion for Weyerhaeuser and over $15 milion for the Canfor project. Thereason for the increase in the net loss is that the cost per unit of savings increases. BCHydro is essentially paying for savings that would have occurred to some extent withoutthe subsidy.
27 Government of Canada and Canadian Pulp and Paper Industry Agree on Blueprint for Climate ChangeAction Government of Canada, Press release, November 6 2003.
Table 3
Benefits and Costs with 10% Conservation(2003 NPV at 6% real, levelized value per Mwh in italics)
Weyerhaeuser Canfor
Utilty Cost (including $18 960 000 $51 610 000provision for overhead) $19. $15.Avoided Cost $46 890 000 $155 690 000
$47. $47.Lost Revenue $35 920 000 $119 250 000
$36. $36.
Ratepayer Net Benefit ($7,990,000) ($15 170,000)($8. 73) ($4. 58)
RIM Benefit-Cost Ratio
Not only could Weyerhaeuser and Canfor have implemented some conservation withoutthe subsidy, particularly for that portion of their load subject to tier 2 rates , it is possiblethey would have installed turbo-generators on their own at some later date. With risingBC Hydro rates , greater access to domestic markets , and some already sunk costs , theprojects might have proven economic in the foreseeable futue.
In Table 4 below, the implications of Weyerhaeuser otherwise installng a turbo-generator in 2009 and Canfor otherwise installng a turbo-generator in 2013 are shown.This net loss to ratepayers increases to over $13 milion for the Weyerhaeuser project andover $25 millon for Canfor. As in the previous case the reason for the losses is that BCHydro is paying for savings that would otherwise have occurred. There are , of coursemajor benefits to Weyerhaeuser and Canfor from the Power Smart subsidies , but theycome at the direct expense of all other ratepayers.
Table 4
Benefits and Costs with Future Unsubsidized Load Displacement(2003 NPV at 6% real, levelized value per Mwh in italics)
Weyerhaeuser Canfor
Utility Cost (including $18 960 000 $51 610 000provision for overhead) $36. $21.Avoided Cost $24 530 000 $113 640 000
$47. $47.Lost Revenue $18 790 000 $87 040 000
$36. $36.
Ratepayer Net Benefit ($13 220 000) ($25 020,000)(25.33) (10.35)
RIM Benefit-Cost Ratio
It is possible that the Weyerhaeuser and Canfor projects are effcient-that they are lesscostly than alternative sources of supply. The test, however, is whether Weyerhaeuserand Canfor would have undertaken those projects without subsidy if they had to pay theincremental cost or value of the electricity they purchased from BC Hydro. Under thecurrent pricing regime , one simply cannot be certain what Weyerhaeuser and Canfortaking all factors including non-electricity benefits and costs into account, would have infact done.
One thing is certain. The BC Hydro contributions in support of those projects areinequitable to ratepayers. There are very significant net losses to BC Hydro and itsremaining customer load, recognizing the market value of the displaced load plus thepossibilty that some of the savings might have been realized without any subsidy.
The contributions are also inequitable to alternative potential suppliers of electricity. Theprojects were not subject to the same competitive bidding process or the same contractualterms as alternative suppliers. The amount of electricity they in fact provide is much lesscertain and relative ranking very unclear.
Alternative Conservation Strategies
There is a clear environmental and economic interest in promoting conservation. Theissue isn t whether to be 'power smart' the issue is how that can be done in the mosteffective , effcient and equitable manner.
BC Hydro s Power Smart plan for the industrial sector is not very effective (a largepercentage of the estimated cost-effective potential wil not be realized) nor necessarilyeffcient. It certainly is not equitable. The problem is that the plan does not address the
fundamental market failure that underlies the sub-optimal levels of load displacement andconservation investment in the industrial sector.
If effective , efficient and equitable conservation is trly the goal, BC Hydro must developrate proposals that signal users the incremental costs or value of the electricity theyconsume. A simple two tier rate structure wil have some positive impact, but it wil belimited by the percentage of customers' loads subject to the tier 2 rate. A fullcommitment to conservation requires the right price signal for all of the customers ' loads.
There are different ways that industrial rates can be strctued to fully promoteconservation, yet stil be sensitive to the governent's policy objective of distributingbenefits of low cost heritage supply to electricity consumers. For example , a basic fixedcharge reflecting each industry or customer s base year energy intensity could beestablished, with the final bil adjusted for differences between actual and baseconsumption priced at the incremental cost or value of electricity. Base year energy usepatterns could be used to define variations by time of day and season in order toincorporate real time pricing of electrcity consumed or saved. Negative customercharges could be another option to consider. In any case the key is to distrbute the shareof the heritage benefit (the difference between incremental cost or value of electricityconsumed and revenue requirements) independently of the load displacement orconservation decisions customers make.
separate hearing wil be held to address BC Hydro s rate strcture. However, BCHydro s expenditure plans for Power Smart, a rapidly growing component of its revenuerequirements , cannot be properly reviewed without considering the way in which BCHydro plans to implement more effcient rates in keeping with the intent of the BCGovernent' s Energy Policy.
What is required at this time is a rejection of the industrial Power Smart expenditures inBC Hydro s current revenue requirements application, and direction to BC Hydro todevelop rate proposals and complementary strategies (facilitating energy service andconservation financing) that wil achieve the industrial sector potential in an effcient andequitable manner.
Appendix A
Impact Assumptions and Calculations forWeyerhaeuser and CanforLoad Displacement Projects
Weyerhaeuser s Kamloops Project
BC Hydro announced on January 15 , 2003 that it was making a Power Smart incentivepayment to Weyerhaeuser to support a load displacement project at WeyerhaeuserKamloops pulp mill. BC Hydro agreed to contribute $18.0 milion dollars toward the$34.8 milion 30 MW turbo-generator project. The tubo-generator wil produce 155GWh per year, making the mil self-suffcient with respect to electrcity use.Weyerhaeuser is committed to using the power to displace domestic load for a period often years under the load displacement agreement.
Table A- I is an analysis of the cost and ratepayer impacts of the Kamloops project basedon information in the BC Hydro press release and BC Hydro responses to InformationRequests for the Revenue Requirements Hearing.
Table A- I assumptions:
Base Case (BC Hydro)Discount rate - 6% real.
. BC Hydro contribution: $18 000 000 , paid 25% in 2003 , remainder in 2004.10% added to BC Hydro contribution to estimate total 2003$ cost, includingprovision for overheads and adjustment for inflation.Project assumed to be in service July 1 , 2004 - 77.5 GWh of load displaced in2004 , 155.0 GWh in 2005 through 2013 , and 77.5 GWh in 2014.Avoided Cost based on levelized cost of new generation of$55/MWh.Lost Revenues based on 2003$ levelized average industrial rate estimated at$36.00/MWh.
. RIM test: Avoided Cost minus Lost Revenue divided by BC Hydro Utilty Cost.
Case 1 - Avoided Cost based on Mid-Columbia price forecast (a 2003$levelized value $47/MWh)
Case 2 - 10 percent conservation would have occurred without subsidyLoad displaced reduced by 10%, commencing in 2004.
Case 3 - Load displacement would have occurred in 5 years without subsidyLoad displacement due to the subsidy reduced to zero in 2009 and followingyears.
!Table 11.
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Canfor s Prince George Project
BC Hydro announced on October 31 , 2003 that it was making a Power Smart incentivepayment to Canadian Forest Products Ltd. (Canfor) to support an upgrade to its PrinceGeorge Pulp and Paper mil to provide all the electricity needs of that mil plus itsIntercontinental Pulp mil. BC Hydro agreed to contribute $49.0 milion dollars towardthe $81.0 milion project. The project wil entail the installation of a 49 MW turbo-generator that wil produce 390 GWh per year, making the two Prince George-area pulpmils self-suffcient with respect to electricity use. Canfor is committed to using thepower to displace domestic load for a period of fifteen years under the load displacementagreement.
Table A-2 is an analysis of the cost and ratepayer impacts of the Prince George projectbased on information in the BC Hydro press release and Information Requests to BCHydro for the Revenue Requirements Hearing.
Table A-2 assumptions:
Base Case (BC Hydro)Discount rate - 6% real.
. BC Hydro contribution: $49 000 000 , paid 25% in 2004, remainder in 2005.10% added to BC Hydro contribution to estimate total 2003$ cost, includingprovision for overheads and adjustment for inflation.Project assumed to be in service July 1 , 2005 - 195 GWh of load displaced in2005 390 GWh in 2006 through 2018 , and 195 GWh in 2019.Avoided Cost based on levelized cost of new generation of$55/MWh.Lost Revenues based on 2003$ levelized average industral rate estimated $36.00/MWh.
. RIM test is: Avoided Cost minus Lost Revenue divided by BC Hydro UtilityCost.
Case 1 - Avoided Cost based on Mid-Columbia price forecast (a 2003$ levelized value of$47/MWh)
Case 2 - 10 percent conservation would have occurred without subsidyLoad Displaced reduced by 10% , commencing in 2005.
Case 3 - Load Displacement would have occurred in 10 years without subsidyLoad displacement due to the subsidy reduced to zero in 2014 and followingyears.
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Appendix B
BC Hydro Forecasts of Mid Columbia Priceand Cost of New SuppIy
(Cdn$/Mwh)
Year Mid- Mid- Cost of New Cost of New
Nominal (2003$) Supply (Nom. Supply (2003$)
2004 50. 49. 55. 53.2005 50. 48. 54. 52.2006 50. 47. 55. 52.2007 48. 44. 53. 50.2008 45. 41.2 53. 48.2009 48. 43.1 53. 47.2010 51.8 45. 54. 47.2011 55.4 47.3 54. 46.2012 58. 49. 55.4 46.42013 62. 51.4 56. 45.
Equivalent2003$ levelized 46. 49.
value
28 Response to BCUC IR #1.2.23. Average price assumes 57%-43% HLH-LLH split. Inflation assumed toaverage 2% per year.29 Response to Sierra Club IR #2.24.30 Calculated over the 2004-2013 period at a 6% real discount rate.
Energy Resources Division
In the northeast plains aa, delineationdrilling in the Ring Field increased potentialgas reserves. Significant Slave Point andJean Marie gas reserves additions wed alsomade in the Hossitl and Helmet North Fieldareas.
Evaluaticm continued c.” the large landblock assembled in the area southwest ofFort St. John by partners ESSCI, CanadianHunter and Bow Valley Industries. Asig”ificant amount of new geophysicalacquisition and drtlling activity isanticipated for this area in 1990.
In the British Columbia interior, theGeological Survey of Canada, t”consultattcm with Minishy petroleumgeologtcal staff, conducted geoscientificstudies in both the Bowser and NechakoBasin areas. This work is focussed in parton determination of the hydmcarbonpotenttal of these areas.
Interest in geothermal activity was alsorevived in ftscal 1989/90. This led tore-evaluation of the commerctal potential ofthe geothermal rwources of the Meager
The Electricity Industry 1989/90
Creek area; commencement of drilling of ageothermal research well at Summerland bythe Okanagan-Sbnilkameen CommunityFutuxw Association; and expressions ofinterest in disposition of geothermal tenurein the Terrace area. In addttion, the Ministryacquired a” &en&e collectton ofgeothemal core obtained durtng B.C.Hydm’s 1974/75 drilling program in theMeager Creek area. This materkd is storedand available for examination at the CharlteLake field office.
The Ministry also participated in theWorld Energy COXI~PZSS in Mont”?al inSeptember 1989. Following the Congress,three separate delegate field tows visitedBritish Columbia energy projects.
