page 8 TC Alaska license bill must be approved Aug. 2, or license fails Vol. 13, No. 31 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of August 3, 2008 • $1.50 ● NATURAL GAS ● EXPLORATION & PRODUCTION BREAKING NEWS ● NATURAL GAS 10 Yukon Flats land assessment drags on: New USGS data indicates some Doyon land more prospective than earlier thought 13 DOI starts new OCS leasing program: 2010 to 2015 program can apply to whole U.S.; some areas need congressional OK 16 Canadian service sector buoyant: Oilfield service firms upbeat, but investors not buying in, energy stocks down 20% Alaska fits Talisman plan Canada independent includes NPR-A in hunt for ‘material reserves’ By GARY PARK For Petroleum News alisman Energy shows no signs of backing away from its view that Alaska is part of its refocused future on an array of global exploration areas — including such potential flashpoints as the Kurdistan region of Iraq, Colombia and offshore Indonesia — to find oil and natural gas reserves on a grand scale. John ’t Hart, executive vice president of global exploration for the Canadian independent, said Talisman continues to “see lots of opportunity” in Alaska, a view reinforced by Chief Executive Officer John Manzoni. Speaking to analysts July 29, Manzoni said Talisman, operating through wholly owned unit FEX, “derisked the (National Petroleum Reserve-Alaska) program by basically writing off the wells. “That didn’t change the nature of our program,” he said. The intention of a seismic program in NPR-A is to “see if we can find big enough accumulations to justify the next step,” Manzoni said. “We did find hydrocarbons in the earlier wells, but we need bigger accumulations.” Search for material reserves The prospects in Alaska seem to fit the new Talisman strategy, unveiled in May, of embarking on JOHN MANZONI T see TALISMAN page 17 Enstar cutbacks? No new contracts could mean no service for some commercial consumers By ALAN BAILEY Petroleum News he initial sparring is over and the contestants have entered the ring for the next round of the tussle between Enstar Natural Gas Co., the State of Alaska and various gas users over Enstar’s multi-year attempt to establish new gas supply contracts with Cook Inlet gas producers. Enstar’s latest try at filling future supply short- falls, the signing of new gas supply contracts with Marathon Oil Co. and ConocoPhillips Alaska, met the full gaze of public scrutiny on July 28 during the first day of the Regulatory Commission of Alaska’s two-week public hearing on the contracts. When Enstar submitted its revised tariff under the new contracts to RCA in April, Colleen Starring, Enstar’s regional vice president, told the commission that the new contracts fill a gap of some 2.1 billion cubic feet in Enstar’s gas supply portfolio for 2009. Enstar, the local natural gas dis- tribution company for Southcentral Alaska, only has contracted supplies to meet all of its cus- tomers’ needs until the end of 2008. The contracts anticipate that by 2011 Enstar will establish gas storage facilities to reduce the need to purchase gas at the more expensive high-demand price tiers. T see ENSTAR page 18 Pacific Energy gets extension to hire heavy lift vessel for jack-up State oil and gas officials have given a Cook Inlet operator 60 additional days to hire a ship capable of bringing a specialty rig to Alaskan waters. California-based independent Pacific Energy Resources Ltd. now has until Sept. 29 to sign a contract with a heavy lift vessel operator to bring a jack-up rig to Alaska. Pacific Energy recently signed a three-year contract to use a Blake Offshore jack-up rig to drill exploration wells at offshore Cook Inlet prospects such as the Corsair unit. A jack-up rig is a mobile unit well-suited for shallower off- shore drilling, and is seen by many companies as the lynchpin of several proposed exploration ventures in Alaska. Without the rig, many previous ventures have been delayed or abandoned. The Blake 151 jack-up rig is stationed in the Gulf of Mexico, and needs to be towed several thousand miles to Alaska. Pacific COURTESY BLAKE OFFSHORE The Blake 151 jack-up rig is currently stationed in the Gulf of Mexico. BP, Savant get go ahead on Badami; ASRC joins project The state recently approved a plan to restart the shut-in Badami field on the North Slope. The plan of development gives BP and Savant Alaska until Sept. 30, 2009, to drill an exploration well at Badami, or give up a significant portion of the leases in the unit. Savant Alaska, the local subsidiary of Denver-based independ- ent Savant Resources LLC, will run the program on behalf of oil giant BP, the operator and sole working interest owner of Badami. Savant plans to bring new technology to bear on Badami, hop- ing to significantly increase oil recovery at the field long consid- ered promising, but uncooperative. Badami needs investment The partnership brings together one of the oldest and largest players in the state with one of the newest and smallest. BP has been looking at investing more in Badami since 2001, and even tried to farm out acreage in the past, according to Simon see PACIFIC ENERGY page 14 see BADAMI page 19 Big gains for Alaska gas Pipeline could get multi-billion dollar annual boost from federal climate bill By STEFAN MILKOWSKI For Petroleum News hat will federal legislation to curb greenhouse gases mean for Alaska’s oil and gas? According to a recent analysis from the University of Alaska Anchorage Institute of Social and Economic Research, a lot more money for producers and the state. Just how much money will depend on how the legislation is written and how it plays out on the ground, but the cap-and-trade legislation currently before Congress could dramatically improve the eco- nomics of an Alaska natural gas pipeline and add $4 billion to $9 billion in wellhead value each year, according to the analysis. While natural gas would be subject to additional costs because of its carbon content, those costs would be less than the additional value of the gas as a rela- tively low-carbon fuel. Per unit of energy, natural gas produces about half as much of the greenhouse gas carbon dioxide as coal. “There’s likely to be a pretty significant shift right away from coal to gas,” said Steve Colt, an associate W The cap and trade legislation currently before Congress could dramatically improve the economics of an Alaska natural gas pipeline and add $4 billion to $9 billion in wellhead value each year, according to ISER’s analysis. see GAINS page 14
Transcript
page8
TC Alaska license bill must beapproved Aug. 2, or license fails
Vol. 13, No. 31 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of August 3, 2008 • $1.50
● N A T U R A L G A S
● E X P L O R A T I O N & P R O D U C T I O N
B R E A K I N G N E W S
● N A T U R A L G A S
10 Yukon Flats land assessment drags on: New USGS
data indicates some Doyon land more prospective than earlier thought
13 DOI starts new OCS leasing program: 2010 to 2015program can apply to whole U.S.; some areas need congressional OK
16 Canadian service sector buoyant: Oilfield service firmsupbeat, but investors not buying in, energy stocks down 20%
Alaska fits Talisman planCanada independent includes NPR-A in hunt for ‘material reserves’
By GARY PARKFor Petroleum News
alisman Energy shows no signs ofbacking away from its view thatAlaska is part of its refocused futureon an array of global exploration areas
— including such potential flashpoints asthe Kurdistan region of Iraq, Colombiaand offshore Indonesia — to find oil andnatural gas reserves on a grand scale.
John ’t Hart, executive vice president of globalexploration for the Canadian independent, saidTalisman continues to “see lots of opportunity” inAlaska, a view reinforced by Chief ExecutiveOfficer John Manzoni.
Speaking to analysts July 29, Manzoni said
Talisman, operating through whollyowned unit FEX, “derisked the (NationalPetroleum Reserve-Alaska) program bybasically writing off the wells.
“That didn’t change the nature of ourprogram,” he said.
The intention of a seismic program inNPR-A is to “see if we can find big enoughaccumulations to justify the next step,”Manzoni said. “We did find hydrocarbonsin the earlier wells, but we need bigger
accumulations.”
Search for material reservesThe prospects in Alaska seem to fit the new
Talisman strategy, unveiled in May, of embarking on
JOHN MANZONI
T
see TALISMAN page 17
Enstar cutbacks?No new contracts could mean no service for some commercial consumers
By ALAN BAILEYPetroleum News
he initial sparring is over and the contestantshave entered the ring for the next round of thetussle between Enstar Natural Gas Co., theState of Alaska and various gas users over
Enstar’s multi-year attempt to establish new gassupply contracts with Cook Inlet gas producers.
Enstar’s latest try at filling future supply short-falls, the signing of new gas supply contracts withMarathon Oil Co. and ConocoPhillips Alaska, metthe full gaze of public scrutiny on July 28 duringthe first day of the Regulatory Commission ofAlaska’s two-week public hearing on the contracts.
When Enstar submitted its revised tariff under
the new contracts to RCA in April, ColleenStarring, Enstar’s regional vice president, told thecommission that the new contracts fill a gap ofsome 2.1 billion cubic feet in Enstar’s gas supplyportfolio for 2009. Enstar, the local natural gas dis-tribution company for Southcentral Alaska, onlyhas contracted supplies to meet all of its cus-tomers’ needs until the end of 2008.
The contracts anticipate that by 2011Enstar will establish gas storage facilitiesto reduce the need to purchase gas at themore expensive high-demand price tiers.T
see ENSTAR page 18
Pacific Energy gets extension tohire heavy lift vessel for jack-up
State oil and gas officials have given a Cook Inlet operator 60additional days to hire a ship capable of bringing a specialty rig toAlaskan waters.
California-based independent Pacific Energy Resources Ltd.now has until Sept. 29 to sign a contract with a heavy lift vesseloperator to bring a jack-up rig to Alaska.
Pacific Energy recently signed a three-year contract to use aBlake Offshore jack-up rig to drill exploration wells at offshoreCook Inlet prospects such as the Corsair unit.
A jack-up rig is a mobile unit well-suited for shallower off-shore drilling, and is seen by many companies as the lynchpin ofseveral proposed exploration ventures in Alaska. Without the rig,many previous ventures have been delayed or abandoned.
The Blake 151 jack-up rig is stationed in the Gulf of Mexico,and needs to be towed several thousand miles to Alaska. Pacific
CO
URT
ESY
BLA
KE
OFF
SHO
RE
The Blake 151 jack-up rig is currently stationed in the Gulf of Mexico.
BP, Savant get go ahead onBadami; ASRC joins project
The state recently approved a plan to restart the shut-in Badamifield on the North Slope.
The plan of development gives BP and Savant Alaska untilSept. 30, 2009, to drill an exploration well at Badami, or give up asignificant portion of the leases in the unit.
Savant Alaska, the local subsidiary of Denver-based independ-ent Savant Resources LLC, will run the program on behalf of oilgiant BP, the operator and sole working interest owner of Badami.
Savant plans to bring new technology to bear on Badami, hop-ing to significantly increase oil recovery at the field long consid-ered promising, but uncooperative.
Badami needs investmentThe partnership brings together one of the oldest and largest
players in the state with one of the newest and smallest.BP has been looking at investing more in Badami since 2001,
and even tried to farm out acreage in the past, according to Simon
see PACIFIC ENERGY page 14
see BADAMI page 19
Big gains for Alaska gasPipeline could get multi-billion dollar annual boost from federal climate bill
By STEFAN MILKOWSKIFor Petroleum News
hat will federal legislation to curb greenhousegases mean for Alaska’s oil and gas?According to a recent analysis from theUniversity of Alaska Anchorage Institute of
Social and Economic Research, a lot more money forproducers and the state.
Just how much money will depend on how thelegislation is written and how it plays out on theground, but the cap-and-trade legislation currentlybefore Congress could dramatically improve the eco-nomics of an Alaska natural gas pipeline and add $4billion to $9 billion in wellhead value each year,according to the analysis.
While natural gas would be subject to additional
costs because of its carbon content, those costs wouldbe less than the additional value of the gas as a rela-tively low-carbon fuel. Per unit of energy, natural gasproduces about half as much of the greenhouse gascarbon dioxide as coal.
“There’s likely to be a pretty significant shift rightaway from coal to gas,” said Steve Colt, an associate
WThe cap and trade legislation currently
before Congress could dramaticallyimprove the economics of an Alaska
natural gas pipeline and add $4 billion to$9 billion in wellhead value each year,
Petroleum News and its supple-ment, Petroleum Directory, are
owned by Petroleum Newspapersof Alaska LLC. The newspaper ispublished weekly. Several of theindividuals listed above work forindependent companies that con-
tract services to PetroleumNewspapers of Alaska LLC or are
OWNER: Petroleum Newspapers of Alaska LLC (PNA)Petroleum News (ISSN 1544-3612) • Vol. 13, No. 31 • Week of August 3, 2008
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FINANCE & ECONOMYBP reports $9.465 billion in 2Q profits
London oil giant BP made $9.465 billion during the second quarter of the year, a28 percent increase over the second quarter of last year, the company reported on July29.
The company does not break out Alaska-specific financial information on a quar-terly basis, but BP’s Alaska operations have accounted for 10.3 percent of total annu-al profits for the company on average over the past five years.
Through the first half of the year, BP made nearly $17 billion in profits company-wide.
Over the second quarter of the year, BP reported an average market price of$123.61 per barrel for Alaska North Slope crude oil delivered to the West Coast
By comparison, ConocoPhillips reported an average delivered price of $118.88 perbarrel over the same time period, and the state Tax Division reported an average spotprice of $123.85 per barrel for the three-month period of April through June.
BP has paid around $500 million in Alaska production taxes each quarter this yearas the result of increased prices and a tax code revision enacted by state lawmakersthis past fall, according to Andy Inglis, chief executive of exploration and production.
