In the Matter of Minnesota Power’s 2013-2027 Integrated Resource Plan 20139-91328-01 MN power...

8/14/2019 In the Matter of Minnesota Powers 2013-2027 Integrated Resource Plan 20139-91328-01 MN power carbon pricin

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Minnesota Public Utilities CommissionStaff Briefing Papers

Meeting Date: September 25, 2013 .............................................................. **Agenda Item # 3

Company: Minnesota Power (MP or the Company)

Docket No. E015/RP-13-53

In the Matter of Minnesota Powers 2013-2027 Integrated Resource Plan

Issues: Should the Commission approve MPs 2013-2027 resource plan?

Should the Commission take any further actions in the resource plan?

Staff: Sean Stalpes ................................................................................. 651-201-2252

Relevant Documents

Minnesota Power Resource Plan, initial filing .......................................................... March 1, 2013Staff briefing papers on completeness ....................................................................... April 17, 2013Commission Order Finding Resource Plan Complete ................................................ May 10, 2013Minnesota Power, Supplemental Filing as required by Commission Order ............... May 15, 2013Department of Commerce, initial comments ................................................................ June 3, 2013Environmental Intervenors, initial comments ............................................................... June 3, 2013Large Power Intervenors, initial comments .................................................................. June 3, 2013Department of Commerce, reply comments .................................................................. July 3, 2013Environmental Intervenors reply comments .................................................................. July 3, 2013Large Power Intervenors, reply comments .................................................................... July 3, 2013Minnesota Power, reply comments ................................................................................ July 3, 2013

The attached materials are workpapers of the Commission Staff. They are intended for use by the PublicUtilities Commission and are based upon information already in the record unless noted otherwise.


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Staff Briefing Papers for Docket No. E015/RP-13-53 on September 25, 2013 Page 2

This document can be made available in alternative formats (e.g., large print or audio) by calling

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preferred Telecommunications Relay Service.


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Contents

Staff Comment on the Scope of This IRP ..................................................................................................... 4

Staff Comment on Modeling ........................................................................................................................ 7

MP Initial Filing .......................................................................................................................................... 11

Company Background ............................................................................................................................. 11

Generation .............................................................................................................................................. 11

Transmission ........................................................................................................................................... 12

Renewable Energy .................................................................................................................................. 13

Demand-Side Management ..................................................................................................................... 17

Needs Projection ..................................................................................................................................... 18

Action Plan Summary ............................................................................................................................. 20

Plan Development ................................................................................................................................... 22

1. MATS compliance ...................................................................................................................... 22

2. Retrofit, Refuel, or Retire ........................................................................................................... 24

3. Identify a Preferred Expansion Plan ........................................................................................... 28

4.

Scenario Analysis ........................................................................................................................ 29

Party Positions ............................................................................................................................................ 32

Departments of Commerce ..................................................................................................................... 32

Environmental Intervenors ..................................................................................................................... 39

Large Power Intervenors ........................................................................................................................ 41

Non-Party Comments .................................................................................................................................. 46

Schroeder Township ................................................................................................................................ 46

Town of Tofte .......................................................................................................................................... 46

City of Aurora ......................................................................................................................................... 46

Public Comments .................................................................................................................................... 46

Staff Analysis .............................................................................................................................................. 47

Decision Options ......................................................................................................................................... 63


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Staff Comment on the Scope of This IRP

Minnesota Powers 2013 resource plan is unique for several reasons. First, the comment periodswere shortened to recognize the urgency for compliance with EPAs Mercury and Air ToxicsStandards (MATS).1 Second, a preliminary completeness review was brought before the

Commission in April 2013 to identify potential issues of dispute, and MP filed supplementalinformation concerning areas of interest to the Commission. Third, because this resource planincorporates the Companys MATS compliance strategy, this resource plan focuses on existingfacilities, which is not normally as central to resource planning.

Ideally, resource plans make generic findings about which resources could meet a utilitysprojected need and when. MP explores the circumstances under which retiring certain existingcoal-fired units is more cost-effective than continuing to operate them. Thus, the size, type, andtiming of MPs resource need depend on the Companys short-term MATS compliance strategyand long-term CO2emissions minimization strategy.

Relationship to MPs Previous IRP

In MPs 2010 IRP proceeding, the Commission ordered MP to develop a baseload diversificationstudy (BDS) to address the retire, retrofit, or refuel question posed to MPs existing coal fleetimpacted by newly promulgated EPA rules. While the Department of Commerce (DOC)recommended certain coal units could be retired as a credible outcome of the BDS, MP did notagree that unit decisions could be made from the BDS. MPs reply comments in the baseloadstudy proceeding state:

Despite what some parties suggest, the BDS does not provide valid economic or

reliability information for taking responsible, material action on any individualMinnesota Power units or its system as a whole that would result in billions ofdollars of impact on customers.