The Ministry continued to supportenvironmentally sustainable economicdevelopment through participation in thehighly successful GLOBE ‘9tl Confavnce,held in Vancouver in March 1990. Planningassistance, funding, speakers, guides andexhibit materials were pmvided to theconference.
The pmvtncial elechicity strategycontinued to provide a framework for thedevelopment and use of the Province’selectricity “zsources. This strategyemphasizes planning and conservationinitiatives which promote a tnore efficientuse of &sting resources, delaying the needfor new higher cost generation pmjects.
As part of this strategy, a new electricitypricing policy was developed to providepricing signals whtch wtll encourageconservation. In setting B.C. Hydm’selectricity rates, the Province directed theBCUC to ensure that rate increases aresmooth, stable and predictable, contrtbute toconservation and efficient electricity use andmeet minimum financial standards.
5
Energy Resources Division
In response to this p&q, B.C. Hydmsubmitted a rate appIication to the BCUC.On AprtI 30,1990, the BCLJC approved rateincreases of three per cent effectiveNovember 15,1989 and 1.5 per cent onApriI 1,199O and cm AprII 1,199l.B.C. Hydra pIans to apply to the BCUC forapproval to m&wtu~ rates so thatconservation and efficient we of paver isrewarded.
B.C. Hydm is new required to paysurplus revenues to the Provtnce in order toencourage operational efficiency and toprovide a return on pubIic investment inthe Corp&tion. The amount paid wiIIreflect B.C. Hydm’s current fhwmciaIsihaadon. Some portton of surpIus revenuewill continue to go towards the payment ofdebt. Once the buIIding of new projectsraises B.C. Hydra’s costs, payments togovernment wiII de&w.
In January 1990, the Province announcedthat the Canadian entitlement to theColumbia River downstream benefits wouldbe repatriated as they become avaiIable.Starting in 1998, the United States mustreturn “free of charge” this low-cost,environmentally clean resamx to theBritish Columbia border. This may d&y theneed to build new generation capacity inBritish Cohunbia by hvo to three years. TheProvince is now in the initial stages ofdeveloping the struchxe under which thereturn of the downstream benefits wiII benegotiated with the United States.
The &chicity strategy also emphasizesincreased competition. In consultation withthe Province, B.C. Hydm has developed awheeling policy which aIIows independentpower producers access to the pmvhwiaItransmission system. Such access is an
6
important element in increasIng competitionh the elechicity indushy since it aIlcwsproducers to sell power directly ,to theircustomers.
B.C. Hydm wiII continue to issuepmposaI caIIs for~independent producersinterested h supplying power to theB.C. Hydm integrated system, or tonon-integrated areas presendy served byB.C. Hydm diesel, operations. Agwements inprincipIe have now been reached withNW Energy Corp. for a 55 megawattwoodwaste-fIred project in Williams Lake,and with Westcoast Energy Inc. andC.U. Power for a 105 m*gawatt gas-f&dco-generation pmject at Taylor, near Fort St.John. The WiIIiams Lake pmject &ninatesthe use of beehive burners for the disposalof woodwaste.
In recognition of the environmentalbenefits which may be associated withindependent power pmjects, B.C. Hydra,at the Province’s direction, may pay apremium of up to 15 per cent for energyfrom developments which result in asig&f+nt impmeement in IocaIenvironmental conditions external to thepower faciIity.
In October 1989 B.C. Hydra and HoweSound Pulp and Paper Limited announcedan agreement whwby B.C. Hydm wiIIprovide financiaI assistance by way of a$108 miIIion interest-free loan, nzpayable in1995, for the construction of a 85 megawattgenerating faciIity. The project will aIspmvide significant environmental benefitsby utiII.zing woodwaste that is currentlybeing disposed of in IandfiIls or inctneratedin beehive burners.
Energy Resources Division
The new generating facility wlIl supply70 per cent of the mlll’s ebxtricity needs;the balance will be purchased from B.C.Hydm. The qqeement will provideeconomic benefits to both B.C. Hydra andHowe Sound Pulp and Paper. Within theframework of B.C. Hydm’s LoadDisplacement Pmgram, industry is beingencouraged to install its own &chicalgeneration capacity, enabling B.C. Hydm todefer construction of new facilities.
Major &&i&y users in BritishColumbia will also have an opportunity topurchase short term, interruptible power atcompetitive market prices under a new
Energy Projects in Review
Energy project review activity imxased Energy Corporation, whose intists are insignificantly during the year. the Meager Creek area near Pemberton.
Seventeen proposals were submitted inrespc~nse to B.C. Hydm’s pmpc~sal call fordomestic electricity supply.
B.C. Hydm’s request for pmposals forprojects of lass than five megawatts resultedin the submission of 14 small hydmptiposals. Energy Project CertificateApplications (EpCAs) a~ expected from allsuccessful proponents by early 1991.
In anticipation of future B.C. Hydmproposal calls, Forest Fuels Inc. (Midwaywoodwaste) submitted a Pmspech~s andWeyerhaeuser Canada Ltd. briefed theMinistry on its plans for a co-generationfaclllty at its Kamloops pulp mill.
In the spring of 1990, BC. Hydm alsoissued a proposal call for a geothermaldemonstration project. Several companiestvsponded, including Canadian Crew
POWEREX also received 17 pmposals asa result of their caU for proposals for exportprojects. Five of these proponents enteradnegotiations for export contracts andattended preliminq meetings withgovernment. Formal EpCAs are expectedfrom proponents in late 1990 or early 1991.
powa* pooling arrangement beingdeveloped by the B.C. Power ExportCorporation (POWEREX). This initiativeshould lead to further growth andimproved efficiencies in the industxy.
POWEREX continued negotiations withthe Bonneville Power Administration toimprove access to their transmission systemto facilitate firm power exports byindependent producers to the United States.Discussions are also underway with twoPacific Northwest utlllties c&xx&g theconstruction of additional lmnsmissioncapacity to facilitate exports.
b 7
Energy Resources Division
In addition, there was an hxrease inactivity h the exploration and pmdwtion 01natural gas in northeastern BritishColumbia. This resulted ln an increasedneed for gas plants in the northeasternregion of the I’rovhvx to process anddeliver natural gas to domestic and exportmarkets.
In 1989/90 there were sb~ EpCAsreviewed and appmved by the Ministers ofEnergy and Environment. One was for the
Energy Policy Initiatives
The government has identified fourcentral and inter-n&ted themes for energypolicy in the 1990s. The first hvo themes,Efficient Energy and Clean Energy, reflectour new priorities. The second two themes,Secure Energy and Energy for the Economy,are continuing goals from the early 19BOs.
Efficient Energy: Cutting energy wastelowers crmsumer energy bills, benefitsthe environment, and makes BritishColumbia industry tnore competitive.
Clean Enew Shifting to cleaner fuels andreducing the environmentaJ impacts ofenergy supply and use wiIl help thequality of our air, water, and othernatLIla reso”rces.
,Vancouver Island natural gas pipeline andthe remaining five were for gas processingplants.
In addition, B.C. Hydm’s Williston-KelIyLake 500 ktlovolt transmIssIon line EPCAwas referred to the BCUC; B.C. Hydra wassubsequently issued a Certificate of PublicConvenience and Necessity for the project.
Secure Energy: Managing existing ~~owceseffectively, finding new sources ofsupply, incw.sing fuel choice forconsumers, and maintaining the qualityand quantity of energy supplies willensun long-term energy security forthe Protince.
Energy for the Economy: Developingenergy resources acmss British Columbiawill stimulate regional growth and bringeconomic benefits to the Pmvince asa whole.
In 1990/91, the Ministry will bereleasing an energy policy documententitled “New Directions for the 1990s”which describes a number of current,initiatives h energy policy as .well as sanechanging issues and initiatives for thedecade ahead.
2004
AnnualReport
TRANSCANADA POWER, L.P.
POWER PLANT STATISTICS
* HRSG is a heat recovery steam generator.** with option exercisable in 2022 and every five years thereafter
for power purchaser to buy the facility or extend the contract.*** these facilities were repowered in 1986.
FINANCIAL HIGHLIGHTS
Year ended December 31 2004 2003
Power Generated (GWh) 2,419 2,153
Weighted Average Plant Availability 97% 96%
Net Income (millions of dollars) 100.7 64.4
Per Unit $ 2.25 $ 1.64
Funds Generated from Operations (millions of dollars) 128.2 99.6
Per Unit $ 2.87 $ 2.53
Cash Distributions (millions of dollars) 114.4 99.1
Per Unit $ 2.52 $ 2.52
Capital Expenditures 14.6 8.2
MAJOR PARTNERSHIP COMMERCIAL POWER SALES FUEL PURCHASECAPACITY LOCATION CONFIGURATION EQUIPMENT* ACQUISITION OPERATIONS CONTRACT CONTRACT
Calstock 35 MW Located on a Enhanced 1 wood waste 1998 2000 20-year term Wood waste supply 55-acre site biomass boiler; 35 MW expiring in agreements with localnear Hearst, wood waste steam turbine; 2020 mills for 20-year termsOntario generation 2 HRSGs expiring in 2019 and
1 mill expiring in 2012
Castleton 64 MW Located on a Combined- 40 MW gas 1999 1992 9-year term No fuel risk. 3-acre lease cycle turbine; 25 MW expiring in Partnership pays a fixed in Castleton-on- gas-fired steam turbine; 2008 demand charge under Hudson, New York generation 1 HRSG management agreement.
Curtis 60 MW Located on the Hydroelectric 7 turbines 2004 1986*** 42-year term Not applicablePalmer Hudson River impoundment expiring in
near Corinth, and run-of-river 2027New York
Kapuskasing 40 MW Located on a Enhanced 25 MW gas 1997 1997 20-year term Gas supply agreements 14-acre site in combined turbine; 31 MW expiring in for 20-year term Kapuskasing, cycle gas fired steam turbine; 2017 or expiring in 2016Ontario generation 3 HRSGs delivery of
10,000 GWh
Mamquam 50 MW Located on the Hydroelectric 2 turbines 2004 1996 30-year term Not applicableMamquam River run-of-river expiring in 50 km north 2027**of Vancouver,British Columbia
ManChief 300 MW Located on a Simple-cycle 2 gas turbines 2004 2000 11-year term Not applicable as the10-acre site gas fired expiring in the power buyer provides near Brush, generation 2012 the fuel requirementsColorado
Nipigon 40 MW Located on Enhanced 22 MW gas 1997 1992 20-year term Gas supply agreements a 7-acre site combined turbine; 18 MW expiring in for 21-year terms near Nipigon, cycle gas fired steam turbine; 2012 expiring in 2010 and Ontario generation 3 HRSGs 2012 respectively
North Bay 40 MW Located on a Enhanced 25 MW gas 1997 1997 20-year term Gas supply agreement 16-acre site near combined turbine; 31 MW expiring in with 20-year term North Bay, cycle gas fired steam turbine; 2017 expiring in 2016Ontario generation 2 HRSGs
Queen 6 MW Located on Hydroelectric 3 turbines 2004 1990 22-year term Not applicableCharlotte Moresby Island, reservoir-based expiring in
British Columbia 2022
Tunis 43 MW Located on an Enhanced 41 MW gas 1998 1995 20-year term Gas supply agreements 11-acre site near combined turbine; 19 MW expiring in with 15-year term Iroquois Falls, cycle gas fired steam turbine; 2014 expiring in 2009Ontario generation 3 HRSGs
Williams 66 MW Located on a Biomass 1 wood waste 1999 1993 25-year term Wood waste supply Lake 31-acre site in wood waste boiler 66 MW expiring in agreements with local
Williams Lake, generation steam turbine 2018 mills for 25 years expiring British Columbia in 2017 and 1 mill
expiring in 2009. Costrecovery mechanism inpower sales contract.