Following similar comments from ConocoPhillips executives, Inglis also said BPwould proceed on plans to build a natural gas pipeline in Alaska regardless of whetherstate lawmakers award a license for the project to TransCanada. BP andConocoPhillips formed a joint venture in April to pursue the pipeline project.
Inglis also said Exxon has been invited to join the project.—ERIC LIDJI
Marathon considering split of businessesMarathon Oil is considering a plan to split the corporation into two independ-
ent companies, one focused on upstream activities and one focused on down-stream activities.
Marathon said it has been considering the idea for several months, but proba-bly won’t make a final decision until the fourth quarter of this year. If the boardof directors chooses to continue with the plan, the separation would take placeearly next year.
The company announced the proposal with second-quarter financial figures onJuly 31, but company executives declined to elaborate on the proposal.
According to a press release, “One entity would consist of the Company’sExploration and Production, Integrated Gas, and Oil Sands Mining businesses;and the other entity would consist of the Company’s Refining, Marketing andTransportation business.”
Marathon is one of the larger producers of natural gas in the Cook Inlet, as wellas a part owner of a liquefied natural gas facility on the Kenai Peninsula and sev-eral pipelines.
—PETROLEUM NEWS
EXPLORATION & PRODUCTIONSunshine Oilsands sheds light on plans
After 18 months of busily and quietly accumulating 677,000 acres of properties atAlberta government land sales, startup Sunshine Oilsands has unveiled plans to spendan initial C$380 million.
The company, formed in February 2007, has so far invested C$100 million on landacquisition and completing 58 core holes last year. It has an estimated resource of 14.2billion barrels, divided between Cretaceous sands and Devonian carbonates.
It has earmarked four steam-assisted gravity drainage projects at sites close to TotalE&P Canada, Chevron Canada, Athabasca Oil Sands and Grizzly Oil Sands, with a 100percent working interest in all of its assets except for a 5,120-acre farmout.
The first development involves a 10,000 barrel-per-day project at West Ells, wherenet pay over more than 10,000 acres is estimated at 40-80 feet.
An application for the first of three phases is expected to be filed late this year.Sunshine is targeting an average capital cost of C$25,000 per flowing barrel.Between West Ells and other land holdings at Thickwood there are 32,000 acres that
Sunshine believes can support production of 130,000 bpd, the company told a recentoil sands forum. Further delineation through winter drilling is expected to see an appli-cation for a 10,000-bpd first-phase project at Thickwood filed late in 2009.
Plans for Sunshine’s carbonate area at Harper include six wells this winter and apossible 6,000-bpd facility, developed in three equal stages.
Financing has been done through private investors and institutions and none ownsmore than 10 percent. An initial public offering is scheduled for the fourth quarter andpartners are being scouted, although the company has said a partner is not essential forwork to progress.
—GARY PARK
● I N T E R N A T I O N A L A R C T I C
Arctic ice: more there, less hereNorwegian report ice buildup north of the Svalbardarchipelago but ice has broken from the Ward Hunt shelf
By ALAN BAILEYPetroleum News
n apparent contradiction to a multi-year trend of shrinking ice cover in theArctic, the Norwegian MeteorologicalInstitute has reported more sea ice
than normal north of the Svalbard archi-pelago, in the northwestern Barents Sea.Although the area is normally ice-free inJuly, there is an extensive ice cover thisyear, the institute says.
And according to a report in theBarents Observer the Norwegian CoastGuard has had to assist two vessels thatbecame stuck in the ice.
The ice situation seems different in theCanadian Arctic, however. According to areport by the BBC, satellite pictures haveshown that an eight-square-mile chunk ofthe Ward Hunt shelf has split away fromEllesmere Island. (See related story onpage 11 of this issue.)
The Arctic is experiencing anotherrapid ice retreat in 2008, although the iceminimum is unlikely to exceed the 2007minimum, the report says.
A scientist from Trent University inOntario told the BBC that the currentwarming trend in the Arctic makes itimprobable that the ice shelves that breakup can regenerate. ●
Turning coal into liquid fuelCalgary startup plans to build C$4.5B plant to produce 40,000bpd of fuel by 2014; project to include CO2 capture for EOR
By GARY PARKFor Petroleum News
small Calgary company is preparedto lead the rest of Canada in convert-ing coal into liquid petroleum fuels,with plans for a C$4.5 billion project
to produce 40,000 barrels per day over 50years starting in 2014.
Alter NRG proposes to turn coalreserves in northwestern Alberta into dieselfuel and naphtha — a heavy oil productused for paving roads and for diluting bitu-men from the oil sands — employingproven processes that have been in com-mercial options around the world for morethan 30 years.
The company started a strategic partnerselection process earlier this year andexpects to disclose its financing plansbefore the end of 2008.
“As the first coal-to-liquids project inCanada, the project will be a significant,long-term contributor to Alberta’s economyas well as set a precedent for clean energysolutions,” said Alter NRG Chief ExecutiveOfficer Mark Montemurro.
He said the venture can break even withoil prices at $50-$60 per barrel and generatereturns at $80.
Each flowing barrel of coal-to-liquidsproduction would require a capital invest-ment of $110,000 per barrel, roughly in linewith larger oil sands plants.
A process for turning coal into liquidfuel was developed in the 1920s and wasused by Germany to produce syntheticdiesel during the Second World War.
Alter NRG owns 460 million metric tonsof proven plus probable coal reserves and876 million metric tons of coal resource.
It plans to mine two blocks containing301 million metric tons using establishedsurface mining technology, then use com-mercially proven gasification and otherprocesses to produce diesel and naphtha.
The coal deposit was chosen partlybecause of its proximity to infrastructureand mature oil fields that would benefitfrom enhanced oil recovery by the injectionof carbon dioxide.
The plans include the sale of producedcarbon dioxide into the enhanced oil recov-
ery market. More than 85 percent of CO2produced by the project will be captured forsequestration in deep saline aquifers or indepleted oil or gas pools.
Alter NRG has identified 30 pools thatare suitable for EOR with original oil-in-place of 7.6 billion barrels and an ability tostore 228 million metric tons of CO2. Thecompany estimates that total CO2 requiredfor EOR in the pools will amount to anaverage demand of 27,000 metric tons perday.
Over the 50-year operating life, the coalwill be mined at a maximum rate of 9.2 mil-lion metric tons per year.
Using a modified Fischer-Tropschprocess designed specifically to produceultra-clean diesel, the gasifier will convertsolid coal feedstock into syngas, which willbe further processed into liquids, with aplanned emphasis on low-sulfur, high-cetane diesel.
A similar coal gasification plant run byDakota Gasification Co. in North Dakotasupplies CO2 to EnCana’s EOR field atWeyburn in southern Saskatchewan.
Montemurro said it was a deliberatemove on Alter NRG’s part to choose a loca-tion where the coal reserves are on top of oilfields.
“We think this gives us a distinct strate-gic advantage,” he said.
Mary Griffiths, a senior policy analyst atthe Alberta-based Pembina Institute, saidthe environmental think tank prefers renew-able energy sources over fossil fuels, butconceded that gasification is probably theleast damaging method.
Because of the potential damage to landand water from strip mining the coal, shesaid Pembina would prefer to see the CO2stored deep underground rather than usedfor EOR.
But Griffiths credited Alter NRG for itspublic disclosure.
Montemurro is a former executive withoil sands startup Deer Creek Energy, whichwas acquired in 2005 by France’s Total.
Michael Heier, chairman of Alter NRG’sboard, is former chief executive officer andcurrent chairman of Trinidad Drilling, oneof Canada’s fastest-growing drilling andwell service contractors. ●
A
LAND & LEASINGBLM sets September NPR-A lease sale
The fall National Petroleum Reserve-Alaska lease sale will be held Sept. 24. The U.S. Department of the Interior’s Bureau of Land Management said July 25
that it will offer lands for lease within the NPR-A Sept. 24. The record of decisionfor the Northeast NPR-A supplemental integrated activity plan was signed July 16and the environmental assessment for the Colville River Special Area has beencompleted, BLM said, providing the framework for the oil and gas lease sale.
Lands within the Northeast NPR-A and a portion of the Northwest NPR-A willbe offered.
“We are looking forward to this lease sale,” Alaska State Director Tom Lonniesaid in a statement. “As new and existing leases are explored we will ensure thatdevelopment of the resource is conducted in an environmentally safe manner so theimportant biological, subsistence and cultural values of the NPR-A are protected.”
The lease sale will be held in the ZJ Loussac Library in Anchorage; BLM saidadditional information will be available when the notice of sale is published in theFederal Register in August.
—PETROLEUM NEWS
North Slope, Beaufort Sea sale date setThe state will open bids Oct. 22 for its 2008 North Slope and Beaufort Sea
areawide oil and gas lease sales. The Alaska Department of Natural Resources Division of Oil and Gas said July
25 that the bid opening will begin at 9 a.m. at the Wilda Marston Theater at theLoussac Public Library in Anchorage.
The North Slope areawide sale lies between the Arctic National WildlifeRefuge and the National Petroleum Reserve-Alaska; the southern boundary is theUmiat baseline.
The Beaufort Sea sale includes state-owned tide and submerged lands fromPoint Barrow to the Canadian border. Beaufort Sea tracts 27 through 39, east ofKaktovik, and tracts 555 and 557 through 573, between Tangent Point and PointBarrow, are deferred from this lease sale.
Minimum bid is $10 per acreBoth sales have cash bonus bidding with a minimum bid of $10 per acre on all
tracts. Royalty rates and length of lease vary by area. For the North Slope sale, all tracts north of the North Slope royalty line have
a fixed royalty rate of 16.66667 percent and a lease length of five years; all tractssouth of the North Slope royalty line have a royalty rate of 12.5 percent and alease term of seven years.
For the Beaufort Sea sale, tracts 1 through 26 have a fixed royalty rate of 12.5percent; all other tracts have a fixed royalty rate of 16.66667 percent.
There are three lease lengths in the Beaufort Sea sale: Tracts 1-26 have a 10-year lease term; tracts 40-77, 500-554 and 556 have seven-year terms; and allother tracts have five-year terms.
For details, including tract deletions, tract deferrals and maps, see the divi-sion’s Web site at www.dog.dnr.state.ak.us/oil/.
hree decades of operation of thetrans-Alaska oil pipeline demon-strate that the State of Alaska can’tafford to get the tariff on a gas
pipeline wrong, Richard Fineberg toldlegislators July 25. Fineberg said hereported on the building of the oilpipeline and has been involved for yearsin tariff issues on that line. The statestands to lose billions in revenue on a too-high tariff for shipping natural gas, hesaid, and North Slope competition wouldagain be inhibited, jeopardizing futuredevelopment.
Fineberg testified before the AlaskaSenate Special Committee on Energy ona report he wrote for the Alaska PublicInterest Research Group about questionshe believes aren’t addressed in the state’sfindings on AGIA. Natural gas contractsand tariff issues are complicated, and inspite of the time legislators have put in onthe TransCanada Alaska applicationunder the Alaska Gasline InducementAct, the level of complication and thedetails issues turn on are “orders of mag-nitude more complicated” than what leg-islators have gotten to yet, he said.
Fineberg said information will be crit-ical in dealing with tariff issues on a gaspipeline. AGIA, in spite of the time, ded-ication and intent of those who crafted it,lacks essential safeguards to ensure thatthe Federal Energy RegulatoryCommission will deliver low tariffs, hesaid.
A critical component is “guaranteedaccess to all the critical information in atimely manner,” Fineberg said, includinginformation needed “to ensure state rev-enues and the maintenance of open com-petition that hinge on the attainment oflowest reasonable tariffs.”
Fineberg said FERC regulators havehad little occasion to deal with tariffissues on producer-owned gas pipelinesand the AGIA proposal “lacks systematicsafeguards to protect against the possibil-ity that unscrupulous parties might usevarious accounting devices to artificially
elevate reported costs and filed tariffs,thereby overcharging shippers and reduc-ing state revenue.”
Recourse tariff a ceilingFineberg said he believes the tariff
process opens “with a bad beginning,”the recourse or ceiling tariff — the high-est rate that can be charged. This is notthe low tariff; it’s the ceiling, he said.
When it sets tariffs for natural gaspipelines, Fineberg said in his report,FERC starts out with preliminary costestimates and a projected tariff, therecourse tariff. That rate is proposed bythe shipper as part of its FERC applica-tion and “effectively sets a ceiling for fur-ther tariff negotiations between thepipeline company and prospective ship-pers,” he said.
Then there is the negotiated tariff, arate negotiated between the pipeline andshippers. Because the shippers are theproducers, the experience with the trans-Alaska oil pipeline is that shippers don’treduce tariffs, they go for high tariffs,Fineberg told legislators. And as a rule,there are no refunds on negotiated tariffsbecause the shippers are supposed tonegotiate the recourse rate down.