Now that MP is on an actionable path to comply with MATS, there is a different interpretation ofhow the BDS informs unit-specific dockets. For example, the Companys Boswell 4 RetrofitPetition states that MP identified in its Baseload Diversification Study that the Boswell Unit 4Retrofit Project was the most economic environmental compliance alternative.2

As MP has stated previously and in this resource plan, the IRP process does not finalize project-specific decisions it informs them. As the Commission considers the Companys MATS

compliance strategy in this proceeding and in future petitions, Staff refers the Commission toAppendix D of MPs 2013 resource plan, in which the Company states: 3

1Under the Clean Air Act, affected sources have three years (until April 2015) to comply with MATS. A fourthyear for compliance is available if reliability issues exist. MP has only requested an extension for Boswell 4.2Docket No. E015/M-12-920,In the Matter of MPs Mercury Emission Reduction Plan Petition and Petition forApproval of the Rider for Boswell Energy Center Unit 4 Emission Reduction, p. 12 of MP Reply Comments.3Appendix D, p. 6


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The Strategist Proview simulations are not robust enough to dictate the ultimateretirement planning decision for a generating asset; they can, however, be a usefulplanning tool to narrow the options through careful evaluation of the retirementtiming trends seen and as they are stressed through multiple sensitivities andplausible scenarios for future economic and power supply variables.

Three major areas of MPs five-year action plan encompass its MATS compliance, windadditions, and 2015 capacity deficit:

1. MPs Laskin natural gas refuel project and Taconite Harbor 3 retirement are included aspart of the Companys Preferred Plan because each complies with MATS, is cost-effective in most scenarios, and is part of the Companys long-term plan to reduce carbonemissions. (MP also proposes to retrofit Boswell 4 and continue its operation as a coal-fired resource. Staff does not provide decision options for the Commission concerningBoswell 4 in this IRP. MP notes in the IRP that alternatives at Boswell 4 are reserved forconsideration under the Boswell 4 Retrofit Project, Docket 12-920.)

2. MPs IRP includes the addition of a minimum of 100 MW and up to 200 MW of windthat would be installed in the next two to three years, with plans subject to the availabilityof the Production Tax Credit (PTC). Consistent with this intention, on August 1, 2013,MP announced its plans to construct Bison 4, a 200 MW wind addition in North Dakota.

3. With or without the Taconite Harbor 3 retirement, MP expects to begin to accumulate acapacity deficit in 2015. MP plans to procure cost-effective bilateral purchases as abridge until 2020-2021.

The decision options on page 63 of this document enable the Commission to define its ownscope of this IRP. The Commission can approve the plan and take no other action, or theCommission can make findings of fact, require compliance filings to further inform the record,and set requirements for the Companys next IRP.

MP has indicated the Company will be making a separate filing later this year for approval of itsBison 4 project. Its Boswell 4 MATS compliance strategy is being addressed in Docket No. 12-920. It does not appear that further regulatory approvals are required for MP to refuel Laskin orretire Taconite Harbor 3. However, upon approval of its resource plan, MP expects to make anAttachment Y request with MISO for retiring Taconite Harbor 3.

Implications for MPs Depreciation Accounting

MPs retirement analysis basically considers three main categories of costs:1. remaining asset value;2. decommissioning cost; and3. replacement capacity and energy cost.


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While MPs retirement analysis will be discussed later in this document, Staff reminds theCommission of the IRPs overlap with MPs 2012 Remaining Life Depreciation Petition (DocketNo. 12-378). In MPs October 29, 2012 reply comments in Docket 12-378, the Companysuggested the Commission address and decide issues related to the remaining lives of existingcoal-fired facilities in this IRP:

Minnesota Power believes that issues related to resource decisions and remaininglives are best addressed and decided as part of Minnesota Powers 2013 IRP andassociated depreciation studies.

Intervening parties did not discuss, or provide recommendations for, how remaining lives shouldbe addressed and decided in this IRP, other than when or if certain units should be retired.

MPs October 29, 2012 reply comments in Docket 12-378 provide the remaining life for thefollowing coal-fired facilities:

The remaining asset value significantly impacts the decision of when (or whether) to retire anexisting unit. According to Appendix H of MPs Petition, the remaining asset value of anyfacility being retired is treated as a cost which is assumed to be recovered from customers over a10-year period after the retirement takes place. This is strictly a modeling choice on the part ofthe Company. Staff recommends that MPs assumptions about cost recovery in the modeling ofthe instant IRP do not in any way decide whether or how MP will get that recovery.

According to the Company, Upon approval of this 2013 Plan, MP will continue to depreciateLaskin Energy Center and Taconite Harbor Energy Center each as one facility with one

remaining life. Assets retired in 2015 will be accounted for as normal retirements of utilityplant. MP intends to submit a compliance filing with final accounting entries in late 2015 orearly 2016 when final retirement amounts are available.4

4Approximately $5 million in net remaining plant balance for Laskin Energy Center and $15 million in netremaining plant balance for Taconite Harbor 3 are expected to be retired. Laskin Energy Center and THEC1&2 willcontinue operations, and the remaining net plant balances retired will be recovered over the remaining lives of thoseplants.


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Staff Comment on Modeling

As stated above, evaluating retirement, retrofit, or refuel options for the Companys existing coalfleet is central to MP resource plan. Because unit performance is so closely tied to unitdecisions, and because the parties comments discuss very granular details about the appropriate

operation of the system, it may be useful to briefly discuss why these details are important to theCommission for an IRP.

A load and capability (L&C) balance informs the size and timing of generation resources thatshould be added to meet customer demand. The function of an L&C table is to provide acomparison between the amount of generating capacity available and the peak load of a systemplus planning reserves.

Each existing resource that makes up the L&C table is modeled separately in Strategist andincludes both operational characteristics and costs of operation. The economics of systemdispatch are sensitive to the alternatives Strategist is allowed to consider and the assumed costs

of running the units themselves. Assumptions for heat rates, outages, operation andmaintenance, and availability of market energy can all impact unit dispatch and, in turn, affectprojected capacity factors for existing thermal units. Thus, the mix and characteristics of allavailable generation to a system affect the generation expected from any particular unit (andwhether it functions as a peaking, intermediate, or baseload resource).