1TRANSCANADA POWER, L .P.
Each of the Partnership’s 11 power plants has long-term PPAs. These PPAs, combined with long-term fueland operating contracts, reduce the financial risk tounitholders, minimize commodity price risk and increasethe stability and security of long-term cash flows.
Output from the Ontario power plants is sold to OntarioElectricity Financial Corporation (OEFC) with remainingterms ranging from eight to 16 years. Output from theWilliams Lake, Mamquam and Queen Charlotte powerplants is sold to BC Hydro under contracts with remainingterms ranging from 14 to 23 years. Output from theCastleton and Curtis Palmer plants in New York is soldto TransCanada Power Marketing Ltd. (TCPM), an indirectwholly-owned subsidiary of TransCanada, and Niagara
Mohawk, respectively. The contract with TCPM expiresin 2008, and the contract with Niagara Mohawk has aremaining term of 23 years. Output from the ManChiefplant is sold to PSCO under contracts with remainingterms of eight years.
The Partnership’s power plants use natural gas, wasteheat, wood waste, water flows or a combination ofthese fuel sources to produce electricity.
Each of the Ontario plants and Williams Lake plant haslong-term fuel supply contracts. Curtis Palmer, Mamquamand Queen Charlotte, as hydroelectric plants, do nothave fuel costs. The power buyer under the ManChiefPPA provides all the fuel requirements for that plant.
7MANAGEMENT’S DISCUSSION AND ANALYSIS
Power GenerationMW Fuel Source
Nipigon (1) 40 Natural gas / waste heat North Bay (1) 40 Natural gas / waste heat Kapuskasing (1) 40 Natural gas / waste heat Tunis (1) 43 Natural gas / waste heat Calstock (1) (2) 35 Wood waste / waste heat Williams Lake (2) 66 Wood waste Mamquam (3) 50 Water flows Queen Charlotte (3) 6 Water flows Curtis Palmer (3) 60 Water flowsManChief (4) 300 Natural gasCastleton (5) 64 Natural gas
744
(1) The Ontario natural gas-fired plants use a process called enhanced combined-cycle generation that uses both natural gas and waste heat as fuelsources. These plants and the Calstock plant obtain waste heat fuel from the adjacent TransCanada Canadian Mainline gas compressor stations.
(2) The Williams Lake and Calstock plants use wood waste from local mills as a source of fuel thereby increasing both environmental and economic benefits.
(3) The Curtis Palmer, Mamquam and Queen Charlotte hydroelectric facilities rely on water flows to produce electricity which is a stable source of low cost, environmentally friendly power production.
(4) The ManChief plant is a simple-cycle, natural gas-fired generating facility which is dispatched by the power buyer during peak demand periods.(5) The Castleton plant is a combined-cycle plant as it uses both natural gas and steam to generate electricity.
The Partnership’s strategic plan continues to be focusedon providing stable and sustainable distributions tounitholders. The 2004 acquisitions provide additionalsources of cash flows that will be used primarily tofund maintenance capital expenditures and further
enhance the stability and sustainability of cashdistributions into the future. The Partnership will alsoseek to grow its asset base, both by expanding capacityat existing plants and pursuing acquisition opportunitiesthat are accretive to cash flows on a per-unit basis.
Consolidated Results-at-a-Glance
Year ended December 31 (millions of dollars except per unit amounts) 2004 2003 2002
RevenuesOntario 126.6 126.2 118.4Williams Lake 35.9 35.5 37.5Mamquam and Queen Charlotte (1) 4.1Curtis Palmer (1) 31.2ManChief (1) 18.4Castleton 15.3 16.3 18.0
231.5 178.0 173.9
Operating MarginOntario 74.4 75.0 69.7 Williams Lake 23.9 25.4 28.0 Mamquam and Queen Charlotte (1) 3.4Curtis Palmer (1) 26.9ManChief (1) 13.0Castleton 8.2 8.8 9.9
149.8 109.2 107.6
Net Income 100.7 64.4 64.1Per unit $ 2.25 $ 1.64 $ 1.63
Funds Generated From Operations 128.2 99.6 101.0Per unit $ 2.87 $ 2.53 $ 2.57
Cash Distributions 114.4 99.1 99.1Per unit $ 2.52 $ 2.52 $ 2.52
Capital Expenditures 14.6 8.2 5.4
Total Assets 1,346.4 604.7 650.5
Long-Term Debt 445.2 – –
Weighted Average Units Outstanding (millions) 44.7 39.3 39.3
(1) From the dates of acquisition: Curtis Palmer and ManChief – April 30, 2004; Mamquam and Queen Charlotte – July 23, 2004.
8 MANAGEMENT’S DISCUSSION AND ANALYSIS
The Consolidated Financial Statements of thePartnership for the year ended December 31, 2004include eight months of results for the Curtis Palmerand ManChief plants and approximately five months of results for the Mamquam and Queen Charlotteplants. Revenues of $231.5 million for the year ended December 31, 2004 were $53.5 million and$57.6 million higher than 2003 and 2002, respectively.The significant increase in 2004 was due to theacquisitions of the Curtis Palmer, ManChief, Mamquamand Queen Charlotte plants. These newly acquiredplants contributed revenues of $53.7 million in 2004.
Revenues for the other plants for the year endedDecember 31, 2004 were comparable to revenues in 2003. Ontario plant revenues for the year endedDecember 31, 2003 were $7.8 million higher than in 2002, primarily due to increased curtailmentopportunities. The slight decline in Williams Lakerevenues from 2002 to 2003 primarily reflects a lowermarket-based excess energy price (2003 – $23 per MWh;2002 – $112 per MWh). The excess energy price in2004 was $36 per MWh. The decline in Castletonrevenues from 2002 through 2004 reflects the impactof a weaker U.S. dollar.
10 MANAGEMENT’S DISCUSSION AND ANALYSIS
Partnership revenues of $231.5 million for the yearended December 31, 2004 increased by $53.5 millioncompared to 2003. The increase in revenues was due to the acquisitions of the Curtis Palmer, ManChief,Mamquam and Queen Charlotte plants.
Ontario Plants All of the power output from theOntario plants is sold to OEFC under long-term PPAs.Remaining terms of these contracts range from eight to16 years. As a result of built-in annual escalators in thesecontracts, power revenues of $115.2 million for the yearended December 31, 2004 were $4.3 million higherthan 2003. Offsetting this increase in power revenueswas a $3.9 million decrease in enhancement revenues.Enhancement revenues reflect decisions by the
Manager to voluntarily curtail power production infavour of selling the unused natural gas at prevailingmarket prices. This is normally done in off-peak hourswhen contracted power prices are lower.
Power output from the Ontario plants for the yearended December 31, 2004 was 23 GWh lower year-over-year although power revenues were higher. Reducedthroughput on TransCanada’s Canadian Mainline in2003 resulted in a decrease in the Partnership’s wasteheat fuel from the adjacent TransCanada compressorstations. In 2004, the Partnership entered into acontract with TransCanada to optimize waste heatthroughput to the Partnership’s Ontario plants and, as a result, the decrease in waste heat availability was
Revenues and Plant Output
Year ended December 31 2004 2003
(millions (millionsGWh of dollars) GWh of dollars)
OntarioPower 1,372 115.2 1,395 110.9Enhancements 11.4 15.3
1,372 126.6 1,395 126.2
Williams LakeFirm energy 445 32.0 401 31.4Excess energy / other 110 3.9 123 4.1
555 35.9 524 35.5
Mamquam and Queen Charlotte (1) 67 4.1Curtis Palmer (1) 198 31.2ManChief (1) 42 18.4Castleton 185 15.3 234 16.3
2,419 231.5 2,153 178.0
Weighted Average Plant Availability (2)
Ontario 98% 98%Williams Lake 96% 89%Mamquam and Queen Charlotte (1) (3) 76%Curtis Palmer (1) 94%ManChief (1) 100%Castleton 97% 96%
(1) From the dates of acquisition: Curtis Palmer and ManChief – April 30, 2004; Mamquam and Queen Charlotte – July 23, 2004.(2) Plant availability represents the percentage of time in the year that the plant is available to generate power, whether actually running or not,
and is reduced by planned and unplanned outages.(3) The 50 MW Mamquam facility was unavailable for part of the fourth quarter due to a planned maintenance outage.
11MANAGEMENT’S DISCUSSION AND ANALYSIS
minimized. The Partnership reimburses TransCanada’sCanadian Mainline for any incremental fuel gas,maintenance and administrative costs incurred as a result of this optimization.
In 2004, weighted average plant availability for theOntario plants was 98 per cent, which was consistentwith 2003.
Williams Lake Revenues at the Williams Lake plantconsist of firm energy sales, including cost recoverycomponents, and excess energy sales under the powersales contract with BC Hydro that expires in 2018. Theamount of firm energy sold to BC Hydro on an annualbasis is fixed at 445 GWh, except in years when majoroverhauls are performed. Major overhauls are performedapproximately every five years, with the most recentoverhaul occurring in 2003. Revenues remain constantin major overhaul years but the firm energy commitmentto BC Hydro is reduced to 401 GWh. Cost recoverycomponents are escalated annually for inflation.
For the year ended December 31, 2004, firm energyrevenues of $32.0 million were slightly higher than the $31.4 million reported in 2003. The increase in firm revenues was primarily due to increased fuel costrecoveries in 2004. Excess energy and other revenuesfor the year ended December 31, 2004 were $3.9 million,compared to $4.1 million in 2003.
Mamquam and Queen Charlotte The Mamquam andQueen Charlotte plants, which were acquired in July2004, have long-term PPAs with BC Hydro that expirein 2027 and 2022, respectively. The PPAs consist of afixed energy component per MWh up to certain outputthresholds, an operations and maintenance componentadjusted annually for inflation and a reimbursable costcomponent. All of the electricity generated at theMamquam plant and most of the electricity generatedat the Queen Charlotte plant is sold to BC Hydro. Asmall amount of electricity from the Queen Charlotteplant is sold to two local industrial customers.
These plants contributed $4.1 million in revenuesduring the period of ownership in 2004.
Curtis Palmer Output from the Curtis Palmer plant,which was acquired in April 2004, is sold to NiagaraMohawk under a PPA that expires in 2027 or the dateof delivery of a cumulative 10,000 GWh of electricity to Niagara Mohawk. At December 31, 2004, there were2,980 GWh delivered under the contract. The PPA sets out eleven pricing blocks over the contract term forelectricity sold to Niagara Mohawk. The price per MWhis dependent upon the cumulative GWh of electricitydelivered and the price increases by approximately 34 per cent from contract inception up to a cumulativetotal of 3,344 GWh delivered (estimated to occur in2006), at which point the price drops by approximately33 per cent. Thereafter, the price increases on averageby approximately ten per cent with each additional1,000 GWh of electricity delivered over the remainingterm of the PPA. The Curtis Palmer plant contributed$31.2 million in revenues during the period ofownership in 2004.
ManChief The ManChief plant, which was acquired in April 2004, has two separate tolling agreementscovering the sale of capacity and incremental energy toPSCO. Both agreements expire in 2012. PSCO controlsthe dispatch of electricity from the ManChief plant,including start-ups, shut-downs and generation loadinglevels. Capacity payments are generally unaffected byoutput levels, but vary depending upon changes in plantavailability. PSCO pays for incremental energy generatedat the plant based upon a fixed price per MWh, escalatedannually for inflation. PSCO also pays for turbine start-up fees, heat rate adjustments and gas transportationcharges. For the period of ownership in 2004, theManChief plant contributed $18.4 million of revenue.