Asked by Sen. Bill Wielechowski, D-Anchorage, if he’s found higher tariffs forindependent pipelines or producerpipelines, Fineberg said he hasn’t donethat research, but he said Barry Pulliam(of Econ One) presented such data in theadministration’s AGIA presentations inJune. That data showed a 19 percent aver-age reduction from the recourse rate tothe negotiated rate on independent
pipelines, Fineberg said. On AlliancePipeline, developed by producers whohave since sold their interest, Pulliam’sdata showed no reduction from therecourse to the negotiated tariff.
Fineberg said he looked at the Alliancerates and found the negotiated tariff hadincreased over the recourse rate becauseof cost overruns.
So there is evidence of reductionbetween the recourse rate and negotiatedrates on independent lines, Fineberg said,but only limited evidence for producer-owned lines. There are very few exam-ples of such lines because for many yearsthe U.S. banned producer-owned linesand so there aren’t many of them;Alliance is a good example because itwas a large project, costing $5 billion, hesaid.
Remedies — information As for remedies, Fineberg said the
state needs access to “timely and com-plete information,” which it doesn’t havenow.
If AGIA is set in motion, the stateneeds to begin immediately preparing towork on costs to be sure the recourse tar-iff doesn’t set the bar too high, he said.Ongoing accounting and oversight willalso be necessary: After the 2006Petroleum Profits Tax was passed itbecame clear the state didn’t have theaccounting mechanisms and that had tobe fixed in ACES, Alaska’s Clear andEquitable Share, the legislation passed in2007 under the Palin administration, hesaid.
Fineberg said accounting and over-sight are needed for both in-state issuesand for issues that will arise beforeFERC.
There are gray areas where producersand shippers will have an interest in max-imizing their revenue; and the producersmay not negotiate the pipeline down onthe tariff, he said. One area that hasn’tbeen discussed is inappropriate gaming,especially on issues where the interests ofthe majors differ from those of independ-ent shippers, Fineberg said.
Committee Chair Charlie Huggins, R-
Wasilla, and Sen. Tom Wagoner, R-Kenai, asked if producer ownership in aline wouldn’t mean that the producerswould work to get a lower tariff.
Fineberg said it would take real num-bers, and incredibly complicated model-ing, to determine at what point the pro-ducers’ interest in a low tariff vanishes.
Interests turn on “very subtle things,”he said, and one of them is whether theincome tax effect is correctly understood.Fineberg said there are tax benefits thatcould conceivably change the answer andsaid he believes that if the state spent thetime to work through all of the numbersthere would be surprises and lawmakerswouldn’t be quite so comfortable becausethere are variables the state cannot con-trol, and one of them is taxes.
Steve Porter, a consultant for theLegislative Budget and Audit Committee,said FERC will go for a reasonable tariffand AGIA set parameters on a tariff, butthe only party that can protect the inter-ests of the state is the state. Porter agreedwith Fineberg’s recommendation that thestate participate in tariff hearings beforeFERC and the National Energy Board ofCanada.
Asked by Sen. Kim Elton, D-Juneau,whether it would require a change inAGIA for the state to participate in tariffhearings, Porter said the state has theright to represent itself before FERC orNEB for the TransCanada Alaska pipelineand for the Denali pipeline.
Huggins asked about some of the costestimates Fineberg cited for theTransCanada Alaska project and Finebergcited work Goldman Sachs did for theadministration with a median $46 billioncost.
Fineberg said that with penalties forcost overruns built into its proposal, thestate should expect TransCanada to high-ball every cost it legally can so it can geta higher rate of return by avoiding thepenalty. He also said he is concerned thatthe state wants to tie up the federal loanguarantees to cover possible cost over-runs when those guarantees could be usedupfront to cut the cost. He said itappeared the state has traded off the gainof loan guarantees and has given itsshare to the pipeline company.
Additional questionsAt the request of Huggins Fineberg
put some fundamental questions aboutgas pipeline tariffs to the committee in aJuly 26 follow-up letter.
He said the average litigated naturalgas rate case at FERC is roughly 50months, with a 36-month average for acontested settlement. He asked what theaverage time was for such cases by proj-ect size ranging from greater than $20billion to greater than $1 billion.
Fineberg asked about the likelihoodthat FERC can assure just and reason-able rates without competition fromother pipelines to test the rates and ratestructure and whether FERC or theTransCanada Alaska AGIA proposal“contain substantive language to ensurethat the veil of confidentiality imposedat the nuts-and-bolts level of this arcaneprocess will not prevent parties with aninterest in inflating their tariff numbersfrom disclosing the information thatwould enable those harmed by the par-ticular transaction from obtaining, in a
6 PETROLEUM NEWS • WEEK OF AUGUST 3, 2008
● N A T U R A L G A S
Fineberg says state needs informationIndependent researcher says getting it wrong on gas tariff could cost state billions; preparation needs to start now for FERC
Fineberg said in his report that hedoes not believe the state can relyon FERC to ensure low tariffs, and
recommends that the state“establish an ad hoc oversightgroup to ensure that the state
maintains a pro-active posture inits efforts to assure low pipelinetariffs on the AGIA pipeline.”
T
see FINEBERG page 8
PETROLEUM NEWS • WEEK OF AUGUST 3, 2008 7
FINANCE & ECONOMYTotal adds to total in Synenco Energy
France’s Total made no secret of its determination to complete a takeover ofAlberta oil sands startup Synenco Energy.
Having previously extended the deadline on its offer, wholly owned Total E&PCanada effectively locked up the deal July 24 by raising the all-cash offer toC$10.25 a share from C$9 to win over two U.S.-based holdout investors.
As a result of the sweetened offer, Total was able to enter agreements withinstitutional heavyweights — D.E. Shaw, which owns 14 percent of Synenco, andWellington Management, with 10 per-cent — adding them to the 58 percent ofshares tendered since April.
The transaction required support fromowners of 66 percent of shares, butcrossing that threshold required twoextensions of the deadline before Totalboosted the value of its all-cash offer toC$530 million from an initial C$478 mil-lion.
Synenco has 60 percent of NorthernLights oil sands project
Synenco controls 60 percent of theNorthern Lights project, which has a“best estimate” of 1.657 billion barrels of discovered resource and plans to pro-duce 114,500 barrels per day of bitumen when fully operational, turning that into100,000 bpd of light sweet synthetic crude over 28 years.
SincoCanada Petroleum, an indirect wholly owned subsidiary of China’sSinopec, owns the remaining 40 percent of the partnership and project.
In addition, Synenco holds 100 percent of the McClelland oil sands lease adja-cent to the Northern Lights lease.
Synenco couldn’t carry weightBut, despite its innovative attempts to curb costs by unveiling plans to manu-
facture and import Northern Lights modules from Asia, Synenco was unable tocarry the financial weight of building a C$10.7 billion mine and upgrader.
Total has openly declared its goal of producing 500,000 bpd from the oil sandssometime in the next decade.
So far, it has the controlling 74 percent stake in the Joslyn project and plans touse surface mining to develop two phases of 200,000 bpd each.
At the ConocoPhillips-operated Surmont, Total owns 50 percent of the projectthat started commercial production last November and expects to reach 25,000bpd by 2012. A second phase due for startup in 2015 is expected to add 75,000bpd.
Total has also initiated plans to build an upgrader near Edmonton, with capac-ity of 245,000 bpd, although cost inflation has slowed progress on that venture.
which has a “best estimate” of1.657 billion barrels of
discovered resource and plansto produce 114,500 barrels per
day of bitumen when fullyoperational, turning that into
100,000 bpd of light sweetsynthetic crude over 28 years.
● N A T U R A L G A S
ANGDA and Enstarwait and workOrganizations haven’t met since announcement of in-state pipelinepartnership, but agree on work needed to advance the project
By ERIC LIDJIPetroleum News
n the three weeks since Gov. SarahPalin announced a public-private part-nership to build an in-state gas pipelinewithin five years, the organizations
involved share a view of the near termwork needed to advance the project, butcontinue to pursue independent ventures.
“We’re continuing with thework plan that we had devel-oped,” Enstar spokesman CurtisThayer told Petroleum News onJuly 30. “We assume ANGDA isproceeding with the work planthey developed. Then we’ll sitdown and compare apples toapples and oranges to oranges.”
Under the partnership Palinoutlined on July 7, the AlaskaNatural Gas DevelopmentAuthority and Enstar NaturalGas Co. would work to build asmall pipeline from Cook Inletto Fairbanks by 2013 or to thefoothills of the Brooks Range by2014.
The move was meant as amidterm solution to two prob-lems: the rising cost of energy inFairbanks and the declining nat-ural gas supply in the CookInlet.
The Palin administration believes mar-kets in Fairbanks will spur development inthe Cook Inlet. If that assumption iswrong, the pipeline will simply continuenorth until it hits a supply source, either inthe foothills of the Brooks Range or on theNorth Slope.
Separate projects in worksANGDA and Enstar have been sepa-
rately working on similar, but mutuallyexclusive projects to deliver Alaska natu-ral gas to in-state markets.
ANGDA wants to build a spur off alarger gas pipeline running from the NorthSlope to markets in North America. Enstarwants to build a bullet line running direct-ly from the Gubik gas field north of theBrooks Range to the existing pipeline gridin Anchorage.
They also favor different routes:ANGDA has been studying theRichardson Highway, a route the stateprefers, while Enstar is looking at theParks Highway.
By bringing the two together, the statehopes to combine Enstar’s experience as apipeline builder and operator withANGDA’s ability to secure public financ-ing.
Must design business setupBut public companies and private com-
panies don’t operate the same way, espe-cially when it comes to buying goods andservice, and financing capital projects.
Enstar and ANGDA agree on the needto determine the structure of a future busi-ness relationship, and on the need to com-pare the work each company has alreadycompleted toward an in-state pipeline tofind what gaps might still remain.
“We are prepared to enter those discus-sions. I’ve informed both the state and
Enstar of that.” Harold Heinze, chief exec-utive officer of ANGDA, said at a boardmeeting in Fairbanks on July 30. “Thatmeeting has not occurred.”
Enstar is ready, too, Thayer said, butthe time-consuming deliberations sur-rounding the Alaska Gasline InducementAct have prevented the parties from meet-ing with the state.
“Everybody’s in Juneau right now,”Thayer said. “We’re in
Anchorage.”Thayer expects Enstar and
ANGDA to meet with the statein September, after the sum-mer special legislative ses-sions have come to an end.
“We’ll be talking and we’llfigure out whether we’re goingto come together,” ANGDAChairman Scott Heyworth saidat a board meeting in
Fairbanks. “And it may or maynot work out, but that’s just whatwe’re dealing with exploringright now.”
The proposal for theANGDA-Enstar partnershipcame together quietly in theweek before Palin made theannouncement, and the twocompanies met for about anhour later that afternoon. So far,
that has been the extent of the interactionbetween them.
Heinze and Heyworth both insist thepartnership is simply an idea to pursue,not a mandate from the governor or abinding business arrangement forcing anyaction. Heinze said ANGDA wouldn’tstart a formal partnership with Enstarwithout board approval.
Summer fieldwork continuesIn the meantime, both organizations are
continuing existing fieldwork programs.Enstar is spending $6 million this year
to study a possible pipeline corridorbetween Gubik and Anchorage along theParks Highway.
Anadarko Petroleum drilled an explo-ration well at Gubik this winter, but hasyet to release details about the amount ofgas it believes the field contains.
In mid-July, about a week and a halfafter the announcement of the partnershipproposal, Enstar and Anadarko met in pri-vate to discuss the Gubik and Chandlerfields. Thayer said Anadarko plans toreturn to the fields this winter to drill moreexploration wells, but doesn’t have anynew estimates about the potential reservesat the site.
ANGDA currently has a contractor inthe field mapping the RichardsonHighway route to gather informationneeded for a wetlands permit from theU.S. Army Corps of Engineers.
ANGDA also recently hired a companyto study possible connections betweenGubik and the existing corridor of thetrans-Alaska oil pipeline. Although theproject likely duplicates work Enstar plansto conduct, Heinze said ANGDA’s goal isto put as much information into the publicdomain as possible.●
timely manner, the information theywould need to identify the problem,assess its significance, understand itsmechanics and respond to protect theirinterests?”
‘Eerie similarity’Fineberg said he sees an “eerie simi-
larity” between where the state is with theAGIA TransCanada Alaska gas pipelineproposal and where the state was in 1985
when it reached a settlement on the oilpipeline tariff, a settlement since over-turned by both the RegulatoryCommission of Alaska and FERC ongrounds that the rates established werenot just and reasonable.
That cost the state billions, he remind-ed the committee.
On the other hand, in his 27-pagereport for AkPIRG, dated July 22,Fineberg said he has watched “with grow-ing admiration” as the state’s citizen leg-islators, over the last two years, “buckleddown to the gritty, painstaking tasks oflearning as much as they could about
complicated issues before punching thered or green button.”
And over those same two years, “Ihave been delighted to see administrationpersonnel break old habits of interdepart-mental skirmishing and indifference tothe public to work together as a weldedteam intent on conducting genuine publicoutreach.”
But the similarities to 1985 remain, hesaid: “Once again, the enormity and com-plexity of the terrain make it difficult tofigure out where the arcane mechanics oftariff formulation and implementation fitinto that landscape.”