Each thermal unit in the L&C table also has an annual fixed cost. Within that fixed cost is arevenue requirement for the capital cost for equipment needed to comply with EPA rules.Therefore, the impact of MATS on MPs existing coal facilities could be a capital investmentincluded in the Present Value Revenue Requirement (PVRR). For example, if a coal unitrequires a dry scrubber to treat the units flue gas, a fixed capital investment is included in the

PVRR and compared to the retirement cost associated with that unit.

Some of MPs units are already controlled to meet (or nearly meet) MATS requirements. Thus,the impact of MATS could alternatively be an increase to a units operating costs (in $/MWh).For example, if a unit only requires additional sorbent to reduce acid gases, this additional costcould make the unit more expensive to operate, and as a result, Strategist may dispatch other,more economical, resources instead.

Since MPs coal units provide baseload generation to the system, the extent to which alternativescould reasonably replace those facilities with historically high capacity factors can come withtheir own cost and technical limitations. MP discusses the relative benefit of one MATS strategy

over another in terms of a full production cost analysis of its system in Strategist. Thisincludes projections of fuel costs, externalities, and wholesale market interaction incorporatedwith operational factors, such as the forced outage history and actual dispatch history.

MPs MATS compliance strategy, and the expansion plan that follows it, implies the system isbeing appropriately optimized by the Strategist model. The extent to which system optimizationis achieved is bounded by a user-defined set of resource technologies and prescribed sets ofconstraints and assumptions. In this record, disagreement exists concerning a wide variety of


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planning assumptions, which ultimately leads to differences in recommendations that certain coalunits should be retired, refueled, or kept as coal-fired facilities.

Strategist can formulate hundreds of thousands of possible resource combinations to construct aleast-cost expansion plan. As the need for additional capacity increases, the number of possible

combinations also increases. Narrowing the number of alternatives for evaluation shortens themodel run-time (which can require weeks) and enables better verification and validation of themodel. Both MP and the Department narrowed Strategist in its own way. MP ran four swimlanes, each with a base case and 21 sensitivities (88 outcomes). The Department ran 15different scenarios, each with 31 different contingencies (465 outcomes).

How units are assumed to operate to serve both the demand and energy requirements of thesystem is a critical component of the modeling. Navigating the complexities of the Strategistmodel to verify these assumptions is not normally as central to IRP, at least for the Commission.The fact remains, substantial capital expenditures will be necessary to bring MP into compliancewith MATS in the short-term. The parties recommendations to the Commission regarding the

best path forward are grounded largely on these granular aspects of system planning.

Boswell 4

MPs IRP scenario analysis does not give the Commission a clear picture of how a natural gasalternative at Boswell 4 would realistically affect its action plan. MP provides options for whatgeneration could replace Boswell 4 in Docket 12-920, but these options do not reflect how all ofMPs electric supply resources would operate to serve both the demand and energy requirementsof the system.

The Commission could decide in Docket No. 12-920 that a natural gas alternative is preferable.Since Boswell 4 provides roughly one quarter of MPs energy requirements, it may have littlevalue to approve MPs resource plan if the Commission moves the Company toward repoweringthe unit. According to MPs response to PUC IR #6c. in Docket 12-920:

The natural gas build schedule would likely create a 2 to 3 year period of powersupply deficit between the time when Boswell 4 would be shut down and whenthe new natural gas facility would be available. MP would need to seekalternative power supply options for 478 MW of capacity and approximately 3million MWhs of energy each year to serve its customers. This volume of nearterm market interaction would more than double Minnesota Powers current nearterm market utilization for normal operations. This level of market interactionwould create significant risk for implementing Minnesota Powers current nearterm least cost strategy.

MP states in its IRP reply comments that the Companys utilization of near-term marketpurchases for its power supply strategy has averaged 18 percent since 2004.5 If MP plans tomore than double this exposure to the wholesale market, Staff believes the entire resource plan

5MP July 3, 2013 reply comments, p. 18.


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should berevisited because MPs instant IRP does not reasonably plan for Boswell 4 to berefueled.6

Demand-Side Management

On May 15, 2013, MP filed its Supplement to the IRP, pursuant to the Commissionscompleteness order requesting further information. Among those topics ordered by theCommission was how MP evaluates demand side management (DSM) programs in themodeling. The Commission asked MP whether DSM is considered as a reduction in load versusa resource to be chosen at an optimal level.

According to the Companys Supplement, MP utilizes a combination of load reduction andresource alternative methods for incorporating DSM into its resource planning evaluation. Sinceeach DSM option is unique, MP does not believe there is not a one-size-fits-all approach forevaluating DSM in general.

The Department hosted a multi-utility and stakeholder discussion on DSM and MISO modelingon May 28, 2013. Members of the DOC, Commission Staff, Center for Energy andEnvironment, and several utilitiesincluding MPwere present.

MP explained at the stakeholder meeting that existing DSM is embedded in the load forecast, butStrategist considers future DSM as a resource option. For example, MPs IRP discusses aroughly 7 MW direct load control program which is separate to its load forecast. For energysavings, though, MP assumes a constant annual savings of approximately 52.3 million kWh,which is embedded in the load forecast. This annual savings level presumably corresponds to anamount at or above the 1.5 percent savings goal. MPs 52.3 kWh of savings is included in Table1 of Appendix B.