Castleton Revenues at the Castleton plant, which are adjusted annually for contractual increases, areearned through fixed monthly capacity payments fromTCPM in return for providing the power plant’s entireoperating capacity. The PPA with TCPM expires in 2008.As a result, Castleton revenues are generally unaffectedby the amount of electricity generated at the plant,which was down in 2004 compared to 2003 due toreduced dispatch by TCPM.
Revenues of $15.3 million for the year endedDecember 31, 2004 were $1.0 million lower than 2003 due to the impact of a weaker U.S. dollar.
12 MANAGEMENT’S DISCUSSION AND ANALYSIS
Cost of fuel, which is the Partnership’s most significantcost of operations, includes the fuel commodity priceand transportation costs. Virtually all of the Partnership’sfuel costs for the Ontario and Williams Lake plants areunder fixed price, long-term supply agreements withbuilt-in price escalators that generally correspond toprice increases in the PPAs.
For the Castleton plant, the Partnership pays a fixeddemand charge, which is escalated annually by inflation,under a management agreement, therefore there is nofuel price risk. Curtis Palmer, Mamquam and QueenCharlotte, being hydroelectric plants, do not have anyfuel costs. The power buyer under the ManChief PPAprovides all of the fuel requirements, but the Partnershipis obligated to pay for demand charges associated withthe transportation of natural gas to the facility.
Fuel costs at the Ontario plants for the year endedDecember 31, 2004 were $37.4 million, compared to $36.9 million in 2003. The increase of $0.5 millionwas primarily due to annual price increases in the fuel contracts.
Fuel costs at the Williams Lake plant increased $0.7 millionto $3.4 million for the year ended December 31, 2004due to wood waste being sourced from mills furtheraway, as well as paying a commodity charge on highergrade wood waste. The variability in fuel costs for the Williams Lake plant has only limited impact on the Partnership’s earnings and cash flow because themajority of fuel costs related to firm energy productionare recovered through cost recovery mechanisms builtinto the PPA with BC Hydro.
Cost of Fuel
Year ended December 31 (millions of dollars) 2004 2003
OntarioNatural gas 36.3 35.9Waste heat 0.7 0.5Wood waste 0.4 0.5
37.4 36.9Williams Lake
Wood waste 3.4 2.7ManChief
Transportation (1) 0.3Castleton
Natural gas 2.4 2.5
43.5 42.1
(1) Represents gas transportation charges from the date of acquisition of April 30, 2004.
13MANAGEMENT’S DISCUSSION AND ANALYSIS
Operating and Maintenance Expenses
Year ended December 31 (millions of dollars) 2004 2003
Ontario 12.8 12.4Williams Lake 5.4 4.6Mamquam and Queen Charlotte (1) 0.6Curtis Palmer (1) 0.8ManChief (1) 2.7Castleton 3.2 3.4
25.5 20.4
(1) From the dates of acquisition: Curtis Palmer and ManChief – April 30, 2004; Mamquam and Queen Charlotte – July 23, 2004.
Operating and maintenance expenses are based on fixedfees, adjusted annually for inflation and are payable tothe Manager for the operation and routine maintenanceof the plants. In 2004, the Manager began operatingand maintaining the Curtis Palmer, ManChief, Mamquamand Queen Charlotte plants, which accounts for $4.1 million of the year-over-year increase in these
expenses. In 2004, the responsibility for certainexpenses at the Williams Lake plant, which werepreviously paid for directly by the Partnership, wastransferred to the Manager, and the Williams Lakeoperating and maintenance fee was increased on a prospective basis.
Other Plant Operating Expenses
Year ended December 31 (millions of dollars) 2004 2003
Property taxes 7.2 2.7Insurance 4.0 2.7Major maintenance 1.5 0.9
12.7 6.3
Other plant operating expenses of $12.7 million for the year ended December 31, 2004 increased by$6.4 million compared to 2003. The increase wasprimarily due to insurance costs and property taxesattributable to the plants that were acquired in 2004.
Major maintenance expense for the year endedDecember 31, 2004 increased by $0.6 million due toan increased scope of work at the Williams Lake plantduring the spring and fall shutdowns.
Depreciation and Amortization
Year ended December 31 (millions of dollars) 2004 2003
Plant, property and equipment 40.6 36.1Power purchase arrangements 14.4 –
55.0 36.1
Depreciation and amortization expense for the yearended December 31, 2004 was $55.0 million, comparedto $36.1 million in 2003. Most of the increase in
depreciation and amortization expense was due to theplants that were acquired in 2004.
A N N U A L R E P O R T
2007
EPCOR Power LP – 2007 Management discussion and analysis
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REVENUES AND PLANT OUTPUT
Years ended December 31 2007 2006
GWh(millions of
dollars) GWh(millions of
dollars)
Ontario Plants (2)
Power 1,412 134.5 1,368 134.7 Enhancements 8.4 12.3 Gas Diversions 9.4 8.7
152.3 155.7
Williams LakeFirm energy 445 33.8 445 33.7 Excess energy 100 4.3 108 5.8
545 38.1 553 39.5
Mamquam and Queen Charlotte 267 18.0 232 15.7 Northwest US Plants (3) 910 60.7 456 38.7 California Plants (3) 1,004 130.6 170 20.5 Curtis Palmer 307 31.7 416 50.9 Northeast US Gas Plants (3) 398 57.7 153 28.6 North Carolina Plants (3) 613 52.3 51 5.6 PERC management fees (3) - 3.4 - 0.6 Fair value changes on foreign exhange contracts - 34.4 - (5.6)
5,456 579.2 3,399 350.2
Weighted average plant availability (1)
Ontario Plants 95% 98%Williams Lake 96% 95%Mamquam and Queen Charlotte 81% 83%Northwest US Plants (3) 94% 96%California Plants (3) 91% 94%Curtis Palmer 96% 97%Northeast US Gas Plants (3) 96% 96%North Carolina Plants (3) 94% 92%
Total weighted average availability 94% 95%Average price per MWh
Ontario Plants (2) $95 $98Williams Lake $70 $71Mamquam and Queen Charlotte $67 $68California Plants (3) $130 $121Curtis Palmer $103 $122North Carolina Plants (3) $85 $110
(1)
(2)
(3)
Plant availability represents the percentage of time in the year that the plant is available to generate power, whether actually running or not, and is reduced by planned and unplanned outages.Ontario power revenue includes the retroactive portion of the settlement with OEFC of $9.8 million in 2006. Average price would decline to $91/MWh in 2006 if the settlement was excluded from revenue.From the dates of acquisition: Frederickson - August 1, 2006; Ventures - November 1, 2006
Revenues of $579.2 million for year ended December 31, 2007 were $229.0 million higher than in 2006. The increase was primarily due to the acquisition of Ventures and Frederickson on November 1, 2006 and August 1, 2006 respectively, which contributed an additional $202.2 million to revenues in the year ended December 31, 2007 compared to 2006, as well as changes in the fair value of foreign exchange contracts. Offsetting the increase were the non-
EPCOR Power LP – 2007 Management discussion and analysis
23
recurrence of the $9.8 million settlement received from OEFC in the first quarter of 2006 and lower generation and pricing at Curtis Palmer. Ontario Plants All the power output from the Ontario plants is sold to OEFC under long-term PPAs with expiry dates ranging from 2012 to 2020. In addition, the Partnership has agreed to sell incremental power from Calstock to OEFC at market based prices to the end of 2009. The Ontario plants reported revenues of $152.3 million for the year ended December 31, 2007 compared to $155.7 million in 2006. Excluding the impact of the one-time settlement with OEFC of $9.8 million in 2006, revenue from power sales increased by $9.6 million in 2007. The increase was due to increased generation resulting from higher waste heat availability, built-in annual price escalators in these contracts and more natural gas being available for power generation due to lower enhancement and diversion sales. These increases were partially offset by lower generation and revenue at Kapuskasing. On May 12, 2007, during a regular maintenance outage at Kapuskasing, the rotor used by the steam turbine generator sustained damage as a result of a serious transport accident. Kapuskasing continued to operate but at a reduced capacity of approximately 20 megawatts (approximately 50% capacity) until late August 2007 when a partially refurbished steam turbine generator rotor was installed allowing the plant to return to full capacity. A new steam turbine generator rotor is expected to be installed in 2008. The financial loss, net of insurance claims, resulting from this incident was under $1.0 million. In 2006, the Partnership reached an agreement with OEFC on a replacement for the Direct Customer Rate index that was discontinued in 2002. The OEFC settlement adjusts the amount owed to the Partnership under the PPAs for the Ontario plants for the period from 2002 through to the end of the respective PPAs. The retroactive portion of the settlement was received in the first quarter of 2006 and positively impacted revenue by $9.8 million. Enhancement revenues at the Ontario plants were lower in 2007 due to price increases in the PPAs and a small decline in natural gas prices. Power output from the Ontario plants for the year ended December 31, 2007 was 44 gigawatt hours (GWh) higher year-over-year as more natural gas was available for power generation due to lower enhancement and diversion sales in 2007. Weighted average plant availability for the Ontario plants declined in 2007 to 95% compared to 98% in 2006 primarily due to the outage at Kapuskasing. Williams Lake Revenues at Williams Lake consist of firm energy sales including cost recovery components, and excess energy sales under the power sales contract with British Columbia Hydro and Power Authority (BC Hydro) expiring in 2018. The amount of firm energy sold to BC Hydro on an annual basis is fixed at 445 GWh, except in years when major overhauls are performed (approximately every five years). Revenues remain constant in major overhaul years and the firm energy commitment to BC Hydro is reduced to 401 GWh. Cost recovery components are escalated annually for inflation. For the year ended December 31, 2007, firm energy revenues of $33.8 million were slightly higher than $33.7 million reported for 2006. Excess energy sales for the year ended December 31, 2007 were $4.3 million compared with $5.8 million for 2006. Excess energy sales result when a surplus of energy is generated above the annual firm amount. The decrease in excess energy sales reflected a decrease in generation and in the market-based price (2007 - $43 per
EPCOR Power LP – 2007 Management discussion and analysis
27
31, 2006. In the second quarter of 2006, the Partnership voluntarily de-designated certain hedge relationships for accounting purposes on foreign exchange contracts. In addition, the Partnership has acquired more foreign exchange contracts as a result of acquiring the Frederickson and Ventures operations. COST OF FUEL
Years ended December 31 2007 2006(millions of dollars except average cost per MWh)Ontario Plants
Natural gas (1) 58.0 55.7 Waste heat 3.3 1.1 Wood waste 1.7 1.1
63.0 57.9
Williams Lake - wood waste 3.5 4.3
Northwest US Plants - natural gas (2) 9.8 3.9
California Plants - natural gas (2) 81.1 15.3
Northeast US Gas-Fired Plants - natural gas (2) 38.9 15.7
North Carolina Plants - coal, tire-derived fuel & wood waste (2) 34.5 4.4
Fair value changes on gas contracts 32.4 -
263.2 101.5
Average cost per MWhOntario (1) $45 $42Williams Lake $6 $8California Plants $81 $90North Carolina Plants $56 $87
(1)
(2) From the dates of acquisition: Frederickson - August 1, 2006; Ventures - November 1, 2006
Ontario gas costs include the retroactive portion of the estimated settlement of a natural gas price escalation dispute with NAL and Devon in 2006.