Ad hoc oversight groupAGIA does not prevent the state from
challenging a tariff proposed byTransCanada Alaska, but Fineberg saidCommissioner of Revenue Pat Galvin hasacknowledged the state would carefullyconsider the interests of its partner beforeadvocating a reduction.
The state signed off on the 1985 settle-ment on the trans-Alaska oil pipeline tar-iff, including a “duty to defend” clausenegotiated by the Department of Law,which “effectively handcuffed the stateon tariff issues for more than twodecades,” Fineberg said in his report. Hewent on to say that the state cannot affordsuch restrictions on a natural gas pipeline,“where the FERC regulatory regimeappears to offer fewer remedies andgreater incentives for high pipeline tar-iffs.”
“Instead of focusing on tariff mechan-ics and implementation, the administra-
tion is content to kick that can down theroad with the observation that nothing inthe AGIA contract worsens the existingsituation,” Fineberg said.
Fineberg said in his report that he doesnot believe the state can rely on FERC toensure low tariffs, and recommends thatthe state “establish an ad hoc oversightgroup to ensure that the state maintains apro-active posture in its efforts to assurelow pipeline tariffs on the AGIApipeline.”
TransCanada speaks of its experiencein opening basins, he noted, but an“industry veteran says the industry strivesfor basin control.” Fineberg said thatgiven the history of the trans-Alaska oilpipeline, “it would be a mistake to assumethe former approach to basin develop-ment is operable but the latter is not.”
Why the concernFineberg said in his report that access
to confidential data has shaped his views. “At the end of the day, I believe it is
the recognition of the importance of with-held confidential information — to whichI have had access in various cases overthe past three decades while working withvarious state and federal agencies on tax,royalty and ratemaking issues — that mayexplain why I have parted company fromothers engaged in this process whom Igreatly respect.”
Based on that experience, he said hebelieves the state needs “full and timelyaccess” to information in order to protectits own interests and those of independentdevelopers.
“In my experience, pipelines (due togeographic realities) and bureaucracies(due to the multiple responsibilities of theplayers) are both inherently vulnerable toinformation short circuits,” he said in hisJuly 26 letter to the committee. “For thisreason, I am particularly worried aboutinformation constraints when the largestpipeline project ever undertaken on thiscontinent will span 1,715 miles much ofwhich is in another country with differenttax, regulatory and oversight frameworks.Without affirmative, advanced resolutionof this issue, the state will remain vulner-able to the consequences of tariff gam-ing.” ●
8 PETROLEUM NEWS • WEEK OF AUGUST 3, 2008
continued from page 6
FINEBERG
● N A T U R A L G A S
TC Alaska license reaches Senate floorBill must be approved Aug. 2, or license fails; Bipartisan Working Group splits votes in ‘super committee’ vote to move bill
By KRISTEN NELSONPetroleum News
he TransCanada AGIA license edged outof the Alaska Senate Special Committeeon Energy, the so-called super commit-tee, by a vote of 7 to 5 the evening of
July 30. Senate floor debate was the next step; the
Senate hadn’t gaveled in yet when PetroleumNews wrapped up this issue midday July 31.The House passed the bill July 23 and thelicense fails if not approved by both House and Senateby midnight Aug. 2.
Amendments in the Senate are expected to includetwo offered and withdrawn in committee by Sen. LesilMcGuire, R-Anchorage.
Both amendments would delay implementation of thebill — which left the House stripped of an effective date— one for the commissioners of Natural Resources andRevenue to impose an appropriate indemnification forthe State of Alaska against possible claims from with-drawn partners of the 1970s Alaska portion of the line,the other requiring mediation before the license can beissued.
McGuire, one of those voting against moving the bill,insisted the amendments were not meant as poison pills.Also voting against moving the bill were the commit-
tee’s chair, Charlie Huggins, R-Wasilla; its vice chair,Bert Stedman, R-Sitka; Senate President Lyda Green, R-Matanuska-Susitna; and Lyman Hoffman, D-Bethel,Stedman’s co-chair on the Finance Committee
The Senate special committee combines SenateFinance and Senate Resources, and brought 12 of theSenate’s 20 members to the table.
Members voting in favor of moving the bill wereSens. Fred Dyson, R-Eagle River; Kim Elton, D-Juneau;Donny Olson, D-Nome; Gary Stevens, R-Kodiak; JoeThomas, D-Fairbanks; Tom Wagoner, R-Kenai; and BillWielechowski, D-Anchorage.
Dyson and Wagoner, both voting to move the bill, arein the five-member Senate Republican Minority. The 10members of the 15-member Senate Bipartisan WorkingGroup split their votes.
Former governors oppose AGIAThe committee began the week with a
rousing call from former Gov. Wally Hickelto reject colonialism and build an all-Alaskagas pipeline from Prudhoe Bay to Valdez.
“Don’t sell us out,” Hickel told the com-mittee July 28.
He said Gov. Sarah Palin made the wrongdecision in going with a line through Canada,but told legislators that if they reject theTransCanada Alaska AGIA license, he thinks
Palin will re-embrace the all-Alaska line (Palin is a formersupporter of the line to Valdez and liquefaction of gas forshipment).
Former Gov. Tony Knowles, a Democrat, also opposesAGIA, telling the committee he fears it would hinder — notpromote — development of North Slope natural gas. Theprice of gas makes an Alaska gas pipeline commerciallyviable, Knowles said, and the state shouldn’t be giving anexclusive license, but should be stepping forward with aviable business plan.
He said AGIA is a “very wrong” decision for the State ofAlaska and its “passage could snatch defeat from the jawsof victory.”
The state should put the AGIA license on the shelf andidentify participants and areas of negotiation. The state has
never been afraid to negotiate in 50 years ofstatehood, Knowles said, and shouldn’t beafraid to negotiate now.
Why not changeThe committee had a lot of questions
July 29-30 for the administration andTransCanada.
Commissioner of Revenue Pat Galvinwas asked by several members why AGIAcouldn’t be changed.
Galvin said AGIA created a competitiveprocess and if the terms of AGIA arechanged now, the competitive process ofthe last nine months will be cast aside. Hetold the committee it would probably becleaner just to vote no on the license andcome back later and do a different one,although he said the administration doesn’tthink that would be in the state’s best inter-est.
Don Bullock, an attorney withLegislative Legal Services, said legislatorsprobably needed to compartmentalizethings that were a problem with AGIA andthings that were a problem with the appli-cant. If the applicant meets the requirementsand doesn’t maximize benefits to the state,then maybe there is a problem with AGIA,he said.
Withdrawn partners an issueSome committee members were still
concerned about the withdrawn partners’liability, and whether the state should seekto be indemnified against such a liability.The withdrawn partners’ issue relates to theoriginal proposal to build a line in the 1970s— and to the Alaska portion of the line only.
Galvin said there were two risk compo-nents — the risk the liability would betransferred into the tariff and the risk that aparty joining TransCanada Alaska as a part-ner would become liable, if it were deter-mined to be a real liability.
TransCanada has committed, he said,that if there is a liability they will not put itinto the tariff.
Bonnie Harris, senior assistant AttorneyGeneral for oil and gas, said the legal per-spective is consistent with Galvin’s expla-nation: Research hasn’t shown how issuinga license could create liability to withdrawnpartners. And the state is protected on thetariff side by TransCanada’s commitmentnot to roll any withdrawn partners’ liabilityinto the tariff, Harris said.
Galvin said if the state ever decided tobecome an equity partner withTransCanada, it would discuss the with-drawn partner liability with TransCanadaagain at that time.
Adding indemnification?McGuire asked about amending AGIA
to add indemnification for the withdrawnpartner liability to the statute.
Galvin said adding indemnificationwould change the terms of AGIA invalidat-ing the competitive process that producedthe license.
Wielechowski asked what the harmwould be if the AGIA must haves wereamended to include a statement that anyonewith a withdrawn partner liability mustindemnify the state for that.
Galvin said he understood from bothBullock and Harris that by changing themust haves a requirement has been added tothe state’s completeness review thatTransCanada will not have met. The com-pleteness review would be eliminated, hesaid, and would put the state back in a posi-tion of having to start the process over.
Commandeering gas Dyson asked TransCanada Vice
President Tony Palmer to comment on a
suggestion the committee had heard thatgas would be commandeered in Canada.Dyson said it was his understanding thatshippers put gas into the line andTransCanada would deliver it for them, andasked Palmer to talk about circumstances inwhich the government of Canada couldcommandeer Alaska gas.
Palmer responded that there is a treatybetween the U.S. and Canada which pro-tects gas in transit from one country into theother and back. He said some gas inTransCanada’s pipelines goes from Canadainto the U.S. and back into Canada everyday, so the treaty is applied to protectCanadian gas and would protect U.S. gas inthe same way.
Palmer said he is not aware of howCanada could commandeer Alaska gas, anddoesn’t know why it would want to as thereis a surplus of gas in Canada which isbeing exported. ●
PETROLEUM NEWS • WEEK OF AUGUST 3, 2008 9
GOVERNMENTStevens indicted, vows to fight charges
The indictment of Alaska Republican Sen. Ted Stevens on charges that he liedabout accepting gifts from an oilfield service contractor only adds to his party’salready bleak electoral prospects in November.
While Stevens has vowed to fight charges and, through a spokesman, to move “fullsteam ahead” with his re-election bid, he’s received little support from the country’stop Republican, President Bush. The only reaction to Steven’s indictment came fromWhite House press secretary Dana Perino who said, “The president has been workingwith Sen. Stevens for many years and he appreciates his strong leadership on keyissues. This is a legal matter that the Department of Justice is handling, and so we willnot comment further on it.”
Stevens, who returned to work in the Senate July 30, has been stripped of his com-mittee leadership posts under GOP rules. He is scheduled to be arraigned in federalcourt July 31. It will be up to a judge to decide where he can travel, whom he needsto check in with and what rules he must follow as he campaigns and continues work-ing as a senator.
Stevens is charged with taking more than a quarter-million dollars worth of unre-ported gifts from oil services contractor VECO Corp. and its executives will play rightinto Democratic efforts to paint Republicans as a party captive to the oil industry.
Stevens, 84, said July 29, “I am innocent of these charges and intend to prove that.”“Our office has been flooded today with calls and e-mails from supporters urging
the senator to press on,” campaign spokesman Aaron Saunders said.Alaska Gov. Sarah Palin told reporters July 29 that it “would be premature at this
point” to demand that Stevens resign. —THE ASSOCIATED PRESS
continued from page 8
AGIAPalmer said he is not aware of
how Canada could commandeerAlaska gas, and doesn’t know why
it would want to as there is asurplus of gas in Canada which is
ppraising the land for a proposed landswap between Doyon Ltd. and theU.S. Fish and Wildlife Service in theYukon Flats of Interior Alaska is tak-
ing quite a long time, primarily because ofthe effect of rising oil prices on land values,
Robert Jess, the manager of the Yukon FlatsNational Wildlife Refuge, told PetroleumNews July 21.
“We’re still waiting for the landappraisals,” Jess said.
The land appraisals are required for anenvironmental impact statement for the landswap and are being prepared by an inde-pendent government agency.
Preparation of the EIS is progressing toplan, Jess said. Fish and Wildlife publisheda draft EIS in January and the public reviewperiod for that draft closed in May. Sincethen Fish and Wildlife has been revising thedraft document in the light of public com-ments and waiting for the land appraisalresults.
However, although Fish and Wildlife has
been hoping to complete the plan bySeptember, EIS completion may not nowhappen until later in the year, Jess said.
And James Mery, Doyon’s senior vicepresident, lands and natural resources, toldPetroleum News July 21 that informationabout the Yukon Flats basin published by theU.S. Geological Survey has indicated thatsome Doyon land earmarked for the landswap is more prospective for oil and gasthan the Native corporation had originallythought. USGS data published since a 2005land swap agreement in principle betweenDoyon and Fish and Wildlife have identifiedYukon Flats sub-basins and have refinedbasin depth profiles, Mery said.
“Some of the lands that were scheduledto go into the trade were subsequently deter-mined by USGS to be prospective,” Merysaid.
That determination may impact theselection of land for the swap, he said.
8.6 million acresThe Yukon Flats consists of an approxi-
mately 15,000-square-mile lowland areaaround the Yukon River between the trans-Alaska oil pipeline and the Canadian border.The 8.6 million-acre Yukon Flats WildlifeRefuge, administered by the U.S. Fish andWildlife Service, lies within the lowlands.Doyon and some Native village corpora-tions own a patchwork of surface and sub-surface land amounting to about 2 millionacres inside the refuge perimeter boundary— the Native corporations selected this landunder the terms of the Alaska Native ClaimsSettlement Act before the wildlife refuge
10 PETROLEUM NEWS • WEEK OF AUGUST 3, 2008
● L A N D & L E A S I N G
Yukon Flats land assessment drags onRising price of oil complicates land appraisals; new USGS data indicates some Doyon land more prospective than previously thought
A
This map shows the land tracts proposed for the Yukon Flats land swap. An independent government agency is currently appraising values for the various land tracts involved.
came into existence. A sedimentary basin with petroleum
potential, the Yukon Flats basin, lies underthe flats. And motivated by the potential foroil and gas development in the region,Doyon has been trying to engineer the landswap with Fish and Wildlife, to consolidateits land holdings in the deepest part of thebasin.