6MP states in response to PUC IR#6 that intermittent wind and solar would not be viable candidates and additionaldispatchable hydro above current levels is not currently available in the region until the 2020 time period.


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The Department does not have a standardized method for modeling DSM. DOC explained at thestakeholder meeting that, in IRP, the Department receives the commands from the utility toevaluate its DSM. Thus, DOC has several different methodologies for DSM evaluation becauseseveral different methodologies exist among the utilities.

Typical of most Minnesota utilities, MPs DSM has the effect of offsetting the demand and salesforecast, and the IRP determines the least-cost expansion plan given the net resource requirementwith DSM already accounted for. InAttachment A, Staff includes a table from a report preparedfor the California Public Utilities Commission,7which shows the variety of ways DSM andenergy efficiency can be incorporated into modeling. If the Commission wants to know howDSM and energy savings can be modeled within a utilitys planning software on an equivalent

basis to supply-side resources,Attachment Aprovides examples of other utilities which utilizethat method of evaluation.

7Aspen Environmental Group & E3, Survey of Resource Planning and Procurement Practices, prepared for theCalifornia Public Utilities Commission, pp. 65-67.


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MP Initial Filing

Company Background

Minnesota Power (MP) serves about 144,000 retail electric customers and 16 municipal systems

in central and northeastern Minnesota. More than half of MPs total energy supply is sold toindustrial customers with continuous operation. As a result, MP has a higher load factor and lessvariable load profile than most utilities.

Generation

MP generates about 80 percent of its energy from coal-fired units, primarily at its Boswell,Laskin and Taconite Harbor Energy Centers in Minnesota.

Unit Net Output(MW)

Year in Service

Boswell 1 & 2 140 1958, 1960

Boswell 3 365 1973

Boswell 48 585 1980

Laskin 1 & 2 110 1953

Taconite Harbor 1 & 2 150 1957

Taconite Harbor 3 75 1967

1. Boswell Energy CenterBoswell Energy Center (BEC) consists of four coal-fired generating units with a sharedinfrastructure. BEC provides approximately 1,000 MW of capacity and nearly half of theCompanys energy requirements. The Minnesota Mercury Emissions Reduction Act (MERA)requires Boswell 3&4 to install mercury emission controls with the goal to achieve up to 90percent mercury removal. Boswell 3 has already complied, and MP is currently requestingapproval for its Boswell 4 Retrofit Project in Docket 12-920.

2. Taconite Harbor Energy CenterTaconite Harbor Energy Center (THEC) is located near Schroeder, Minnesota, on the NorthShore of Lake Superior. THEC consists of three 75 MW coal-fired generating units, with a totalcapacity of 225 MW. The generators all operate at capacity factors of 60 to 75 percent on anannual basis.

8MP owns 497 MW of Boswell 4 with the balance owned by WPPI Energy.


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THEC does not have direct access to natural gas as a fuel source. No pipeline is present, and theclosest access is 30 miles from the facility. THEC is located at an active shipping port on LakeSuperior and receives coal shipments via boat for its operations.

As part of MPs Arrowhead Regional Emissions Abatement (AREA) plan in 2006-2008,Taconite Harbor 1 and 2 have been retrofitted with NOX, SO2, and mercury emissions controlequipment. Therefore, MP believes Taconite Harbor 1 and 2 are well-positioned to meet therequirements of EPAs MATS rule in 2015. Taconite Harbor 3, however, does not currentlyhave the necessary emission controls in place to meet the MATS requirements.

3. Laskin Energy CenterLaskin Energy Center (LEC) is located near Hoyt Lakes, Minnesota. The facility is in closeproximity to one of the major natural gas pipelines in the region, Northern Natural, and utilizesnatural gas as a starting fuel for its current coal-fired operations. The units have operated at

capacity factors of 50 to 60 percent over the past six years as market and operating conditionshave changed.

LEC also had emissions controls installed as part of MPs AREA. However, the EPA MATSrule would require that LEC install additional boiler injection technology to further reducemercury emissions.

Transmission

1. The North Shore LoopMP refers to the North Shore Loop as an area of its transmission system that is extremelygeneration-rich and serves a significant portion of the large industrial customers in MinnesotaPowers load requirements.9 The North Shore Loop includes the 115 kV and 138 kVtransmission system between Duluth, Taconite Harbor, and LEC, as well as the three 115 kVlines that extend from the Laskin facility to the rest of the transmission system.

2. Great Northern Transmission LineMP expects to file a certificate of need for the Great Northern Transmission Line by the end of2013.10 The project will include high voltage connections between Manitoba and the Arrowhead

Substation in St. Louis County, Minnesota, to enable deliveries from Manitoba Hyrdro. Theproposed construction includes approximately 225-300 miles of 500 kV transmission line andapproximately 50-70 miles of 345 kV transmission line.

9Appendix F, p. 14.10Docket No. E015/CN-12-1163


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The Great Northern Transmission Line is intended to provide delivery of at least 250 MW ofenergy and capacity from Manitoba Hydro by June 1, 2020 under a Power Purchase Agreementapproved by the Commission in Docket No. 11-938.

3.

The DC Line

In 2010, MP finalized its purchase of a 465 mile, 250-kilovolt high voltage direct currenttransmission line which connects Center, North Dakota with the Arrowhead Substation inHermantown, Minnesota. This DC Line is expected to facilitate the delivery of wind powergenerated in North Dakota to MPs customers.