Fuel costs, which are the Partnership’s most significant cost of operations, include commodity price, transportation costs and fair value changes on natural gas supply contracts. Virtually all the fuel for Ontario and Williams Lake is supplied under fixed price, long-term supply agreements with built-in price escalators that generally correspond to price increases under the related PPAs. For the year ended December 31, 2007, fuel costs were $263.2 million compared with $101.5 million in 2006. The increase was primarily due to the acquisitions of Ventures and Frederickson on November 1, 2006 and August 1, 2006 respectively, which resulted in an increase in fuel costs of $119.2 million in the year ended December 31, 2007 as well as a decline recorded in 2007 on the fair value of natural gas contracts. Fuel costs at the Ontario plants for the year ended December 31, 2007 were $63.0 million compared to $57.9 million in 2006. The increase was due to higher fuel supply costs at Tunis as a result of the settlement of a supply contract dispute (see Significant Events - NAL and Devon claims), higher waste heat optimization costs and annual price increases in the natural gas
EPCOR Power LP – 2007 Management discussion and analysis
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supply contracts. These increases were partially offset by retroactive charges for estimated additional fuel charges of $4.1 million in 2006 and a $1.2 million refund in 2007 of transportation charges related to prior years. Fuel costs at the Northwest US plants increased by $5.9 million for the year ended December 31, 2007 due to the acquisition of Frederickson on August 1, 2006 and Greeley on November 1, 2006. Fuel costs for year ended December 31, 2007 at Frederickson were $4.1 million compared to $2.2 million for the five month period from the date of acquisition to December 31, 2006. Fuel costs for year ended December 31, 2007 at Greeley were $5.5 million compared to $1.3 million for the two month period from the date of acquisition to December 31, 2006. The Partnership pays for demand charges associated with the transportation of natural gas to Manchief, which were $0.2 million for the year ended December 31, 2007 compared to $0.4 million in 2006. Fuel costs at the California plants were $81.1 million for the year ended December 31, 2007 compared to $15.3 million for the two month period from the date of acquisition to December 31, 2006. Lower gas prices through the middle part of the year resulted in lower than expected fuel costs for the year ended December 31, 2007. The Northeast US gas plants incurred fuel costs of $38.9 million for the year ended December 31, 2007 compared to $15.7 million in 2006. Fuel supply costs at Castleton increased by $6.0 million for the year as the result of the higher sale of natural gas in 2007 to utilize excess natural gas transmission capacity. Fuel costs at Kenilworth were $21.3 million for the year ended December 31, 2007 compared to $4.1 million for the two month period from the date of acquisition to December 31, 2006, slightly lower than expectations due to lower generation during the year. Fuel costs at the North Carolina plants were $34.5 million for the year ended December 31, 2007 compared to $4.4 million for the two month period from the date of acquisition to December 31, 2006. An unfavourable fuel blend (a greater amount of coal burned compared to wood waste and tire derived fuel) and higher dispatch rates led to higher fuel costs than expected. The Curtis Palmer, Mamquam and Queen Charlotte hydroelectric plants do not have fuel costs. OPERATING AND MAINTENANCE EXPENSE
Years ended December 31 (millions of dollars) 2007 2006
Ontario Plants 13.5 13.4
Williams Lake 5.8 5.7 Mamquam and Queen Charlotte 1.3 1.3 Northwest US Plants (1) 8.5 6.0 California Plants (1) 12.6 2.4 Curtis Palmer 1.1 1.1 Northeast US Gas Plants (1) 5.0 3.6 North Carolina Plants (1) 11.2 2.9
PERC management expenses (1) 0.9 -
59.9 36.4 (1) From the dates of acquisition: Frederickson - August 1, 2006; Ventures - November 1, 2006.
EPCOR Power LP – 2007 Management discussion and analysis
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PPA contracts The Castleton PPA expires in June 2008. Operating margin from the facility is expected to be lower after the PPA expires and may be more volatile if the Partnership is not successful in recontracting. If the plant is not recontracted, unfavourable market conditions could result in negative operating margins. The PPAs for the North Carolina facilities and the Kenilworth facility expire in 2009. The Partnership expects to be able to replace the PPAs with similar new agreements, however there is no assurance that the new agreements will provide a similar level of operating margin and it could be lower. The Navy has the right to terminate the Naval Facility Negotiated Utility Service Contracts for convenience on one year's notice. These agreements grant the Partnership access rights to the Naval Facilities that are operated to produce and sell electricity under the Naval Facility PPAs. The termination would result in the loss of the Naval Facilities' steam host and subsequently its QF status which in turn would allow SDG&E to terminate the Naval Facility PPAs. The terms of the Kenilworth Energy Supply Agreement provide Schering the right to terminate the agreement when the price of natural gas exceeds a certain threshold. Although the Partnership does not expect that this termination right will be exercised, there can be no assurance that this will not occur. Fuel supply Wood waste is required to fuel the Partnership’s two Canadian biomass wood waste plants, Williams Lake and Calstock, which expose the Partnership to increasing price and supply risk for wood waste as demand for wood waste increases. At Williams Lake, the cost of delivered wood waste for the firm energy component (approximately 80%) is flowed through to BC Hydro. The Partnership is at risk for the wood waste price escalation for the remaining 20% of the fuel supply. The pine beetle infestation in the area is expected to continue to have a positive impact on the fuel supply for the plant in the short to medium term, but may adversely impact the long term availability of waste wood. At Calstock, the Partnership procures its wood waste from a number of suppliers. In 2006, a fire temporarily impacted one supplier while another supplier closed its mill. Combined, these two suppliers represented approximately 40% of Calstock’s fuel supply. These volumes have since been replaced through a combination of mill re-openings and procurement of new supply. The high Canadian dollar and a depressed US housing market have placed economic hardships on Ontario forestry mills which may impact future wood supply at Calstock. In August 2007, the Partnership was successful in negotiating a two year agreement with a new wood supplier to provide up to 25% of Calstock’s annual requirements. Existing coal supply contracts will meet the 2008 requirements and half of the 2009 requirements for Roxboro and Southport. While the Partnership believes that coal supply will be available for these facilities, there can be no assurance of when or upon what terms, including pricing, the existing supply agreements will be renewed or replaced.
Weyerhaeuser CHP Project
NWPPC CHP RoundtableJune 24, 2003
Project Profile
• Located at Weyerhaeuser mill, Kamloops• 30 MW hog-fuelled turbo-generator• Annual turbo-generator output : 200 GW.h• Annual pulp mill displacement : 155 GW.h• Excess 45 GW.h annually available for
market sales• Will become electrically self-sufficient
Project Profile (cont)
• Start-up scheduled for Spring 2004• Backup power and ancillary services
available from BC Hydro
Project Profile (cont)
• Project cost : $28 million CDN• Power Smart Incentive : $18 million CDN• Incentive deal announced Jan 2003
What made Weyerhaeuser a Willing Partner ??
• Interested in the project … a decade of effort to get the project advanced, but the financial hurdles had not been met
• Operates similar projects at this and other sites … technical basis well proven
• Positive economic spin-offs (construction jobs, permanent trucking jobs)
• Excess of hog fuel in the region
What made BC Hydro a Willing Partner ??
• Open to non-utility options for generation• Two options to acquire CHP projects ---
Customer Based Generation (CBG) and Load Displacement (Power Smart)– CBG, establishment of 15-20 year Electricity
Purchase Agreements, payments over the life of the agreement
– Power Smart, establishment of 10-15 year Incentive Fund Agreements, payments provided as upfront capital to assist construction
What made BC Hydro a Willing Partner ?? (cont)
• Projects present a reasonable risk profile (technical, financial, credit, performance)
• Resource stack prioritization– DSM, Resource Smart, Private Sector (green &
alternate, independent power)Power SmartResource SmartPrivate PowerVI Generation
How Did Government Policy Support This Project ??
• Recent provincial Energy Plan promotes conservation, energy efficiency and low rates – #9, Electricity distributors will acquire new
supply on a least-cost basis, with regulatory oversight by the BC Utilities Commission
– #13, The private sector will develop new electricity generation, with BC Hydro restricted to improvements at existing sites
How Did Government Policy Support This Project ?? (cont)– #20, Electricity distributors will pursue a
voluntary goal to acquire 50% of new supply from BC Clean Electricity of the next 10 years
– #21, New rate structures will provide better price signals to large electricity consumers for conservation and energy efficiency
– #23, The Utilities Commission Act will be amended to remove a disincentive for energy distributors to invest in conservation and energy efficiency
How Did Government Policy Support This Project ?? (cont)
• www.gov.bc.ca/em/
How Did the Regulatory Regime Support This Project ??
• DSM treated like generation projects for rate basing and rate of return
• Investments judged on Total Resource Cost (project cost being less than alternate resources)
• BC Utilities Commission historically supportive of DSM, alternate energies, net metering
Win-Win Project
• BC Hydro– Receives 155 GW.h of
load displacement for 1.5 ¢/kW.h
– Avoids new generation at 5.5 ¢/kW.h
– Supporting environmentally beneficial projects
– Reduced transmission loadings
• Weyerhaeuser– Receives staged
payments totalling $18 million
– Alleviates capital requirements
– Utilization of hog fuel to generate electricity rather than beehive burner disposal
This document is solely for the use of the BC Pulp and Paper Industry Task Force. We expressly disclaim any responsibility or accountability to any third parties who may gain access to this report, in whole or in part.
© 2007 PricewaterhouseCoopers LLP, Canada. PricewaterhouseCoopers refers to the Canadian firm of PricewaterhouseCoopers LLP and the other member firms of PricewaterhouseCoopers International Limited, each of which is a separate and independent legal entity.
Report on the Economic Impact of the BC Pulp and Paper Industry Prepared for BC Pulp and Paper Industry Task Force November 2007
PricewaterhouseCoopers refers to the Canadian firm of PricewaterhouseCoopers LLP and the other member firms of PricewaterhouseCoopers International Limited, each of which is a separate and independent legal entity.
PricewaterhouseCoopers LLP Chartered Accountants PricewaterhouseCoopers Place 250 Howe Street, Suite 700 Vancouver, British Columbia Canada V6C 3S7 Telephone +1 604 806 7000 Facsimile +1 604 806 7806 Direct Tel. (604) 806-7603
November 15, 2007 Private and Confidential Mr. David Gandossi Chair BC Pulp and Paper Industry Task Force Suite 2840, 650 West Georgia Street Vancouver, BC V6B 4N8 Dear Mr. Gandossi: Subject: Report on the Economic Impact of the BC Pulp and Paper Industry Please find enclosed our report summarizing the economic impact of the BC pulp and paper industry. Thank you for providing us with the opportunity to assist the industry with this important advocacy initiative. Please contact me (604 806 7603) or Linda Castagna (604 806 7524) if you have any questions. Yours truly, W. L. Craig Campbell Incorporated Partner Global Forest and Paper Practice
Contents
Terms of Reference__________________________________________________________4
Source Data ________________________________________________________________4
Definition and Glossary ______________________________________________________5
Executive Summary _________________________________________________________7
Report Results______________________________________________________________9
Employment and Compensation ______________________________________________12
Economic Dependence ______________________________________________________14
Payments to Government____________________________________________________15
Fibre Supply ______________________________________________________________17
Environment ______________________________________________________________21
Report on the Economic Impact of the BC Pulp and Paper Industry Page 4 BC Pulp and Paper Industry Task Force November 2007
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Terms of Reference
This report has been prepared at the request of the BC Pulp and Paper Industry Task Force to improve stakeholder knowledge and understanding of the pulp and paper industry in British Columbia.