The 2005 agreement in principle for theland swap involved the shuffling of a jigsawpuzzle of land tracts. That agreement gainedsupport from some communities in theYukon Flats, but vehement opposition fromothers. The controversy triggered develop-ment of the EIS for the swap.
Revenues from oil or gas production onDoyon land would result in dividends to thecorporation’s Native stockholders, many ofwhom live in the Yukon Flats region. And 70percent of the money would flow to otherNative regional corporations, under the nat-ural resource revenue sharing provisions ofthe Alaska Native Claims Settlement Act.
Dividend income and an influx of oil andgas related jobs could revive the fortunes ofthe Yukon Flats communities — the villagesof Birch Creek, Beaver, Stevens Village andFort Yukon, for example, are close to someof the deeper sections of the basin. In com-mon with rural communities elsewhere inAlaska, Yukon Flats villages are sufferingfrom the impact of escalating fuel prices.
But, with concerns about the potentialimpacts of oil development on the environ-ment and the subsistence way of life in theregion, there has also been vociferous oppo-sition to the land swap proposal.
ControversialUnder federal regulations, Fish and
Wildlife has to exchange refuge land ofequivalent value to the Native land that thefederal government obtains for the refuge.So, the government land appraisal is criticalin determining exactly how much landwould be exchanged — the federal govern-ment uses a prescribed formula to assign adollar value to the land, based on factorssuch as the land’s wildlife and otherresources.
Some residents of the Yukon Flats haveexpressed concern that under the terms offederal land valuation rules the Native cor-porations would relinquish a larger area ofsurface land than they would gain.
And the agreement in principle betweenDoyon and Fish and Wildlife spelled outhow the two landowners envisaged the landswap working.
Doyon would acquire about 110,000acres of refuge lands over the deepest part ofthe basin. The corporation would alsoreceive 97,000 acres of oil and gas rightsnext to some of these lands — this subsur-face acreage would only be accessible bydirectional drilling from Doyon land. Therefuge would acquire a minimum of150,000 acres of Doyon full-fee land. AndDoyon would also re-allocate about 56,000acres of remaining entitlement within therefuge to locations outside the refuge.
Also Doyon would pay Fish and Wildlifea portion of any oil and gas revenues fromland obtained in the swap. Fish and Wildlifewould subsequently have the right to usethat money to purchase up to an additional120,000 acres of Doyon land.
Rising oil priceBut, because a primary purpose of the
land swap is oil and gas development, theescalating price of oil has complicated theland appraisal, Jess said. In principle, a high-er oil price could increase the dollar value ofthe refuge land, thus increasing the area ofDoyon land needed for the exchange.However, at this stage Fish and Wildlifedoes not know what impact the oil price sit-uation will have, Jess said.
Although the high price of oil mighttranslate into an increase in the acreage ofDoyon land that could be transferred to therefuge, that does not imply an unlimitedcommitment to the amount of land thatDoyon would transfer, Mery said.
“We’re not going into this at any price orcost,” Mery said.
Mery said that in the agreement in princi-ple Doyon had agreed to swap not less than150,000 acres. And no more than 270,000
acres of Doyon land would be availablebetween the two proposed phases of the landswap, he said.
Mery has also commented in the past thatunder the terms of the Alaska Native ClaimsSettlement Act Doyon had made an excep-tionally large land selection in the YukonFlats, with future oil and gas development inmind.
“Those are 330,000 acres of surface thatthe villages own that could have gone some-place else,” Mery said.
And Doyon plans to move ahead with oiland gas development on its own land,regardless of whether the land swap goesahead. The increasing price of oil has sub-stantially reduced the minimum field sizerequired for viable development and theeconomics of developing oil on Doyonacreage has improved, Mery said. ●
PETROLEUM NEWS • WEEK OF AUGUST 3, 2008 11
continued from page 10
ASSESSMENT
● I N T E R N A T I O N A L A R C T I C
Seven square mile ice chunk breaks offCanada’s largest remaining ice shelf looses piece; shelf crack found in 2002; Ellesmere Island used to be ringed by an ice shelf
THE ASSOCIATED PRESSfficials said July 29 a chunk of ice about seven squaremiles in size has broken off Canada’s largest remain-ing ice shelf.
Trent University researcher Derek Mueller said hewouldn’t surprise him if even more ice broke off this sum-mer from the Ward Hunt Ice Shelf, a vast frozen plain offthe north coast of Ellesmere Island in Canada’s far north.
In a development consistent with climate change theo-ries, an enormous icy plain broke free sometime the weekending July 25 and began slowly drifting into the ArcticOcean. The piece had been a part of the shelf for 3,000years.
A crack in the shelf was first spotted in 2002. Lastspring, a patrol of Canadian Rangers found the weaknesshad spread into an extensive network of cracks, some 40
meters wide and 11 miles long. Formed by accumulating snow and freezing meltwater,
ice shelves are large platforms of thick, ancient sea ice thatfloat on the ocean’s surface. Ellesmere Island was onceentirely ringed by a single enormous ice shelf that broke upin the early 1900s. At 170 square miles in size and 40meters thick, the Ward Hunt shelf is the largest of thoseremnants — seven times the size of the Ayles Ice Shelfchunk that broke off in 2005 from Ellesmere’s westerncoast.
Despite a period of stability in the 1980s, the Ward Huntshelf and its characteristic corrugated surface has beensteadily declining since the 1930s, said Mueller. Its south-ern edge has lost seven square miles over the last six years.
Mueller is careful not to blame the Ward Hunt breakupspecifically on climate change, but said it is consistent with
the theory. “We’re in a different climate now,” he said. “It’s not con-
ducive to regrowing them. It’s a one-way process.”It’s the same all over the Arctic, said Gary Stern, co-
leader of a major international research program on sea ice.Speaking from the Coast Guard icebreaker Amundsen inCanada’s north, Stern said the Ward Hunt breakup is relat-ed to what he’s not seeing thousands of miles -- ice. Plansto set up an ice camp last February had to be abandonedwhen usually dependable ice didn’t form for the secondyear in a row.
“Things are happening fast and they’re going to contin-ue to happen fast,” Stern said.
Many scientists believe that the Arctic will have ice-freesummers by 2013 instead of 2030 as predicted by theInternational Panel on Climate Change.●
“If our young people don’t have a future, if they don’thave something to lookforward to, they aregoing to be lost.”
For those who live in Bush Alaska, mining creates
good-paying jobs in areas of limited opportunity and
provides a revenue stream to help rural Alaskans be
self-reliant. It provides hope for the young so that they
can stay in their villages, continue their subsistence
lifestyle and still provide for their families.
Ballot Measure 4 threatens the lifestyle of all Alaskans –
from those who work in the industry to those who
Ballot Measure 4 is a classic bait and switch. The
proponents want you to think it’s about one mine
but it impacts the entire industry.
Vote No on 4. It’s Defective and Deceptive.
Protect our hope and opportunity
Vote No on 4
Evelyn ThomasVice President,Crooked Creek Tribal Council
VOTE ONTo learn more about mining and the threat posed by Ballot Measure 4,go to www.FacesOfAlaskaMining.com to view a short documentary.
The Red Dog Mine operating agreement provides jobsand job training for NANA shareholders and protects the subsistence lifestyle of the people in the region.
● F I N A N C E & E C O N O M Y
Free tradepayoff forAlberta
By GARY PARKFor Petroleum News
n almost 20 years of free tradebetween Canada and the UnitedStates, exports from the province ofAlberta have grown 674 percent, com-
pared with a 166 percent increase to othernon-free-trade countries, according to areport by the University of Alberta’sWestern Center for Economic Research.
The report focused on Alberta’s exportperformance since the inception of vari-ous free trade agreements, starting withthe Canada-U.S. pact in 1989, the NorthAmerican Free Trade Agreement whichadded Mexico in 1994 and separate dealswith Chile, Israel and Costa Rica.
Not surprisingly, energy has accountedfor 69 percent of the growth in all ofAlberta’s exports since 1993, generatingrevenues of C$56.5 billion in 2007.
Non-energy exports to free-trade part-ners rose to C$16.5 billion in 2007 fromC$2.9 billion in 1988 while non-energyexports to non-free-trade countriesclimbed 196 percent.
Crude oil value rocketsThe value of crude oil shipped to the
U.S. rocketed to C$28.1 billion in 2007from C$3.1 billion in 1988, while, overthe same period, natural gas and naturalgas liquids increased to C$26.6 billionfrom C$3.2 billion.
The value of exports per employee inAlberta currently stands at C$42,344against the Canada-wide average ofC$26,707. In 1988, the Alberta andnational averages were both aboutC$10,900.
Over the study period, Alberta’s shareof all Canadian exports has grown to 18.4percent from 9.6 percent.
The importance of NAFTA to Albertaand the resource-based economies ofWestern Canada (including BritishColumbia, Saskatchewan and Manitoba)has grown steadily over the past twodecades.
In 1988, 52.4 percent of all exportsfrom the region were destined for the U.S.and Mexico. By 2007 that figure hadgrown to 76.6 percent, periodically top-ping 80 percent when the Canadian dollarwas at its weakest point against the U.S.currency.
Exports of resource-related machineryand parts have made strong gains toalmost C$250 million last year from C$16million in 1995.
Although energy has been the engineof Alberta’s growth, non-energy sales toNAFTA partners has climbed by 468 per-cent over the past 20 years, with machin-ery, plastics and organic chemicals allplaying a part. ●
I
The report focused on Alberta’sexport performance since theinception of various free tradeagreements, starting with theCanada-U.S. pact in 1989, the
North American Free TradeAgreement which added Mexico in
1994 and separate deals withChile, Israel and Costa Rica.
Denali names Calvin, Coughlin, JepsenNorth Slope producer group hires experienced pipeline exec from BP’s Baku office for operations VP of its Alaska gas line firm
PETROLEUM NEWShree vice presidents have been named at Denali —The Alaska Gas Pipeline LLC.
Denali President Bud Fackrell said Dave Calvinhas been named vice president and operations direc-
tor; Patrick Coughlin vice president and general counsel;and Scott Jepsen vice president for external affairs.
Calvin joins Denali from BP’s Baku office, where hemanaged the commissioning, startup and all operationalaspects of the Baku-Tbilisi-Ceyhan pipeline and the SouthCaucasus Pipeline.
Denali said the large diameter (42-inch to 44-inch)pipelines extend 1,600 miles across three countries —Azerbaijan, Republic of Georgia and Turkey.
Calvin was project manager for the Alaska Gas Pipelinefeasibility study in 2001-02, and was project manager forBP’s gas-to-liquids test facility in Nikiski from 2000 to2001. He worked in Valdez and Fairbanks while on second-ment to Alyeska Pipeline Service Co., and spent severalyears in Bogota, Colombia, as project manager for BP’sCusiana oil field.
“Dave is a seasoned pipeline project manager, havingmost recently delivered one of the most complicated, chal-lenging pipeline projects the world has ever seen, the BTCand SCP Pipelines,” Fackrell said. “Those skills, along withhis extensive Alaskan experience will serve Denali verywell. We are delighted to have someone of Dave’s caliberreturning to Alaska.”
Calvin and his wife have a home in Anchorage. Theyhave two children, one of whom will be pursuing a MastersDegree in engineering at the University of Alaska Fairbanks.
“I am pleased to be coming home to Alaska after severalyears of overseas assignments. This is a tremendous project,
and I am happy tobe part of the team,” Calvin said. Calvin has a Bachelor ofScience in Physical Sciences from Westminster College inSalt Lake City, Utah, a masters degree in chemical engi-neering from the University of Utah, and an MBA from theUniversity of Houston.
Coughlin named Denali general counselPatrick Coughlin, named vice president and general
counsel, has worked for BP Exploration (Alaska) Inc. inAnchorage for the last four years.
He came to Alaska in 1978 and has served as a law clerkwith the Alaska Supreme Court and 9th Circuit Court ofAppeals, was a partner in the Alaska law firm of Guess &Rudd, specialized in oil and gas as an Alaska assistant attor-ney general, was deputy director of the Alaska Division ofOil and Gas and a consultant to the Alaska Legislature in2001-02.
Coughlin “brings with him a broad spectrum of legalexperience — most of it in Alaska, and will have responsi-bility for managing the company’s legal affairs,” Fackrellsaid. Coughlin said, “I am very pleased that BP’s andConocoPhillips’ gas line efforts over the last seven years are
coming together to get a gas line project moving. I lookforward to making the Alaska gas pipeline a reality and Iam excited about becoming a part of the team.”
Coughlin and his wife Julie live in Anchorage and havefour daughters; he is a graduate of Duke University, holdsJD from Golden Gate University (with highest honors)and has been a member to the Alaska Bar Associationsince 1980.