MP expects to complete a 50 MW upgrade to the DC Line by the end of 2013 to further developthe reliability of its Bison Wind projects. MP is evaluating a series of modernization activitiesto the DC Line to possibility increase its deliverable capacity up to 750 MW in the future.

Renewable Energy

Minnesotas Renewable Energy Standard (RES) requires MP to generate or procure at least thefollowing percentages of total Minnesota retail electric sales with eligible renewable energytechnologies by the end of the year indicated:

12 percent by 2012 17 percent by 2016 20 percent by 2020 25 percent by 2025

1. Biomass and HydroMPs Renewable Base (Table 1 below) is comprised of biomass and hydroresources andmeets approximately 6 percent of MPs projected 2025 retail electric sales.11

11Thomson Hydro station is currently inoperable for an undetermined amount of time due to damage sustained inthe severe flooding of June 2012. Thomson Hydro is still a component of MPs IRP, and MP does not anticipate theinoperability to affect the achievability of the RES.


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Also, a non-firm energy supply PPA with Manitoba Hydro is assumed to count as renewableenergy credits (RECs) and covers a period from May 1, 2011 through April 30, 2022.12

Planned Biomass Expansion Projects

A.

Rapids Energy Center Optimization

Rapids Energy Center (Rapids) is a non-regulated co-generation facility located at the BlandinPaper Mill in Grand Rapids, Minnesota. Rapids is fueled by a mixture of wood and coal.

MP currently has before the Commission a Petition for approval to increase the biomassgeneration at Rapids by approximately 56,000 MWh per year by 2015.13 The Rapids Projectwill not result in increased nameplate electric generation capacity at Rapids; instead, the goal ofthe project is to improve the capability for Rapids to more routinely utilize the full nameplatecapacity of its solid fuel boilers and connected turbines.

Rapids currently generates approximately 70,000 RECs per year. These RECs are included inthe Companys internal projections for meeting 2025 RES requirements. While MP does notproject a shortage of RECs to meet current RES requirements in the next ten years, may need touse banked RECs in order to meet the 25 percent goal in 2025.

B. Hibbard ExpansionHibbard Renewable Energy Center (Hibbard) is a coal and biomass generation facility located inDuluth, Minnesota. MP plans to increase in biomass generation at Hibbard by 140,000 MWh peryear. MP has not yet determined its expansion schedule at Hibbard. The expansion wasscheduled to be completed in the 2012/2013 timeframe, but has been delayed to a yet-to-be-determined future date to better coincide with MPs anticipated needs for renewable energy.

2. Wind AdditionsBetween 2006 and 2011, MP executed several PPAs and constructed a wind facility to increaseits renewable energy supply to approximately 12 percent of projected 2025 electric sales. Uponcommercial operation of approved renewable energy projects, MPs renewable portion of retailsupply will increase to approximately 18 percent by the end of 2013.

The Bison wind projects near Center, North Dakota have been the bulk of MPs renewableenergy additions since 2010. The 81.8 MW Bison 1 project came online in two phases, the firstphase in December 2010, and the second in January 2012. Adjacent to Bison 1, Bison 2 and 3are each 105 MW projects which became commercially available in December 2012. MP owns,

12Docket No. E015/M-10-96113Docket No. E015/M-12-1349, In the Matter of the Petition of Minnesota Power for Approval of Transferring theAssets of Rapids Energy Center to Regulated Operations and Approval For Investments and Expenditures in theRapids Optimization Project for Recovery through Minnesota Powers Renewable Resources Rider under Minn.Stat. 216B.1645.


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operates, and maintains the Bison facilities for long-term use as a rate-based renewable windgeneration resource.

On August 1, 2013,MP announced its plans to construct Bison 4, a 200 MW expansion of itsBison wind project.14 Bison 4 will be constructed in Oliver County, North Dakota. The

expansion will include a new substation and approximately 11 miles of a 230 kV transmissionline. MP has filed a site permit application with the North Dakota Public Service Commissionand intends to submit a request to the Minnesota Commission for project approval and costrecovery through MPs Renewable Resources Rider.

Table 2 summarizes the projected annual energy production and estimated capacity additions ofcommitted and planned renewable resource additions.

The renewable resource additions in Table 2 were also filed in Docket No. E999/M-12-958 (the

biennial RES compliance review). In 12-958, the Commission did find MP to be in compliancefor the past two years and anticipated compliance going forward.

Figure 1 below shows that pending approval of the Bison 4 project, Hibbard expansion, andRapids optimization MP will continue to meet its RES obligations. The committed windprojects have increased MPs renewable resource portfolio to about 18 percent of projected 2025sales. Bison 4 would increase this percentage further, up to about 24 percent of projected sales.

14Staff notes that MPs March 1, 2013 IRP filing included plans to issue an RFP for up to 200 MW of wind capacityand energy. On April 2, MP filed a Wind RFP Update, including a summary and schedule of the wind RFP.


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The estimated costs of MPs renewable plan are provided in Figure 3 (from Appendix G of thePetition). The levelized revenue requirements of MPs renewable projects (the green line) areprojected to be priced competitively with the longer-term outlook for wholesale market energyprices (the red line). The blue line shows the annual revenue requirements. As shown in thefigure, the recent spike in annual revenue requirements is due to the Bison projects.