We provide no opinion, attestation or other form of assurance with respect to our work or the information upon which our work is based. The procedures we performed in preparation of this report do not constitute an examination or a review in accordance with generally accepted auditing standards or attestation standards. We did not audit or otherwise verify the information supplied to us in connection with the preparation of this report.
This report is to be used solely by the BC Pulp and Paper Industry Task Force.
Source Data
To prepare this report, we reviewed the following material:
• PricewaterhouseCoopers reports: - Forest Industry in BC Report, prepared for the Council of Forest Industries - Market Pulp Benchmarking Study - BC Solid Wood Benchmarking Study
• Statistics Canada and BC Stats information • Media articles • Tax legislation • Ministry of Forests and Range - Harvest Billing System • Company websites and annual reports • Industry publications • Discussions with company representatives
Report on the Economic Impact of the BC Pulp and Paper Industry Page 5 BC Pulp and Paper Industry Task Force November 2007
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Definition and Glossary
For purposes of this report, the BC pulp and paper industry includes the following primary mills in British Columbia:
Company Location Market Kraft Pulp (1)
Uncoated Groundwood
Papers (2)
CTMP and Other Paper (3)
Abitibi Mackenzie √
Canfor Taylor √ Canfor Pulp Prince George 3 mills √ Cariboo Pulp Quesnel √
Catalyst Campbell River √ √
Crofton √ √
Port Alberni √ Powell River √ Domtar Kamloops √
Howe Sound Port Mellon √ √
Kruger New Westminster √ Mercer Castlegar √
Neucel Port Alice √
Pope & Talbot Mackenzie √
Nanaimo √
Tembec Chetwynd √ Skookumchuk √ West Fraser Kitimat √ Quesnel √
(1) Referred to in this report as Market Pulp. (2) Also referred to in this report as Newsprint and/or Groundwood Specialty Papers. (3) Referred to in this report as Other Pulp and Paper.
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The following industry terms are used throughout the report: BDU – Bone Dry Unit. A measure of chip volume commonly used in the BC Interior. By definition, a BDU of pulp chips weighs 2,400 pounds when oven dry. The solid wood equivalent volume in a BDU of chips varies with species and density. BEK – Bleached Eucalyptus Kraft pulp. Pulp made from eucalyptus trees found mainly in the southern hemisphere. By-products or residual chips – wood chips produced as part of the lumber or plywood production process. Cash conversion costs – total costs to produce pulp, excluding fibre and depreciation. CTMP – chemi-thermo mechanical pulp. FTE – Full Time Equivalent employees. An FTE is deemed to work 1,950 hours per year (52 weeks at 37.5 hours per week). Mill Net – net revenue realized by the mill. Calculated as gross sales revenue, net of freight, commission, trade and cash discounts and other export taxes. NBSK – Northern Bleached Softwood Kraft pulp. Pulp made from the strong, lengthy fibres of softwood trees found in the northern hemisphere. Net earnings (loss) – operating earnings (loss), less allocated interest (based on capital employed) and allocated income taxes (in the proportion that operating earnings bear to net earnings). ROCE – Return on Capital Employed. A ratio used to understand the profitability of a company or industry. Calculated as net earnings (loss) plus after-tax interest expense, as a percentage of year-end capital employed. An ROCE of 12% is the generally accepted minimum for an industry. Stumpage – revenue collected by the provincial government in exchange for consumption of Crown timber. Note: all $ references in this report are in Canadian currency, unless otherwise noted.
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Executive Summary
The BC pulp and paper industry contributes over $4 billion annually to the economy of British Columbia. Beneficiaries of the industry include employees, communities, government, the solid wood industry and, when the industry is profitable, shareholders.
The BC pulp and paper industry provides a significant number of well-paying jobs for the provincial workforce. Directly, over 10,000 employees earn a living from the pulp and paper industry, which indirectly provides employment for some 20,000 additional people. The pulp and paper industry is estimated to pay $1 billion annually in compensation and benefits directly to, and on behalf of, its employees. The average hourly employee in a BC pulp mill earns $96,000 per year in salary and benefits, making pulp and paper the second highest paying industry in BC next to mining, oil and gas.
Although declining employment in the industry raises concerns about job security for existing employees, in fact employers face a significant challenge attracting and retaining sufficient numbers of skilled workers to replace aging employees.
The pulp and paper industry in BC contributes $600 million annually to all three levels of government, which benefit greatly from the industry itself through taxes, assessments and other government revenues, and also from the employees, who contribute significantly to government revenues.
The pulp and paper sector contributes revenues to government, irrespective of whether the companies are profitable – through the federal Large Corporations Tax, provincial and municipal property tax, provincial sales tax, the pulp portion of provincial stumpage payments, and federal and provincial employee tax withholdings, CPP and EI.
Pulp and paper mills in BC are frequently located in small towns, which become economically dependent on the mills for municipal taxes and employment. When mills are operating near capacity and experiencing positive financial results, the benefits of being a mill town reach far beyond the jobs created and taxes paid. BC communities benefit from the industry’s support of local activities and infrastructure.
The symbiotic relationship between the solid wood sector and the pulp and paper industry in BC helps ensure overall value is extracted from the Crown resource (timber). The pulp and paper industry contributes in excess of $1.5 billion to the solid wood sector by consuming residual chips (by-products) from the sawmilling industry. This value-added process not only supports the sawmill companies, but also generates more work for pulp and paper employees, further payments to government by pulp and paper mills, returns to pulp and paper shareholders, and a stronger and more diversified economic base for the people of British Columbia.
Pulp and paper producers have a tremendous social responsibility to care for the air and the water on which their mills rely. According to the industry, BC pulp and paper facilities greenhouse gas emissions were 62% less in 2006 than 1990, despite increased production volumes during that
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period. The reduction achieved by BC mills is ten times the 6% reduction in greenhouse gas emissions by 2012 committed to by Canada in ratifying the Kyoto Accord. As reported by the industry, the greenhouse gases that were not emitted by the BC pulp and paper industry in 2006, in comparison to 1990 levels, are the equivalent of removing the emissions of over 600,000 vehicles.
Unfortunately, one significant stakeholder is not currently benefiting from the BC pulp and paper industry: the shareholders. The Return on Capital Employed (ROCE) has not exceeded 12% in any subcomponents of the industry for the past ten years, and the average for the 20 years between 1986 and 2005 has been significantly below the minimum expected 12% threshold. The industry cannot provide high paying jobs to its employees, contribute to government revenues, support local communities and purchase by-products from the solid wood sector unless it earns sufficient profits to generate a reasonable return on investment for its shareholders.
Market pulp and newsprint prices have shown little upward trend over the past 20 years, and being a commoditized industry, it is critical for BC pulp and paper operations to minimize costs and be globally competitive in order to generate positive earnings. The earnings over the past 20 years have not met the minimum threshold expected by the shareholders. Additional investment is required to upgrade the mills and achieve lower costs; however, further investment will be hard to attract without reasonable expectation of a proper return.
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Report Results
The economic impact of the BC pulp and paper industry is measured by the tangible and intangible benefits attributable to the industry realized by the stakeholders of the industry. Stakeholders include owners of the operations (shareholders), owners of the resources consumed by the industry (residents), employees, and suppliers of the industry. Tangible benefits include profits earned by the owners of the industry’s operations, employment for BC residents (direct and indirect jobs), and revenues received by the various levels of government. Intangible benefits include efforts made by the industry to be good corporate citizens in the communities in which they operate. This report outlines the tangible and intangible benefits of the industry to its stakeholders. Industry Profitability and ROCE
The BC pulp and paper industry has been struggling to generate positive financial results for an extended period. A Return on Capital Employed (ROCE) of 12% is considered to be the generally accepted minimum for a healthy, sustainable industry. ROCE has not exceeded 12% in any subcomponents of the industry for the past ten years and the average for the 20 years between 1986 and 2005 has been significantly below the 12% threshold, as shown in the chart below:
Source: PricewaterhouseCoopers
The average ROCE over the 20-year period from 1986 to 2005 was:
• Coastal Market Pulp: 2.8% • Interior Market Pulp: 7.1% and • Newsprint and Groundwood Specialty Papers: 4.2%
Pulp and Paper Industry Subsectors - Return on Capital Employed
-15%-10%
-5%0%5%
10%15%20%25%
86 87 88 89 90 91 92 93 94 95 96 97 98 99 00 01 02 03 04 05
YearMarket Pulp Newsprint Other Pulp and Paper - BC Region
Average Market Pulp Average Newsprint
12% Threshhold
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The pulp and paper industry is highly capital intensive, so a significant level of earnings is required to generate a reasonable ROCE.
The following table outlines the net earnings (loss) of the BC pulp and paper industry over the five years from 2001 to 2005:
Net Earnings (Loss) ($ millions)
2001 2002 2003 2004 2005
Market Pulp (147) (174) (113) 20 (143)
Uncoated Groundwood Papers 135 (85) (83) (33) (12)
Other Pulp and Paper (estimate) 67 4 (23) 6 6
Combined Net Earnings (Loss) 55 (255) (219) (7) (149)
The market pulp sector has earned a paltry $164 million over the 20-year period from 1986 to 2005. The sector has incurred net losses in 12 of those 20 years. In the five-year period from 1986 to 1990, the sector generated net earnings of $2.2 billion. However, those profits were completely eliminated over the following 15 years; the total net loss experienced in the market pulp sector between 1991 and 2005 was $2 billion.
A similar story exists for the BC newsprint sector where newsprint has suffered net losses for 11 of the 20 years in this period. The total net loss over the 20-year period (1986 to 2005) was $37 million. As with pulp, the net earnings between 1986 and 1990 of $456 million were completely wiped out by a total net loss of $493 million between 1991 and 2005.
The profitability of the pulp and paper industry depends on the price of the end product. The BC industry tends to be profitable in years of higher prices and incur net losses in years of lower prices. Pulp and paper are global commodities, and as such, BC producers are price takers in the global market and have limited ability to influence prices.
The BC pulp and paper industry is not alone with its poor financial results. The global industry, with the exception of BEK mills in South America and Asia, is suffering from reduced revenues, mainly due to over-capacity of pulp and paper production. NBSK has been used indiscriminately in the past because of its superior properties and favourable pricing brought about by excess supply. Paper producers focused on cost reduction have developed new paper recipes that allow for substitution of NBSK pulp with less expensive BEK. As a result, BC has seen its share of mills disappear over the past 20 years. The Gold River newsprint mill closed in 1993 and the pulp mill followed in 1998, Norske Canada’s pulp mill at Powell River shut down in 2001, and Western Pulp’s Woodfibre (Squamish) mill closed in 2006. The pulp mill in Prince Rupert has been on the brink of resurrection since Skeena closed its doors in 2001, and the Port Alice mill was given a new life by Neucel in 2006. Other mills have channelled their investments to higher value paper production rather than market pulp, especially on the Coast, to try to reduce their dependence on cyclical commodities.
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Market Price
As illustrated in the graph below, market pulp and newsprint prices have shown little upward trend over the past 20 years. Prices for both products have similar cycles and the most recent peak was in 1995. The prices in the following chart are not adjusted for inflation. In 1992 dollars, net mill realization for pulp was over $750 per tonne in 1986 and only $460 in 2006. Because BC pulp and paper operations are experiencing periods of downward price pressure, it is critical for the industry to minimize costs and be globally competitive.