Jepsen named VP external affairsScott Jepsen, named as Denali’s vice president for
external affairs, joins Denali from ConocoPhillips’Anchorage office where he was Cook Inlet manager. Jepsenis a 28-year veteran in the oil and gas industry. He hasworked in various roles across the United States in oil andgas production and operations. Most recently, he ledConocoPhillips’ successful efforts to obtain a two-yearlicense extension for the Kenai LNG Plant.
“Jepsen is a long-time Alaskan who brings excellent pub-lic and government outreach skills to the job,” said Fackrell.“Jepsen’s strong operations background and his expertisewith natural gas will ensure that our government and publicaffairs efforts are aligned with the project goals.”
Jepsen has lived in Anchorage for 19 years. He has twoteenage sons who attend Service High School. “I am excit-ed for the opportunity to contribute to Denali and participatein the opening of a new era for North Slope exploration anddevelopment,” Jepsen said.
He has a Bachelor of Science and master’s degree inchemical engineering from the University of Texas atAustin. Jepsen is a member of the Society of PetroleumEngineers and past president of the Petroleum Club ofAnchorage. ●
T
DAVE CALVIN PATRICK COUGHLIN SCOTT JEPSEN
● L A N D & L E A S I N G
DOI starts on new OCS leasing programThe 2010 to 2015 leasing program can apply to the whole U.S. OCS but leasing in some areas would require congressional approval
By ALAN BAILEYPetroleum News
ecretary of the Interior Dirk Kempthorne announcedJuly 30 that the U.S. Department of the Interior is start-ing the development of a new five-year oil and gasleasing program for the U.S. outer continental shelf.
The program will span the years 2010 to 2015, a time peri-od that overlaps the current OCS leasing program’s time-frame of 2007 to 2012.
DOI said that the start of program development couldgive the next administration a two-year head start inexpanding energy production from federal offshore lands— the Outer Continental Shelf Lands Act Amendments of1978 give the secretary of the Interior the authority to devel-op out-of-cycle leasing programs.
“When our current five-year program for outer conti-nental shelf oil and gas leasing was launched in July 2007,
oil was selling for $64 a barrel,” Kempthorne said. “Todaya barrel of oil costs more than $120, almost double the pricea year ago. Clearly, today’s escalating energy prices and thewidening gap between U.S. energy consumption and sup-ply has changed the fundamental assumptions on whichmany of our decisions were based.
“Areas that were considered too expensive to develop ayear ago are no longer necessarily out of reach based onimprovements to technology and safety. The American peo-ple and the president want action and this initiative canaccelerate an offshore exploration and development pro-gram that can increase production from additional domesticenergy resources.”
The announcement comes in the wake of President Bushlifting an executive ban on oil and gas leasing in many areasof the continental shelf. However, any leasing in areas sub-ject to congressional withdrawal would require congres-sional action. The president has also urged Congress to
enact legislation that would give states involvement in off-shore oil and gas operations, DOI said.
“The president believes coastal states should have avoice in how outer continental shelf resources are devel-oped off their shores while ensuring those environments areprotected. Also, Congress should provide a way for the fed-eral government and states to participate in revenue sharingfrom those new leases,” Kempthorne said.
The U.S. Minerals Management Service is starting themulti-year process to develop the new leasing program witha call for information about what that program should takeinto account. MMS is requesting comments to ensure con-sideration of all concerns regarding oil and gas leasing,exploration and development that result from the new pro-gram — the Outer Continental Shelf Lands ActAmendments require several rounds of public commentand multiple environmental reviews for out-of-cycle leas-ing programs, DOI said. ●
professor of economics at the University ofAlaska Anchorage and author of the ISERanalysis. “It’s really the only thing utilitiescan do immediately to reduce their carbonoutput.”
“It means the market for Alaska’s gasbecomes that much stronger,” Colt added.
Colt’s analysis, dated April 11, looksspecifically at a report done by theAmerican Council for Capital Formationand the National Association ofManufacturers using the National EnergyModeling System. The report projected thenational and state impacts of theLieberman-Warner Climate Security Act.
The Lieberman-Warner bill would capemissions for various sectors of the econo-my, but would allow utilities and othermajor emitters to trade their emissionsallowances. The bill aims for reductions incarbon dioxide emissions to 4 percentbelow 2005 levels by 2012 and 17 percentbelow 2005 levels by 2020.
According to the ACCF/NAM report,the legislation would increase the marketprice of natural gas by roughly $6 per thou-sand cubic feet in 2020 and $20 per mcf in2030. The cost of emissions allowanceswould total roughly $3 and $14 over thesame period, meaning the overall value ofthe gas would increase by $3 per mcf in2020 and $6 in 2030.
At 4 billion cubic feet per day, an Alaskanatural gas pipeline would generate an addi-tional $150 billion to $230 billion over a 30-year lifespan, according to the analysis.
Colt challenges some of the assumptionsin the ACCF/NAM report, which projectsvery high costs associated with carbonreductions in 2030, and argues that theavailability of alternative energy sourceswill keep the cost of allowances relativelylow. A lower cost for carbon allowanceswould likely decrease the premium for nat-ural gas, he said.
Good for the gas pipelineThe projected increase in value would
significantly boost the economics ofTransCanada’s gas line proposal. Accordingto Alaska Revenue Commissioner PatGalvin, Gov. Sarah Palin’s gas line teamand hired consultants considered the poten-tial impacts of climate legislation on gaspricing, but did not include those impacts intheir economic analysis.
“What we recognize in our analysis isthat if a cap-and-trade was put in place, itwould likely put a greater demand on gasprices,” Galvin said, adding that the teamwas taking a conservative approach and hadnot assumed the additional value.
Antony Scott, head of the Division ofOil and Gas’ commercial section, said noneof the three price forecasts used in thestate’s analysis assumed the passage of fed-eral climate legislation.
He said it was impossible at this point toproject detailed impacts of cap and tradelegislation because of the huge number ofvariables and unknowns. But he added thatit was hard to imagine the legislation wouldhave a negative impact on the gas line proj-ect.
“Getting serious about climate change islikely to be very supportive of this project,”he said.
BP, ConocoPhillips support carbon capAlaska’s big three oil producers declined
to speculate on how federal legislationwould impact their business in Alaska.
“There’s so many variables, we’d reallyhave to wait and see what the legislationwould look like to assess it,” said AlanJeffers, a spokesman for ExxonMobil.
But BP America and ConocoPhillips areboth advocating some kind of cap-and-tradelegislation. In a July speech to the NationalGovernors Association, BP AmericaChairman Robert Malone said it was criti-cal to start addressing climate change.
“Until energy producers and consumersknow the cost of carbon, the uncertaintyassociated with planning and investing inall kinds of energy projects will remainhigh,” he said.
BP America and ConocoPhillips areboth members of the U.S. Climate ActionPartnership, a group of businesses and envi-ronmental organizations pushing for emis-sions reductions of 60 to 80 percent fromcurrent levels by 2050.
Jeffers said Exxon has not taken a formalposition on climate legislation but favorsproposals that are efficient and predictableand allow market forces to work.
Those tracking the climate legislation inWashington say the Lieberman-Warner billprobably won’t pass this session. But theyadd that some kind of cap-and-trade legisla-tion will likely pass in the next few years.
“I think the only question is, how strongis it going to be?” Colt said.
Congress is also considering a carbontax, but it’s expected that a cap-and-trademechanism will ultimately be used instead.
Alaska Sens. Ted Stevens and LisaMurkowski last year co-sponsored a differ-ent cap-and-trade proposal that capped thecost of carbon allowances.
Impacts on oil and coalWhile the impact of federal climate leg-
islation on Alaska’s natural gas is likely tobe positive, the impacts on crude oil andcoal are less certain.
Per unit of energy, oil products emit lesscarbon dioxide than coal but more than nat-ural gas. Colt said it’s unclear how cap andtrade legislation would affect U.S. demand
for crude oil, but he added that oil is sold ina global market and that worldwide demandwill likely continue to rise.
According to Colt, the ACCF/NAMreport suggests that oil prices will rise morethan the cost of emissions allowances,adding to the overall value of the product.Additional wellhead value would rangebetween $500 million and $9 billion peryear in 2020, according to Colt’s analysis ofthe report.
Coal used in conventional ways wouldlikely face large new costs for carbonallowances, but could remain competitivein Alaska if the carbon dioxide producedthrough combustion is captured and stored,
14 PETROLEUM NEWS • WEEK OF AUGUST 3, 2008
Energy said it is negotiating with six differ-ent carriers, trying to find a company capa-ble of making the trip, but couldn’t geteverything in line by the original July 31deadline.
Adding to the presumed delay is the factthat the carrier most likely won’t be anAmerican company, forcing Pacific Energyto get a federal exemption of the Jones Actrequirement that tankers in U.S. waters bebuilt, owned and manned by Americans.
While Pacific Energy is confident it willget the exemption, federal officials won’tstart the process until a carrier has beenfound and contracted.
Pacific Energy plans to start drilling atCorsair in 2009 and believes the prospectcontains 500 billion cubic feet of gas and100 million barrels of oil.
The company produced nearly 4,600barrels of oil per day from its Alaska leasesin July.
Following an announcement earlier inthe month that Pacific Energy received$101 million by selling part of its onshoreassets in Calfornia, the company announcedon July 31 that it brought in around $34 mil-lion from the final part of the sale.
That money will be used for capital proj-ects like those in Alaska, and for debt reduc-tion.
Extension may have downsideThe extension may have one negative
outcome for Pacific Energy.The company is currently appealing a
state decision to take back several pacificEnergy leases around the Corsair unitbecause of disuse. Pacific Energy had askedfor those leases to be brought into theboundaries of the unit, which would auto-matically extend their life.
Originally, the independent suggestedCorsair might not be economic without theexpansion acreage. Recently, the companysaid the leases already within the unit con-tain a new prospect.
By asking for an extension of the dead-line for a heavy lift vessel, the state Divisionof Oil and Gas said Pacific Energy is con-tradicting its earlier claim.
“The Division interprets PERL’s vesselcontract extension request as a repudiationof its appeal argument that delivering the rigis uneconomic without the expansion leas-es,” Acting Director Kevin Banks wrote tothe company.
Pacific Energy officials could not bereached for comment.
—ERIC LIDJI
“The Division interprets PERL’svessel contract extension request
as a repudiation of its appealargument that delivering the rig
GAINSINTERNATIONAL ARCTICArctic Ocean drilling workshop in Nov.
A workshop to be held Nov. 3 to 5 in Bremerhaven, Germany, will bringtogether scientists interested in future drilling expeditions in the Arctic Ocean.Funded by the Consortium for Ocean Leadership, the European ScienceFoundation, the Arctic Ocean Science Board and the Nansen Arctic DrillingProgram, the workshop is titled “Arctic Ocean History, From Speculation toReality.” The overall goal of the workshop is to enable collaboration in planningand site surveying for Integrated Ocean Drilling Program drilling in the ArcticOcean.
The workshop organizers say that drilling on the Lomonosov Ridge in thesummer of 2004 under the Integrated Ocean Drilling Program revealed invalu-able new information about the Arctic, including new insights into the sensitivi-ty and response of the high latitudes to greenhouse gases. But the geologic his-tory of the Arctic Ocean remains substantially unknown, they say.
The workshop will help scientists build a drilling program that will target evi-dence relating to issues such as the history of the formation of the Arctic Ocean;the composition of the Alpha-Mendeleev Ridge; the opening of gateways andexchange of water between the Arctic Ocean and other oceans; and the role ofthe Arctic in transitioning between greenhouse and icehouse climatic conditions.
Applications to attend the workshop are due by Aug. 24. Further informationis available at www.oceanleadership.org/usssp/workshops/arctic. Or contactBernard Coakley ([email protected]) or Ruediger Stein([email protected]).
—ALAN BAILEY
see GAINS page 17
“Getting serious about climatechange is likely to be verysupportive of this project.”
—Antony Scott, Division of Oil and Gas, on theAlaska gas pipeline
While the impact of federalclimate legislation on Alaska’s
natural gas is likely to be positive,the impacts on crude oil and coal
are less certain.
Charlie Boddy, vice president ofgovernmental relations at UsibelliCoal Mine, Inc., said … that hehas been working with Alaska’s
congressional delegation on waysto protect Usibelli from the
negative impacts of cap-and-tradelegislation, such as through creditsfor emissions allowances. He said
Usibelli would be interested inhelping develop and test carbon
aving emerged from a difficult 12months, oilfield services companiesare counting on a vigorous reboundin Canada.
The big U.S.-based companies —Halliburton, Baker Hughes, BJ Servicesand Weatherford — are all issuing themost optimistic forecasts since early 2007.
Bernard Duroc-Danner, Weatherford’schairman, president and chief executiveofficer, said he believes Canada will enjoya strong recovery in the second half of2008 and into 2009, led by heavy oil,shale and broad-scale new gas plays.
He expected to see an average 400 rigsworking in the current quarter and morethan that in the final three months. (Thelatest industry figures show 465 rigs, 55percent of the available fleet, are operat-ing.)
“We can see very healthy incrementalsin Q4 and Q3,” he said.