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MP used the estimated project costs to approximate the rate impact of the renewable energyprojects over the long term. MP calculates that its identified renewable projects are estimated tohave an average of a $3 per MWh cost impact for customers from 2007 to 2026.

Demand-Side Management

MP includes a prospective air conditioning (AC) cycling program as an expanded DSM programfor its 2013 Plan evaluation. This program expansion amounts to a total peak reduction ofapproximately 7.6 MW by year 15 of the program. Due to economical generation alternativespresently available, as well as regional surpluses, MP notes the benefits of the AC cyclingprogram are likely to be limited in the near term. MP expects the earliest an AC cycling programcould be implemented for customers would be the 2015 timeframe to accommodate additionaldesign and gain regulatory approvals.

MPs Preferred Plan includes achieving the 1.5 percent savings goal throughout the planningperiod. MP assumes in each year of the planning period that the Company will achieveapproximately 52.3 million kWh of energy savings, which is consistent with the historicalperformance of its energy efficiency programs. The impacts of MPs energy savings are


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embedded in the energy sales forecast. MP did not include in its Petition additional analysis thatevaluates achieving higher levels of conservation energy savings than the 1.5 percent.

On June 3, 2013, MP filed its 2014-2016 Triennial Conservation Improvement Program (CIP).15MP proposed a plan which, according to the Company, meets the 1.5 percent energy-saving goal

and has program budgets well above the minimum spending requirements for conservationprogram efforts.

MP calculates its energy-saving goal and spending requirements in accordance with the CIPstatute, using gross annual retail energy sales and gross operating revenues.16 Proposedprograms and budgets are made within the context of those calculations. As a result oflegislation passed in May 2013, Minn. Stat. 216B.2401 was amended from an annual energy-saving policy goal equal to 1.5 percent, to a policy goal of at least 1.5 percent of annual retailenergy sales of electricity and natural gas through a variety of programs or actions that may, ormay not, involve direct utility involvement. (CIP is an example of a conservation-relatedprogram that does involve direct utility involvement.)

MP does not believe the statute amendment changes any requirements for MPs large industrialcustomers nor does it change the Commissions jurisdiction over CIP. There was no repealer oramendment to Minn. Stat. 216B.241 which changes MPs large power customers to petition forCIP exemptions. Therefore, retail energy sales still exclude, by definition in statute, electricsales to large customers that have obtained approval from the Commissioner of Commerce to beexempt from CIP.

MP believes large customers are already highly incentivized to conserve energy and adoptenergy-saving practices in order to control utility related expenses.

Needs Projection

As a MISO member and market participant, MP falls under the requirements of the MISOModule E Resource Adequacy Program for near-term planning. MP is a winter-peaking utility,but bases its resource need on the summer season MISO Load and Capability (L&C) balance.Since most other regional utilities are summer peaking and, accordingly, have large wintercapacity surpluses, winter capacity is typically available for purchase.

Figure 5 presents MPs base case summer season L&C. As illustrated by the red bar in Figure 5,MPs coal fleet comprises about 1,300 MW of MPs 1,700 MW of capability.

Under the base case outlook, MP does not project a summer capacity deficit until 2018. Of note,no retirements of MPs thermal or hydro generation resources are included in the base case L&Cbalance, although MPs Preferred Plan is to retire the 75 MW Taconite Harbor 3 unit.

15Docket No. 13-409.16Minn. Stat. 216B.241Subdivision 1 and Subd. 1a, respectively.


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MPs winter peak is typically about 60 MW higher than its summer season peak; therefore, thesurplus and deficit outlook is slightly different when shown for the winter season peaks.However, MP notes that the general trends remain the same, as there is very little deficit in thenear-term. MP believes its existing generation and planned renewable energy additions, alongwith economic purchases, can meet the projected needs of its customers for the next severalyears.

During the Companys IRP completeness review, Staff raised the issue that MP and theDepartment employ two different methodologies to calculate a planning reserve margin (PRM).For long-term expansion planning evaluations, MP uses the installed capability (ICAP) capacityvalue. The Department, on the other hand, uses the unforced capacity (UCAP) accreditation toreflect historical forced outage data for MPs system.17

In its completeness order, the Commission directed the Company to demonstrate how the use ofUCAP would have impacted its base case and preferred plan.18 MP filed this supplementalinformation on May 15, 2013. When MP recalculated its base case and Preferred Plan to includethe use of UCAP values, the capacity need was basically the same between the UCAP and

ICAP methods, as shown in the figure below:19

17ICAP represents the maximum generating capacity of a given facility. UCAP represents the amount of ICAP thatis actually available at any given time after discounting for time that the facility is unavailable due to outages, suchas for repairs. In other words, ICAP times a forced outage rate equals UCAP. MP included a forced outage rate forexisting generating resources in its Strategist expansion plan evaluation to ensure the energy production/dispatch foreach of its units was accounted for.18Commission Order Point #2 in its May 10, 2013 Order.19MP Supplemental Filing, May 15, 2013, p. 7.


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Action Plan Summary

MPs resource plan addresses two key long-term planning questions. First, what environmentalcompliance strategies will be utilized to keep its coal-fired generation in compliance with therecently finalized MATS regulations, and second, how will it position its power supply to meet

the emerging load growth potential in its service territory.

MPs 2013 IRP builds from the modeling conducted in the Companys baseload diversificationstudy (BDS). According to MP, the study itself was necessarily only exploratory and largelyprovisional.20 Unlike the BDS, the IRP 2013 provides the level of information necessary forresource decisions that are in the public interest.