Capital Expenditures
The poor economic returns of the industry have resulted in limited re-investment, contributing to further poor economic returns. The table below depicts the decline in capital expenditures in market pulp and newsprint over the period from 1986 to 2005:
Total Capital Expenditures ($ millions)
1986 to 1995 1996 to 2005
Market Pulp 4,523 1,359 Newsprint 2,471 826
As noted in the graph below, over the 20-year period from 1986 to 2005, the most significant capital expenditures were made between 1989 and 1993 when Howe Sound Pulp and Paper underwent a significant expansion and modernization program as did the Celgar (Mercer) mill in Castlegar. In
Market Pulp and Newsprint Prices
0 200 400 600 800
1,000 1,200
87 88 89 90 91 92 93 94 95 96 97 98 99 00 01 02 03 04 05 06
Year
Market Pulp Newsprint
(Mill
Net
– C
AD
/tonn
e)
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addition, new environmental regulations were enacted during this timeframe. In the ten years between 1989 and 1998, the market pulp mills invested $1.3 billion to make their production processes more environmentally friendly, slightly more than the $1.2 billion invested over the same period in projects to reduce costs or increase revenue at the existing operating level. The capital projects focused on the environment were split almost equally between improving air quality and improving water quality. Minimal capital spending has occurred since the late 1990s. In fact, the industry has recently been in a period of de-investment, where annual depreciation exceeds annual capital spending, a situation that is not sustainable.
BC Pulp and Paper Industry Capital Expenditures
0200400600800
100012001400
86 87 88 89 90 91 92 93 94 95 96 97 98 99 00 01 02 03 04 05
Year
($M
illion
s)
Employment and Compensation
The BC pulp and paper industry provides a significant number of well-paying jobs for the provincial workforce. The inter-dependency between the solid wood sector (lumber and logging) and the pulp and paper sector is significant, especially when considering employment levels. The lumber and logging industry depends heavily on the pulp and paper industry for use of residual chips and pulp logs, and the pulp and paper industry relies on the lumber and logging sector for fibre supply.
FTE Analysis
The following table shows the average number of full-time equivalent positions (FTEs) in the BC forest industry for several of the years between 1986 and 2005:
Source: PricewaterhouseCoopers
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1986 1996 2001 2005 Market Pulp 6,900 7,500 6,100 5,000 Newsprint 4,100 3,700 3,300 3,500 Other Pulp and Paper (estimate) n/a n/a 2,400 2,000 Pulp and Paper sector total n/a n/a 11,800 10,500 Lumber 29,300 23,700 19,200 16,800 Plywood and Veneer 5,100 3,300 3,600 3,600 Logging (company and contractor) 27,000 30,500 26,800 23,500 All other sectors (value added, provincial government, silviculture) n/a n/a 24,200 23,000
Total direct employees in BC Forest Industry 94,600 99,100 85,600 77,400
Source: PricewaterhouseCoopers
Capital investments made out of necessity to reduce costs have increased capacity in the industry without a corresponding increase in employment levels. As reported by BC Stats, in 1996 the paper manufacturing industry employed 22,900 people in British Columbia. In 2001, paper manufacturing industry employment levels had dropped to 15,000 people and by 2005 employment had decreased further to 12,300 people. In contrast, BC’s total labour force grew by 21% over the ten years from 1996 to 2005. As a result of investment in modernizing plants, the average market pulp mill currently produces 0.86 tonnes per FTE compared to 0.53 tonnes per FTE in 1986.
Although declining employment in the industry raises concerns about job security for existing employees, in fact employers face a significant challenge attracting and retaining sufficient numbers of skilled workers to replace aging employees. The average age of the pulp and paper industry union workforce is 45 years.
Indirect Employment
The BC pulp and paper industry generates significant employment outside the industry. Suppliers to the industry, such as transportation providers, fuel companies, office supply companies and construction workers, depend on the industry for employment but are not categorized as forestry workers in provincial statistics. In addition to the indirect employment generated by the industry, significant tertiary employment is created when pulp and paper employees spend their pay cheques on such services as taxis, restaurants, hotels and cars.
Using a common industry multiplier of 2.0—that is, for every direct job, an additional two other jobs are created—the nearly 80,000 people currently employed full time by the forest industry create an additional 160,000 jobs for others, for a total of 240,000.
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Annual Compensation and Benefits
Forestry workers are very well compensated and have achieved significant benefit packages as a result of historically strong union negotiations. The average hourly employee in a BC pulp mill earned $64,000 in compensation in 2005 and a further $32,000 in benefits, for a total of $96,000 per year. The average forestry worker in BC earned $51,800 in compensation in 2005 and a further $19,000 in benefits. In comparison, the average employee earned $37,000 in BC or $37,700 in Canada, with very few benefits. Using the pulp sector’s average hourly compensation and benefits, the pulp and paper industry paid approximately $1.0 billion in compensation and benefits to, or on behalf of, its employees.
Of the major BC industries selected for review, pulp and paper industry workers are the second highest paid, only slightly behind mining and oil and gas workers. Wages for forestry workers in BC are approximately 30% higher than the average BC industrial wage. The table below compares compensation earned by a forestry worker in BC to other industries and to Canada as a whole in 2005:
Source: Statistics Canada, except Forestry which is sourced from PricewaterhouseCoopers
Economic Dependence
Pulp and paper mills in BC are frequently located in small towns, which become economically dependent on the mills. A 2004 Economic Dependency Report by BC Stats analyzed 29 communities outside Greater Vancouver in 2001. In ten of those 29 communities, the forest industry was the number one employer, second only to the public sector, which was the main employer in 15 communities. In those 29 communities, the forest industry provided employment for an average of 27% of the workforce.
Average Annual Compensation ($) 2005 All Canada workforce 37,727 All BC workforce 37,053 Significant BC Industries:
Mining, oil and gas 69,047 Forestry 51,760 Professional, scientific and technical services 48,355 Manufacturing 45,617 Construction 43,884 Health care and social assistance 35,220 Trade 30,218
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When mills are operating near capacity and experiencing positive financial results, the benefits of being a mill town reach far beyond the jobs created and taxes paid. Despite its recent financial performance, the BC pulp and paper industry continues to demonstrate corporate generosity by making large donations to hospital foundations and scholarship funds and sponsoring and contributing to community recreational facilities, activities and other infrastructure such as schools, hospitals and water treatment processes. However, when operations close as a result of poor economic performance and better use of available capital elsewhere, the economic impact to the community can be significant.
Payments to Government
The BC pulp and paper industry is a significant contributor to the revenues of the three levels of government: municipal, provincial and federal. There are varying sources of government revenue – driven by income, investment and production inputs.
Income Tax
The BC pulp and paper industry is subject to income tax on its taxable earnings. The federal tax rate for a typical BC pulp and paper facility is 22%, and an additional 12% income tax is charged by the provincial government. A 3% credit is available for qualifying manufacturing and processing property in BC.
Given that the industry has been in a net loss position for many of the past 20 years, actual income tax payments have not been significant.
Capital Tax
The Large Corporations Tax (LCT) was implemented by the federal government in 1996. Since it is a tax on the infrastructure of the industry and does not fluctuate relative to earnings, it becomes a fixed cost to the companies. The tax rate is 0.225% on all taxable capital above a corporate threshold of $50 million. Therefore, for a typical BC mill with taxable capital of $300 million, the LCT collected by the federal government is over $500,000.
Another form of capital tax is property tax charged to the industry by municipal governments and regional tax authorities. Property taxes paid by pulp and paper mills are significant due to the size of the land base covered by the mills. Pulp and paper facilities in BC pay property taxes that equate to a range from $8 and $14 per tonne of pulp and paper produced, or 3% of cash conversion costs.
Commodity Taxes and Other Government Revenue
The government also collects revenue from the industry based on consumption of materials in the production process, including stumpage, sales, water, fuel and electricity. These costs vary in
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relation to production levels but not profitability. As a result, governments receive significant revenue from the industry even when shareholders are left covering financial losses.
Stumpage - The provincial government collects payment for consumption of the Crown resource by charging stumpage on each cubic metre of Crown timber harvested. Until recently, stumpage rates varied in relation to the quality of wood harvested, the cost of harvesting the wood, and the market price of the products produced from the harvested timber. Recent changes to the stumpage system have made the market price for timber the primary factor influencing the stumpage rate.
Sawlogs attracted an average stumpage price of $16 per m3 in 2005 but stumpage has been as high as $29 per m3 within the past ten years. Since residual chips represent approximately 10% of the revenue earned from the log, the pulp industry’s cost of residual chips includes approximately $1.50 per m3 of stumpage paid to the provincial government in 2005 and an average of $2.00 per m3 over the past decade. The table below shows stumpage trends in BC over the past ten years:
Average Provincial Stumpage ($ per m3)
1996 1997 1998 1999 2000 2001 2002 2003 2004 2005
Stumpage, Royalties, Rents, etc.
25.19 28.66 24.44 20.63 21.87 18.75 19.50 17.02 16.79 15.72
Source: PricewaterhouseCoopers
Pulplogs are lower value timber and therefore the stumpage rate is only $0.25 per m3.
Assuming production of 4.2 million tonnes of pulp annually in BC, approximately 25 million m3of chips are consumed. Using an average fibre diet of 90% residual chips and 10% chips from pulp logs, stumpage attributable to the BC pulp industry in 2005 was over $30 million.
Sales tax – BC has a provincial sales tax (PST) of 7%. PST is charged on most goods and services consumed by the industry. As a high level estimate, a typical mill purchases at least $100 per tonne of taxable supplies, excluding energy and fuels, for a total of $7 per tonne of sales tax. With over 4 million tonnes of pulp and 3 million tonnes of paper produced annually in BC, that equates to almost $50 million in PST, excluding taxes on capital spending, which are an estimated further $10 million.
In addition to consumable supplies, the industry pays PST on fuel and electricity. In 2006, an average pulp and paper mill in BC consumed $13 million in fuel and $20 million in electricity. The resulting PST paid annually by each mill on fuel and electricity is approximately $900,000 and $1.4 million, respectively.
Employee Withholdings
In addition to taxes paid by the industry itself to the federal government, employees pay significant federal tax and the industry also contributes to the federal government on behalf of its employees.
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For a typical wage of the pulp and paper industry (e.g., $65,000 per year), the following taxes relating to employees are paid:
$ per Employee Employee Employer Total EI $ 729 $ 1,022 $ 1,751 CPP 1,911 1,911 3,822 Provincial Income Tax 15,635 0 15,635 Federal Income tax 12,351 0 12,351 Total $30,626 $ 2,933 $33,559
Source: Canada Revenue Agency
Based on the 10,500 employees in the pulp and paper sector in 2005, total government revenue from those employees was in the neighbourhood of $350 million, excluding taxes from employee benefits.
In summary, the three levels of government receive over $600 million annually from the BC pulp and paper industry, irrespective of whether the companies are profitable.
Type of Tax
Estimated Annual Tax Paid by BC Pulp and Paper Mills
($ millions) Income Tax 0 Large Corporations Tax 10 Property Tax 100 Stumpage 30 Sales Tax – Supplies and Capital 60 Sales Tax – Fuel and Electricity 50 Taxes on behalf of direct employees 350 Total >600
Fibre Supply
Overview
British Columbia has a total land base of 95 million hectares, of which 60 million hectares, or 63%, is covered by forests. Fibre is a Crown resource in BC and approximately 90% of the annual harvest volume is from Crown lands, while the remaining 10% is from private lands. Government policies and regulations are established to maximize the value of the Crown resource to the
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taxpayers of the province. Value is established through stumpage, a tax paid to the government by consumers of the timber, and employment in the forest industry.