Duroc-Danner said the drilling down-turn in Canada, which was more severeover the past two years than in the U.S.,has “bottomed out.”
Chief Financial Officer Andrew Becnelprojected a 20 percent revenue growth forCanada in the second half of 2008 com-pared with the same period last year.
Halliburton expects strong activity for balance of the year
Halliburton Chief Executive OfficerDave Lesar said that with natural gasprices on the rise and excess equipmentcapacity being absorbed, he expectsstrong activity over the balance of the yearin Canada.
Tim Probert, Halliburton’s vice presi-dent of strategy, said some of the equip-ment which was moved into the U.S. dur-ing the Canadian slowdown will “return tomeet expectations of the market.”
He forecast that the second-half contri-bution from Canada will be stronger thanhis company had initially anticipated.
Those same general themes wereechoed in conference calls by BakerHughes Chief Executive Officer ChadDeaton and BJ Services Chief ExecutiveOfficer Bill Stewart.
Duroc-Danner said average labor costsincreased 8 percent in the second quarterand the cost of raw materials rose 25 per-cent everywhere except Canada, butadded that “Canada’s turn will come.”
Investors have dropped valueHowever, the positive mood isn’t
reaching investors, who have wiped about20 percent off the value of energy stocksin the past month, as the price of naturalgas has fallen by a similar percentage.
Units of Precision Drilling Trust,Canada’s largest contractor, droppedC$1.75 each to C$21.83 on July 23, thesame day it reported a second-quarterprofit of C$22 million, a drop of only C$4million from a year earlier, which itblamed on incentive compensationexpense accruals of C$9 million, up C$5million from the same period of 2007.
The market sell-off surprised Jeff
Fetterly, an analyst with CIBC WorldMarkets, who said he saw few, or no oper-ational red flags in the second quarter,with cash flow only a fraction short offorecasts.
He suggested investors might be onedge because of a dip in gas prices, whichcould undermine drilling hopes.
Well completions in Canada dropped18 percent in the first half to 8,129 from9,897 a year earlier, with only oil explo-ration posting any gains, including 420discoveries, up 14 from the same period of2007, but the highest total for the period in22 years.
Gas discoveries slumped to 896 from1,482 last year and a record 2,332 in theJanuary-June period of 2006.
The industry tallied 6,183 developmentwell completions and 1,826 explorationwell completions, compared with 7,510and 2,219 in the same six months last year.
Drilling down from 2007For June, well spuds totaled 1,145, just
13 behind June 2007, dragged down byAlberta’s drop to 761 from 819.
To the halfway point for the year, thetotal well depths drilled in Canada were29.8 million feet, off 7 percent from2007’s 32 million feet, with the tallyhelped by a 3 percent rise to a record1,209 horizontal wells.
In Alberta rigs were released on 4,773wells, off 16 percent from last year, andBritish Columbia was down 16.5 percentat 441 wells, while Saskatchewan trailedits 2007 count by 4 percent at 1,341 wells.
For the first half, operators acrossCanada started drilling 6,785 wells, off11.6 percent from 2007, with onlyManitoba recording an increase amongthe provinces, rising to 144 wells from119.
EnCana led the operators with 1,338
PETROLEUM NEWS • WEEK OF AUGUST 3, 2008 15
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LAND & LEASINGMMS holds Bristol Bay scoping meetings
Scoping meetings for the proposed North Aleutian basin lease sale will be held inthe Bristol Bay region in August and September.
The U.S. Department of the Interior’s Minerals Management Service said July 28that the meetings will be held to gather information to be included in the environ-mental impact statement for a proposed Outer Continental Shelf oil and gas sale inthe North Aleutian basin planning area.
Sale 214 is scheduled for late 2011 and is part of the agency’s 2007-12 oil and gasleasing program.
MMS staff will answer questions about the proposed sale and seek input from res-idents on important environmental, social or economic issues that could arise fromsales in the area. MMS said it will continue to evaluate issues, if new ones are iden-tified in the future; the agency is also seeking input on alternatives to the proposedsales and measures to mitigate any potential impacts.
The draft EIS will be available in early 2010. More information is available at www.mms.gov/alaska.
Meeting scheduleDates and locations include: • King Salmon, Aug. 18, 7-9:30 p.m., Lake and Peninsula Borough
Administration Building;• Naknek, Aug. 19, 11 a.m.-1 p.m., Borough Assembly Chambers;• Dillingham, Sept. 2, 7-9:30 p.m., Dillingham City Council Chambers;• Sand Point, Sept. 15, 7-9:30 p.m., Aleutians East Borough Offices;• Nelson Lagoon, Sept. 16, 11 a.m.-1 p.m., Nelson Lagoon Community Building;• Cold Bay, Sept. 16, 7-9:30 p.m., Cold Bay Community Center; and• King Cove, Sept. 17, 7-9:30 p.m., King Cove City Council Chambers.
—PETROLEUM NEWS
● F I N A N C E & E C O N O M Y
Canadian servicesector buoyantOilfield service firms take most upbeat view in 18 months aboutoutlook; investors not buying in, energy stocks down 20%
H
see SERVICE SECTOR page 17
Fire and Life Safety Specialists
Providing design, installation, repair/service& inspections on fire protection systems.
520 W. 58th St, Ste G, Anchorage, AK 99518 | Phone (907) 569-4340 | coscofire.com
All of the companies listed above advertise on a regular basis with Petroleum News
Business SpotlightUsibelli Coal Mine Inc.
Alan Renshaw, Usibelli’s chief of engineeringsince 2001, has been appointed vice president ofengineering. In announcing the promotion,President Joe Usibelli Jr. said Renshaw possessesthe leadership qualities, enthusiasm and technicalskills needed to elevate UCM to higher perform-ance levels. Renshaw supervises seven engineersand laboratory personnel in Healy and is responsi-ble for permitting and regulatory compliance.
Alan and his wife Amber, lifelong Alaskans,have four sons. The whole family participates inmountain climbing, skiing and other outdooractivities, including escaping to Hawaii beachesduring school breaks.
This year the Usibelli workforce of about 95employees celebrates the company’s 65th anniversary. UCM produces some 1.5 million tonsof subbituminous coal for six Interior Alaska power plants and for export to the Pacific Rim.
—PAUL EASLEY
Alan Renshaw, vice president of engineering
CO
URT
ESY
PH
OTO Northern Air Cargo Inc.
For 52 years Northern Air Cargo has beenrural Alaskans’ most reliable air cargo operator.With one eye on its strong history and the otheron modernizing for the future, NAC now relieson its Boeing 737-200 fleet to transport cargothroughout Alaska. In addition to 14 other hubs,NAC’s jet service between Anchorage andDeadhorse (Monday through Friday) ensuresprompt delivery of construction, drilling and min-ing materials.
Margot Wiegele joined NAC five years agoafter a stint in the television industry. She firstworked in NAC’s sales department before step-ping into marketing and communications. AnAlaskan for 31 years, Margot and her husbandScott have two daughters. Margot studied historyat UAA, but wandered into communications so she “never has to stop talking.”
Earnings from Petroleum News Top 25Earnings second quarter 2008 • Change from second quarter 2007
Liquids production second quarter 2008 • Change from second quarter 2007Natural gas production second quarter 2008 • Change from second quarter 2007
Liquids production in barrels per day. Natural gas production in millions of cubic feet per day.* Does not include Lukoil investment
Top companies chosen based on exploration spending and commitment to Alaska and Canada
OIL COMPANY EARNINGS
a global exploration program that Manzonisaid gives priority to looking at the “mostprolific places for the best chance of find-ing the material reserves to renew the com-pany.”
He said that is a major shift from theapproach taken previously of spending a“high portion of exploration dollars look-ing for tie-backs in more mature basins,(although) we will still do that.”
Manzoni said that if the approach is suc-cessful “we can then high-grade some ofour other activities to ensure we don’t getover-stretched.”
Talisman announced a month ago that ithad entered into agreements with theKurdistan Regional Government that ithopes will establish a new core operatingarea.
The deal involves paying C$220 millionto Kurdistan, plus further conditional con-tributions, representing financial supportfor infrastructure projects and capacitybuilding projects for local communities.
Talisman also plans to spend C$80 mil-lion to gain a 40 percent stake in Block 44,including access to an established produc-tion-sharing contract area and a three-wellcommitment. In addition, it has enteredinto a two-year seismic services agreementwith the Kurdistan Regional Governmenton Block 39, following which it will havethe option to gain 60 percent and commit toone well in the first year.
Manzoni said the company studied thelegal, regulatory, security and corporateresponsibility implications before the dealswere signed, but that hasn’t eased all of theconcerns about entering such a volatileregion.
He said Talisman believes a “construc-tive political accommodation (will bereached in Kurdistan) at some stage in thenext few years.”
“I believe it will come in time for us tocapitalize on our entry should our explo-ration prove successful,” he said.
Manzoni noted that the U.S. GeologicalSurvey estimates Kurdistan has 40 billionbarrels of undiscovered oil “making it one
progress in implementing and executing(the) recently announced unconventionalstrategy in North America,” building on a2.5 million net-acre unconventional landbase and expanding and accelerating anumber of drilling programs.
The push is taking place in the Montneyarea of northeastern British Columbia, theFoothills region of Alberta, the Bakkenlight oil play in Saskatchewan, the Utica-Lorraine gas shales in Quebec and theAppalachian shales of New York andPennsylvania.
Buoyed by initial results so far,Talisman is boosting its 2008 capital budg-et by up to C$500 million, all of it directedat unconventional gas, targeting NorthAmerican spending of C$2.5 billion as partof its C$5.5 billion global plan.
The stepped-up program will see thetotal unconventional well count increasedto 160 from 130, with the rig count in theMontney area of British Columbia hiked tonine from six to complete 30 wells in thesecond half on top of the 18 drilled so far;56 wells are scheduled for Bakken, with 11drilled to date; and four wells are scheduledfor Quebec.
Talisman has also picked up 26,500acres in the Hinton area of west-centralAlberta, increasing its holdings to 80,000net acres and expanding its drilling loca-tions to 190 from 150.
But company officials were coy aboutwhere the additional money will go beyondsaying it will be divided between drillingand land acquisition. They would not saywhether Talisman was among the success-ful bidders in the last British Columbialand sale.
Analysts Andrew Potter of UBSSecurities and Stephen Calderwood ofRaymond James noted that Talisman haskept the lid on results from its emergingresource plays, but Calderwood gave a voteof confidence to management, while sug-gesting it could build on that credibility andincrease share values by being more forth-coming. ●
continued from page 1
TALISMAN
well completions to the end of June, butalso posted the largest decline with a dropof 310 wells from 2007.
Husky Energy finished 475 wells(down 29) , Canadian Natural Resourcesdrilled 444 wells (down 113), whileDevon Canada had 256 completions and
Enerplus Resources Fund drilled 235wells, compared with just 25 wells in 2007for the largest year-over-year increase.
Among those who made solid gains,Apache Canada climbed to 161 from 92,Petrobank Energy and Resources jumpedto 69 from 22, ConocoPhillips Canadarecovered to 201 from 160 and TriStar Oil& Gas drilled 68 wells, up from 28 lastyear. ●
continued from page 15
SERVICE SECTOR
according to Colt.In a separate analysis from July 2007,
Colt estimated that emissions allowancescould double the cost of coal.
“The conventional wisdom is carboncontrol is going to be bad for coal,” hesaid. “That’s probably true for utilities inOhio, or if you’re sending boatloads ofcoal to the Midwest, but it could actuallybe good for Alaskan coal if it leads to oneor two big-time projects.”
Colt said the potential for using car-bon dioxide to increase oil recovery
makes Alaska an attractive place for newtechnology aimed at capturing and stor-ing carbon emissions.
Charlie Boddy, vice president of gov-ernmental relations at Usibelli CoalMine, Inc., said he and companyPresident Joe Usibelli Jr. have traveled toWashington to advocate for moreresearch into carbon capture technology.
Boddy added that he has been work-ing with Alaska’s congressional delega-tion on ways to protect Usibelli from thenegative impacts of cap-and-trade legis-lation, such as through credits for emis-sions allowances. He said Usibelli wouldbe interested in helping develop and testcarbon capture technology. ●
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GAINS
What happens in January 2009 if RCAhas not approved the new supply con-tracts, state Assistant Attorney GeneralSteven DeVries asked Eugene Dubay,chief operating officer of Semco EnergyInc., Enstar’s parent company, duringcross examination at the RCA hearing.
We have identified a slice of our com-mercial customers that we might not beable to serve, Dubay said.
“It’s possible for instance that thosecommercial customers could be repre-sented by an enterprising marketer andthat marketer could go directly to Conocoand Marathon, and they could get thesame gas that we’re trying to get undercontract … at whatever price they couldnegotiate,” Dubay said.
However, Dubay said that Enstar hasnot made any decision about what to do inthe event of a gas supply shortfall —other options would include trying tonegotiate another agreement with the pro-ducers.
“Obviously we’ll do our best to seethat the community is served,” Dubaysaid. “But I don’t have an answer for youtoday as to how that service will comeabout if these contracts aren’t approved.”