Specifically, the plan includes the following Commission requirements from the BDS Order:

A proposal to address the viability of Laskin Energy Center, Units 1 and 2, and TaconiteHarbor Energy Center, Unit 3.

MP has identified that Laskin Energy Center (110 MW) and Taconite Harbor 3 (75 MW) are notcost effective to retrofit with additional environmental controls. MPs 2013 IRP proposes torefuel Laskin Energy Center to a natural gas peaking station and retire Taconite Harbor 3.

20MP Initial filing, p. 7.


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An evaluation of the consequences including all relevant costs and the consequencesfor transmission adequacy of retiring Boswell Energy Center, Units 1 and 2 by 2020.

MP expects to operate Boswell Energy Center throughout the planning period.

Scenarios that add 100 to 200 MW of wind capacity in the 2014-2016 time frame.MP has announced plans to construct 200 MW of wind (Bison 4) prior to December 31, 2015.

Scenarios that add 400 to 600 MW of natural gas capacity in the 2014-2016 time frame.MP concludes from its analysis that a natural gas combined cycle unit is not economic for itscustomers prior to 2020, largely due to lack of need for the capacity. However, MP expects itsnext large power supply addition beyond 2020 may be a combined cycle gas plant.

A comprehensive socioeconomic impact analysis by customer class in conformance withthe Commissions resource planning rules.

MP commissioned the University of Minnesota-Duluth to develop a socioeconomic impact studyof the full closure of Laskin and Taconite Harbor Energy Centers. This study is provided asAppendix K of MPs 2013 IRP filing.

Table 6 shows MPs preferred expansion plan with its base assumptions and for a carbonregulation scenario, which applies CO2prices of $21.50 per ton starting in 2017.


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Both expansion plans are very similar, except the CO2regulation scenario is more expensive andresults in more wind additions.

Plan Development

MPs 2013 resource plan consists of a four-step planning evaluation to arrive at theenvironmental compliance strategy for each facility and to position the Companys supply forlong-term customer requirements. The four sequential steps include:

1. MATS compliance;2. Retrofit, Refuel, or Retire;3. Identify a preferred expansion plan; and4. Conduct a scenario analysis

Taken together, MP refers to this process as the Companys EnergyForwardstrategy.EnergyForwardwill shift MPs resource mix to a one-third, one-third, one-third balance ofcoal, natural gas and renewable energy plus conservation.

1. MATS complianceTo create its Preferred Plan, MP first determines the requisite MATS compliance measures at itscoal-fired generation facilities. MP describes how planning for required controls is modeled in

two separate cases: a Base Case EPA scenario that reflects environmental regulations laid outwith fairly certain requirements, and an EPA Sensitivity case that reflects environmentalmeasures with a higher level of uncertainty:

The Base Case EPA scenario includes measures that address the MATS, the IndustrialBoiler maximum-achievable control technology (MACT) rule, National Ambient AirQuality Standard (NAAQS) revisions, Regional Haze requirements, 316(b) cooling waterregulations, the MERA requirements for large coal-fired boilers and Subtitle D Non-Hazardous waste designation for coal combustion residuals (coal ash).

The EPA Sensitivity case includes all measures from the Base Case plus water treatmentrequirements for Effluent Limitation Guidelines and greenhouse gas regulation onexisting sources.

The overall cost for emission control measures, not including any CO2prices,21is summarized in

Table 1.

21The EPA Sensitivity case excludes CO2costs because this scenario assumes EPAs greenhouse gas regulation.Therefore, inclusion of CO2would have been, in effect, double counting CO2.


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Totals shown in Table 1 reflect the environmental controls needed for all the coal fueled units atBEC, LEC, and THEC to satisfy environmental requirements. Of note, Table 1 includesestimated costs for proposed Boswell 4 Retrofit Project, but not expenditures for controls alreadydeployed (e.g. Boswell 3 retrofit under the AREA plan).

A majority of MPs fleet will have some level of requirements under the Base Case EPAscenario and EPA Sensitivity case. Specific to MATS compliance only, the following is asummary unit-by-unit impact for MATS requirements (i.e., mercury, acid gases, and particularmatter control):

Boswell 1 and 2. Boswell 1 and 2can meet MATS requirements by averaging provisionsfor the overall BEC infrastructure.22 Through the Boswell 4 Retrofit Project and Boswell3 AREA investments, MP does not need to further reduce mercury emissions at Boswell1 and 2.

Boswell 3. Because of the emissions controls already installed at Boswell 3 to meetMERA, Boswell 3 does not need to further to reduce mercury for MATS.

Boswell 4. The Boswell 4 Retrofit Project before the Commission in Docket 12-920would also address MATS compliance.

Laskin Energy Center Units 1 and 2. To meet MATS requirements, LEC would need tobe retrofitted with mercury emission controls, the existing wet particulate control systemswould have to be replaced, and other acid gases would need to be controlled.

Taconite Harbor Energy Center Units 1 and 2. The environmental upgrades at TaconiteHarbor 1 and 2 as part of the AREA Project will meet the mercury emission requirementsof MATS. To control acid gases, some changes to the type of sorbent used for SO2maybe necessary. Improved particulate matter control will need to be installed on each unit.