The pulp and paper industry is a significant consumer of fibre in the province. Final products produced by the mills in the BC pulp and paper industry are made from whole logs, residual chips, slush pulp or dried pulp.
The industry includes:
• market pulp mills that produce pulp from chips and dry the pulp into sheets • pulp and paper mills that initially produce pulp from chips and then further refine the slush
into paper • paper mills that produce dry pulp sheets into paper.
Proximity to high quality fibre gives the BC pulp and paper industry a competitive advantage; however, the distance to the final consumer creates a challenge. Because high value paper produced from BC fibre is heavy, it is expensive to transport; it is also expected to be of a certain quality and there is a risk of damage during transit.
The following chart shows the estimated primary use of the annual provincial log harvest. Residual chips are sourced from lumber mills as a by-product that is further processed.
Estimated Primary Log Use
77%
10%
3%
3%
7%Lumber Mills
Veneer/OSB Mills
Pulp Mill Wood Rooms
Chip Mills
Other
Source: Statistics Canada and BC Ministry of Forests
Residual Chips
Residual chips are the most economic source of fibre for the BC pulp and paper industry. The pulp and paper sector’s consumption of residual chips is a value-added use of Crown timber. Sawmills and other solid wood processing facilities process logs into their final products and chips are produced during the process. The chips are collected and stored by the solid wood facilities. The
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pulp and paper mills buy chips from the sawmills and cover the shipping costs to deliver them to the pulp and paper facilities where they are further processed into pulp and paper. The following chart depicts the average product recovery from a typical BC Interior sawmill:
Estimated Product Recovery from Lumber Mills
37%
16%
47%
By-product chips
Sawdust and shavings
Lumber
Source: Forintek Canada Corp.
The following diagram illustrates the flow of fibre within the BC forest industry:
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The consumption of residual chips and hogfuel by the pulp and paper industry is a symbiotic relationship with the solid wood sector and evidence of the value the pulping process adds to the consumption of fibre as a natural resource. Sawmills receive on average $35-45 per mfbm of lumber produced, or $10 per m3 of fibre consumed, from the sale of residual chips – approximately an additional 10-20% on top of the revenue earned from the sale of lumber, so a significant benefit to sawmills. Most pulp mills have long-term contracts with sawmills to provide certainty over their source of fibre and the contracts typically provide for the price of chips to vary in relation with the market price of pulp. Historically, the lumber and pulp price cycles have peaked at different times, so sawmills stand to benefit from increased chip revenue when they are suffering from reduced lumber prices.
The benefit to sawmills of selling residual chips to pulp mills is often underestimated. When the industry has been in a situation where the pulp mills are closed and the sawmills are still operating (e.g., during labour disruptions), the sawmills often have to close as well. Residual chips have a limited shelf life, there is limited storage space, and it is not economically viable to continue operations without the revenue from the sale of the residual chips. While the ability of pulp mills to consume the hogfuel produced as a by-product at sawmills does not financially benefit the sawmills, it does mean they don’t have to dispose of the waste in another manner.
Whole Log Chips
If pulp mills are unable to obtain sufficient residual chips at an economical price from nearby sawmills, they sometimes rely on whole log chipping. Some pulp mills, especially on the Coast, have a woodroom and can chip whole logs on site. Other mills have whole log chipping facilities nearby. Low grade logs of insufficient quality for processing into lumber or plywood are chipped entirely. They are harvested along with the sawmill quality logs in the bush and are then traded or sold to pulp mills or whole log chipping facilities. This market for the low grade logs helps the loggers who would otherwise leave the pulp logs as salvage in the woods or leave the trees standing, increasing the cost of the harvest process on each cutblock and the risk of accidents during harvest.
Residual chips are the most common source of fibre for pulp mills. Most BC and Canadian pulp mills consume 90% residual chips and 10% whole logs and sawdust. Because whole log chips require a log to be processed into chips, they cost approximately 30% more than residual chips. Fibre is the single largest cost component of a tonne of pulp, at approximately 35%. In the BC Interior, fibre currently costs approximately $150 per tonne of pulp produced.
Fibre as a Crown Resource
Pulp mills consume approximately 6 m3 of fibre per tonne of pulp produced. Based on a total BC NBSK pulp production volume of 4 million tonnes, 25 million m3 of fibre is consumed annually. At an average price of $90 per BDU or $35 per m3, the market kraft pulp industry contributes close to $1 billion of benefits to the sawmilling industry, by further refining the residual chips.
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Additional benefits are realized by the sawmilling industry on any raw fibre consumed by the paper sector and the three CTMP mills in BC.
Alternative Uses of Fibre
The traditional fibre flow of the BC forest industry is being challenged by the energy sector. The temporary uplift in available fibre as a result of the mountain pine beetle epidemic, combined with the current economic situation in the BC forest industry (low lumber prices, relatively high pulp and paper prices, strong Canadian dollar), means alternative uses for BC fibre are being considered. Unless incentives and penalties are applied equitably, the forest and paper industry may see fibre being diverted to the energy sector.
Certain alternative uses of pulp logs, residual chips and hogfuel offer additional sources of revenue for pulp and paper plants and for other producers with access to BC fibre. One of these alternatives is pellets. BC pellet production capacity is approximately 600,000 tonnes per year, spread over 12 plants. More than 80% of this production is currently being sold in Europe. European demand for wood pellets is expected to increase 150% by 2010 and Canada is viewed as a secure supplier of quality wood pellets.
British Columbia is blessed with significant biomass resources such as woody debris, agricultural crop residues, animal manure and municipal wastes that can be used to produce heat, electricity, liquid fuels and other forms of energy. These resources are renewable, distributed throughout the province, and suitable for either large-scale or smaller, community-based energy production opportunities. Wood pellet production, wood-fired electricity generation and cogeneration are already well established in British Columbia, with wood gasification, liquid biofuel production and other bioenergy/biorefining technology also well positioned to play a significant role in British Columbia’s energy future.
British Columbia currently leads the nation in wood energy production and consumption, with about 50% of Canada’s biomass electricity generating capacity. Mill residues currently incinerated in beehive burners provide no energy recovery and also cause adverse impacts on local air quality. Wood residue is expected to increase in the short term while the mountain pine beetle infestation takes its toll on the standing timber. These resources, and abundant wood residues in other regions throughout the province, present an opportunity for increased bioenergy production in British Columbia.
Environment
Emissions Regulations and Initiatives
Pulp and paper operations are heavily integrated with the air and water. The industry has always been extremely conscious of its impact on the environment. Comprehensive regulations were implemented in the early 1990s that strengthened the already good care the industry was taking of the environment. Companies in the Canadian pulp and paper industry today strive to obtain certification under the International Organization for Standardization (ISO) 14001 and many
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companies have met these standards for several years running. ISO 14000 is a series of international, voluntary environmental management standards developed to address such things as Environmental Management Systems (EMS), Environmental Auditing and Related Investigations and Environmental Performance Evaluations.
Canada has the world’s largest area of forests certified as sustainable by third parties. In addition to the ISO 14001 certification, Canadian companies have obtained certification through the Sustainable Forestry Initiative (SFI) Standard, the Canadian Standards Association (CAN/CSA Z809) and the Forest Stewardship Council (FSC).
Given its integration with the environment, the industry has a tremendous social responsibility to care for the air and the water on which its mills rely. A significant number of recent initiatives by pulp and paper producers relate to reducing greenhouse gas emissions of pulp and paper mills. According to the Forest and Paper Association of Canada (FPAC), between 1990 and 2006 FPAC member pulp and paper facilities across Canada reduced their greenhouse gas emissions by 44%, while increasing production volumes. The BC pulp and paper sector is leading the national reduction in greenhouse gases. According to the industry, BC pulp and paper facilities greenhouse gas emissions were 62% less in 2006 than 1990, despite increased production volumes during that period. The reduction achieved by BC mills is ten times the 6% reduction in greenhouse gas emissions by 2012 committed to by Canada in ratifying the Kyoto Accord. As reported by the industry, the greenhouse gases that were not emitted by the BC pulp and paper industry in 2006 in comparison to 1990 levels are the equivalent of removing the emissions of over 600,000 vehicles.
The pulp and paper industry is a global leader in the use of combined heat and power (CHP) systems. These cogeneration systems produce electrical power and thermal energy from the same fuel. Yielding at least twice as much usable energy from the same amount of fuel as normal methods reduces the demand for fossil fuels, which in turn reduces greenhouse gas emissions.
Energy Self-sufficiency
An average pulp mill in BC consumes 300,000 MWH of power per year. However, the industry generates over 70% of its energy requirements from within the pulping process. In addition to satisfying their own needs, several mills in BC sell steam or electricity to the grid, for consumption by households and businesses in the province.
BC Hydro has the capacity to generate 11,000 MW and currently imports 12% of its energy requirements. BC’s energy demand is expected to increase by 25-45% over the next 20 years, creating a significant opportunity for the BC pulp industry to supply the province with energy and thereby generate additional income to support operations and capital expenditures. The BC pulp sector is currently generating 850 MW for internal use and many mills in the province have achieved energy self-sufficiency. This type of self-sufficiency has a positive impact on the environment.
www.PulpandPaperBC.ca
The Road to Renewal for B.C.’s Pulp and Paper Industry
• B.C.’s pulp and paper industry is at a crossroads with respect to its future economic prospects. The industry is facing increased global competition, growing concerns about fibre availability and affordability, and pressures from the strong Canadian dollar.
• The B.C. pulp and paper industry has fallen behind competitors in other regions in areas such as R&D, new technologies, government support and the formation of global companies. Strategic reinvestment encouraged by sound public policy could facilitate and accelerate the revitalization of the sector in B.C.
• B.C.’s Northern Bleached Softwood Kraft (NBSK) mills are high cost in terms of delivered cost to natural markets — especially those on the Coast. Newsprint producers in B.C. are also high cost. The recent rise in the value of the Canadian dollar has made the situation more urgent by reducing margins substantially.
• The capital assets in B.C.’s pulp and paper sector are older than in competing jurisdictions and the reinvestment rate is below the level required to sustain their already weak competitive position. The 4% return on capital employed achieved by the industry over the past 15 years has severely constrained the industry’s access to capital.
• B.C.’s large supply of high quality fibre remains its core competitive advantage. However, it is at risk. The ongoing pine beetle infestation will reduce interior harvest volumes by more than 25% over the next 10 years.
• There is potentially a growing use for biomass. Policies are required that can enable the pulp and paper sector to benefit from opportunities in demand for biomass-based energy. Done properly, there should be room for both the pulp and paper sector and an independent power industry to benefit from biomass.
• The road to renewal is clear — consolidation, restructuring and subsequent reinvestment in world-class assets. The industry needs fewer, larger companies in order to benefit from competitive advantages in cost of capital, investment capacity, supply chain leverage and innovation. Restructuring will ensure that only economically viable assets are supported.
• Significant capital investments in B.C.’s pulp and paper sector can be encouraged by:
developing and supporting energy policies that provide revenue incentives for biomass-based energy produced by the pulp and paper sector;
establishing a tax structure—particularly municipal property tax rates—that is more in line with competing jurisdictions;
supporting employee training and development at all levels, including apprenticeships, technical training, and management training; and
funding research that encourages knowledge-creation and innovation, while supporting the sawmill sector in making the transition to post-pine beetle forest conditions.
• Abitibi Consolidated • Canfor Corp. • Canfor Pulp Limited Partnership • Cariboo Pulp • Catalyst Paper • Domtar • Howe Sound Pulp and Paper • Mercer International • Neucel Specialty Cellulose • Pope and Talbot • Tembec • West Fraser
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