2006 rejectionIn September 2006 RCA rejected an
Enstar contract with Marathon that wouldhave filled the 2009 shortfall. That con-tract involved gas pricing based on a trail-ing average of Henry Hub prices in theLower 48. A contract with Union Oil ofCalifornia (now part of Chevron)approved by RCA in 2001 used a similarHenry Hub-base pricing model, but in the2006 decision a majority of the commis-sioners said that the Henry Hub pricingwas unjustifiably high for the Cook Inletgas market.
Enstar and the gas producers have long
argued that Lower 48 pricing is necessaryin Cook Inlet to provide gas producerswith an incentive to explore and developin the region.
The pricing in the new Marathon andConocoPhillips contracts uses indexesbased on baskets of North American gasprice points. Price tiering increases theprice paid for “swing” gas during periodsof high gas demand, during the coldAlaska winters. In keeping with the Stateof Alaska agreement with Marathon andConocoPhillips over the extension of theexport license for the Nikiski LNG termi-nal, the contracts include provision for thecurtailment of LNG production to meetany shortfall in the deliverability of gas toEnstar.
The contracts anticipate that by 2011Enstar will establish gas storage facilitiesto reduce the need to purchase gas at themore expensive high-demand price tiers.
Request for proposalIn his opening remarks at the RCA
hearing, Enstar’s attorney William Saupesaid that following the 2006 RCA rejec-tion of the 2005 Marathon contract,Enstar issued a request for proposal forgas supplies. Only Marathon andConocoPhillips responded to that RFP,Saupe said.
World gas prices have increased sinceEnstar’s previous tariff proposal and thepricing in the new contracts reflects newmarket conditions. And although theprices would result in an increase inEnstar’s weighted average cost of gas, thecomposite indices used in the pricing arepreferable to pricing based on LNGprices, Saupe said.
Current LNG prices in Japan wouldnet back to a price of $15 to $17 per thou-sand cubic feet of gas in Cook Inlet, hesaid.
“Under these market conditions theproposed contracts priced at domesticU.S. market prices are unquestionably abetter deal for customers,” Saupe said.
The tiered price structure reflects com-mon practice at Lower 48 hubs, wherehigher prices for peak gas supplies reflectthe cost of gas storage or the need to pur-chase additional gas on the spot market,Saupe said.
“The swing premiums are far lowerthan other peak shaving options thatEnstar might have available in the CookInlet at the present time,” he said.
LNG curtailmentSaupe emphasized the value of the
provisions to curtail LNG production, todivert gas to meet high Enstar demandwhen necessary. The decades-long trackrecords of Marathon and ConocoPhillipsin meeting their obligations to customersalso added confidence to the security ofthe gas supplies that Enstar had now con-tracted, he said.
“The new contracts do reflect the bestterms and conditions that were availableto Enstar,” Saupe said. “… These con-tracts necessarily reflect conditions in awholesale gas market that is unregulatedand is experiencing tight supplies andconstraints on deliverability that are well-documented in the record. … These twocontracts … achieve a reliable supply ofgas for our customers at reasonable pricesthat do reflect the realities of the market.”
Saupe addressed arguments put for-ward by Chugach in written testimonythat the continued operation of theNikiski LNG plant demonstrates the exis-tence of plentiful Cook Inlet gas and thatthe gas producers have obligations undertheir leases to sell gas to Enstar as long asthey can make a profit.
“Our witnesses have explained in greatdetail all of the reasons why these theo-ries don’t work in the real world,” Saupesaid. Cook Inlet gas is not as abundant asit was 20 years ago and the producershave alternative customers to Chugachand Enstar, he said.
Presumably Enstar needs to wait forthe Alaska Department of NaturalResources and other lessors to take actionto enforce lease obligations to market gasbeyond what the producers are doingnow, he said.
“We hope these contracts will bridgeus to a different market in the future,”Saupe said, referring to prospects for newgas storage facilities and gas pipelinesthat he said may make the gas marketmore favorable to consumers.
Redman: no doomsdayIn an opening statement for Chugach
Electric Association, a major Anchorageelectric utility, attorney Eric Redman saidthat while Chugach doesn’t underestimatethe uncertainties and difficulties in theCook Inlet gas market, there is no evi-dence for a pending doomsday scenario.
“The doomsday scenario is that Enstarcustomers begin to freeze in their homesand businesses on Jan. 1 while Conocoand Marathon … ship Alaska gas fromAlaska leases off to Japan to make sure noone freezes in their homes and businesses
in Tokyo,” Redman said. “No businesshas yet suggested a doomsday scenario onthe record.”
Redman said that the entire case relat-ing to the new Enstar contracts revolvesaround whether Enstar has met its burdenof proof that the gas pricing in the newcontracts is reasonable and, if not, whataction RCA should take. And Redmancharacterized the price formula in the newEnstar contracts as “Henry Hub super-sized.”
But the case is not about a scarcity ofgas in the ground, Redman said.
“ConocoPhillips and Marathon …have just proven to the U.S. Departmentof Energy the existence of an abundanceof … reserves,” Redman said. “They hadto do that to get their LNG export author-ization.”
Scarcity pricing can reflect a scarcityof competing sellers and in the Cook Inletmergers have reduced the number of pro-ducers to three, he said.
And the case is not about prices goingup or being high; it’s about which marketprice should apply, Redman said.
Price mark-upThe new contracts don’t just use index
prices for the Lower 48, Redman said.They mark up the prices using tiering toinclude storage costs that have previouslybeen bundled into the base price. And thenew price formula looks likely to result inprices that are higher than Henry Hub allor much of the time.
“In the Lower 48 there are marketprices at points of receipt and productionareas. There are market prices at gas trad-ing hubs and there are market prices fur-ther downstream at city gates. They areall market prices,” Redman said.
Price analogues for Cook Inlet shouldbe at the production end of the pipelineswhere there are drilling rigs, productionplatforms and roustabouts, not at hubs orcity gates, Redman said. To do otherwisewould, for example, allow pricing basedon delivery to some hypothetical LNGterminal on the U.S. West Coast withoutallowing for the transportation costs fromAlaska.
In fact, Redman questioned the wholeprinciple of linking Cook Inlet prices tothe Lower 48, since there is no way ofdelivering Cook Inlet gas to Lower 48markets.
And Redman lambasted the argumentthat Lower 48 pricing is required toencourage new investment in Cook Inletgas exploration and development. A gasboom in the Lower 48 is driving invest-ment there and investment decisionsdepend on expected returns, not on pricelevels, he said.
“It’s not enough to suggest that otherthings being equal if you raise the pricesit’s more profitable. It doesn’t tell youabout the flow of capital,” Redman said.And then there’s the question of the dutyof the companies to produce gas under theterms of their Cook Inlet leases, he said.
Redman commented that there is evi-dence to link the Cook Inlet gas market tothe gas market in Japan, because of theexport of LNG from Cook Inlet.However, federal limits on both theamount of LNG that the companies canexport and the time period over which theexports can take place complicate thatmarket linkage.
“Chugach’s witnesses point out thatthere’s no way Conoco and Marathon cansimply toss into the current export hopperanother 37 bcf earmarked for Enstarunder these contracts,” Redman said. “…They also can’t simply shut in productionand silo away this extra gas for exportlater.”
18 PETROLEUM NEWS • WEEK OF AUGUST 3, 2008
www.pdcharrisgroup.com
Putting it alltogetherfor the successful commercialization of your project> Project Controls & Management
Difficult decisionAnd Redman commented on the diffi-
culty of RCA’s pending decision over thenew Enstar contracts.
“The record shows that in the absenceof effective competition in the Cook Inletamong producers, the price ceiling thatyou approve in one Enstar contractbecomes the price floor to negotiate thenext Enstar contract,” Redman said.
On the other hand, if RCA rejects thepricing there’s no way to know what willhappen next, he said.
However, there are some other possibleoptions such as approving the contractssubject to required modifications or allow-ing the contracts to go into operation, sub-ject to later reconsideration of the pricing.Alternatively, without RCA approval, theproducers could legally sell gas to Enstarat prices that reduce Enstar’s averageprice of gas, Redman said.
In pre-filed testimony the State ofAlaska Attorney General’s RegulatoryAffairs and Public Advocacy Section hadalso taken issue with the gas pricing termsin the new Enstar contracts.
However, on the first day of the hearingAssistant Attorney General DeVries spentmuch of his cross examination of Dubayexploring the extent to which terms of thecontracts ensure a reliable supply of gas.DeVries particularly focused on the term“proven and risk-probable reserves,” usedas an assurance for the availability of gasunder the contracts.
DeVries said that the Marathon con-tract defined “risk-probable” as reserveswith a probability of 50 percent or better.
“Is it your testimony that 50 percent
certification is reliable?” DeVries asked.“My testimony is that when you look at
what we’ve got in the contract we believethat Marathon and Conoco can performand meet their obligations under theagreement, and I include with that theexpectation that they would convert fromthe LNG plant when so required,” Dubayresponded. “.… When we go back toeverything in the contract I think we getthe reliability.”
However, the ConocoPhillips contracthas a provision that deliveries to Enstar
can be suspended if the state elects to takeits royalty gas in kind (i.e. take delivery ofactual gas rather than royalty payments),DeVries said.
“The agreement is what it is. … I thinkthat these agreements provide us the gaswith the certainty that we need and I’mabsolutely certain … that the producersintend to meet their obligations underthese agreements,” Dubay said.
DeVries asked if it was reasonable toexpect customers to pay 5 to 10 percentabove the base index price for gas in the
tiers for high demand. Cristina Klein, wit-ness for the Attorney General’s office, hadstated in pre-filed testimony that the priceindex in the ConocoPhillips contract, forexample, should reflect an average pricefor gas across the various tiers, not thebase price.
“No one wants to pay any more for anycommodity or service than they have to,”answered Dubay. “… We think we’veended up with the best deal that we couldcraft.”
The hearing continues until Aug. 8. ●
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ENSTAR
Harrison, an asset manager with BP.“The current business environment has
enabled that to happen now,” Harrison said. Comparing the Badami facilities to a car
unable to move at half a mile per hour,Harrison said it became “doubtful” BP couldkeep the Badami plant and pipeline alive atthe low production rates seen over the pastfew years.
BP talked with several companies overthis past winter, and eventually signed a dealwith Savant, which agreed to bring theASRC Energy Services in as a partner atBP’s request.
Plan to frac horizontal wellsBP shut down the Badami field a year
ago to “recharge” the reservoir, hoping thatallowing the field to rest would build uppressure underground and ease production.
But that move was only the most recentin a decade of frustrating starts and stops.
The easternmost developed field on theNorth Slope, Badami originally promised toproduce around 35,000 barrels of oil eachday at its peak.
That would have made it the fifth mostproductive oil field on the North Slope, butBadami underperformed from the start, pro-ducing only 5,000 bpd during its first fewmonths, about half of the expected startupvolume.
The field was only producing around 900bpd by the time BP shut it down last year.
The reason for that low output was thecomplex geology of Badami, considered bysome to be among the most challenging inthe world to develop.
The turbidite formation at Badami has aseries of channels, like fingers on a hand.The trouble has been getting those channelsto “communicate” so that oil moves from
one to the next. Savant plans to drill horizontal wells at
Badami and hydraulically fracture the chan-nels to reach more of the oil-bearing sands.Previous attempts to develop Badami haveused hydraulic fracturing, but only on tradi-tional vertical wells.
The technology for fracturing a horizon-tal well simply didn’t exist when BP firsttried to develop Badami in the late 1990s,according to Greg Vigil, executive vicepresident and chief operating officer forSavant.
Hydraulic fracturing involves pumping
large amounts of fluid into a well in order tocreate new avenues in the reservoir for oiland gas to travel to the surface.
Vigil said high oil price alone wouldn’thave justified returning to Badami. Onlyhigh prices in conjunction with the newtechnology promise to make the venture asuccess.
Badami a technical problemAlthough Savant is relatively new to
Alaska, arriving during a March 2006 leasesale, the company already has experiencenear Badami.
This past winter, Savant drilled theKupcake No. 1 exploration well from an iceisland in Foggy Island Bay, less than 20miles west of Badami.
Ultimately, though, Kupcake failed touncover the oil Savant hoped to find.
Vigil said Badami is more in line with theprojects Savant prefers, where the trick isn’tfinding oil, but getting known accumula-
tions of oil out of the ground. Because even if Kupcake had been suc-
cessful, Savant would have needed to spendtime and money connecting the field toexisting infrastructure on the North Slope.
That infrastructure is already in place atBadami.
“We’re taking technical risk as opposedto exploration risk in the Brookian sands,”Vigil said.
This winter, Savant plans to drill anexploration well in one of the satellite fieldsoutside the Badami Sands participating area,but within the larger Badami unit. If BP andSavant fail to perform the work commit-ment laid out in the development plan, thecompanies have agreed to relinquish all theleases outside of the Badami Sands partici-pating area.
—ERIC LIDJI
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BADAMI
CO
URT
ESY
BP
The easternmost developed field on the North Slope, Badami originally promised to produce around 35,000 barrels of oil each day at its peak.