Taconite Harbor 3. For the Base Case EPA scenario, MP has identified a multi-pollutanttechnology alternative for Taconite Harbor 3. This system consists of a dry scrubber forSO2and acid gases control with activated carbon injection and a fabric filter for mercuryand particulate matter control.

22The finalized MATS rule allows a facility with multiple units in the same emissions subcategory to average thoseemissions across the units to demonstrate compliance with the numerical standards.


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Through the first step of its planning evaluation, MATS compliance, MP concludes that BEC,LEC, and THEC are all impacted by the MATS rule. For each of its impacted coal-fired units,MP then evaluated alternatives for retrofit, refueling, and retirement.

2. Retrofit, Refuel, or RetireStrategist compared the cost of required controls for MATS compliance (Step 1) to retiring themaltogether (Step 2). The retirement analysis accounts for many categories of costs, including:remaining plant asset balance, decommissioning costs, transmission system and socioeconomicimpacts, and replacement generation costs.

For BEC and LEC, Strategist included a natural gas refuel option because these facilities havedirect access to natural gas distribution. THEC, on the other hand, does not have natural gaspipeline access in close proximity; therefore, the refuel option was not considered for THEC.

The results from Step 1 and Step 2 helped MP develop its Preferred Coal Plan and included thefollowing decisions:

Boswell 1 and 2: Continue operations on coal Laskin Energy Center: Refuel to natural gas-fired operation in 2015 Taconite Harbor 1 and 2: Retrofit and continue operations on coal Taconite Harbor 3: Shutdown unit in 2015

Boswell 1 and 2

Before conducting the shutdown evaluation, MP evaluated a natural gas refuel option forBoswell 1 and 2. BEC has natural gas supply infrastructure in place, including appropriatelysized pipe that could accommodate the operation of Boswell 1 and 2 on natural gas.

Boswell 1 and 2 are baseload resources that run a large part of the year, typically at capacityfactors of 70 to 80 percent. Because a constant supply of generation is needed, MPsproduction cost analysis identified units with a low variable cost and high fixed cost (which iscommon for a baseload generation resource, such as coal generation) to be the most appropriate

type of resource to meet its system needs provided by Boswell 1 and 2.

Figure 13 of MPs Petition compares the levelized production cost of Boswell 1 and 2 as a coal-fired resource (blue curve) versus the natural gas refuel option (red curve). Using a six-yearhistorical average of how Boswell 1 and 2 has been dispatched to meet its system needs, MPfinds that continuing Boswell 1 and 2 to run on coal is cost-effective:


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The figure shows that at a capacity factor greater than 40 percent, coal is a lower cost resource atBoswell 1 and 2. MP believes keeping Boswell 1 and 2 as environmentally compliant coal-firedgenerators serving baseload operations is economical, relative to converting the units to naturalgas to meet the MATS requirements.

Applying the Commissions mid-point CO2value of $21.50/ton starting in 2017, MPs analysisshows that continuing coal-fired operations Boswell 1 and 2 is still $70 million less expensivethan refueling the units over the planning period.

MP indicates the option was available for Strategist to retire Boswell 1 and 2, but the retirementoption was not economic under any scenario.

Laskin Energy Center

As with Boswell 1 and 2, MP evaluated refueling LEC to natural gas before considering as ashutdown alternative. LEC has been dispatched with much less frequency than Boswell 1 and 2over the past six years, averaging a range of 50 to 60 percent capacity factors. In MPsproduction cost analysis, the natural gas refuel and environmental retrofit are extremely close.

Figure 14 below identifies that at a 55 percent capacity factor, the two compliance options areessentially equal.


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If the capacity factor at LEC is decreased below its 6-year historical average, the natural gasrefuel option is the lower-cost option. MP projects LEC will face additional economic pressurewith the emissions controls installed because its operating costs will increase. Thus, MP believesit is likely that capacity factors would decrease from its present level in future years, and LECwill operate more like an intermediate or peaking resource than a baseload unit.

Refueling LEC to operate on natural gas is cost-effective with and without the application ofCO2values. MP believes LEC can be optimized as a natural gas peaking unit with wind or the

regional market replacing its energy.

Another benefit MP identified with the LEC refuel is significantly lower emission rates. AsTable 4 below shows, MP projects the conversion to natural gas at LEC will result in an averagereduction in emission rates of 78 percent across all pollutants:

However, converting LEC to natural gas creates system-wide operational changes. The increasein delivered fuel cost at LEC when converted to natural gas is expected to significantly decrease


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the capacity factor at the facility when compared to where it has typically operated on coal. MPexpects LEC will operate like a peaking resource, with an expected capacity factor of 27 percent.

MPs retirement analysis finds that refueling LEC is more cost-effective than retiring it. LEChas an original installed cost of $79 million, and a remaining plant balance of approximately $29

million as of December 31, 2012. While some assets will be retired after the refuel ($5 millionof the $29 million will be retired assets), most are expected to still be used. According to MP:23

The benefit of utilizing a depreciated asset (LEC) in a reduced role is more costeffective than building a new and more efficient natural gas-fired resource.Additional energy can be supplied through a new wind project or the market tooffset the lost energy production at LEC.

Additionally, MP highlights the socioeconomic impacts of LEC retirement. While not includedas a direct cost to the LEC shutdown alternative, MP and the University of Minnesota-Duluthpartnered to evaluate the the socioeconomic impact of a facility closure (Appendix K of MPs

Petition).

According to the socioeconomic impact analysis, significant benefits exist to the communitiesand surrounding region through tax payments, employment and vendor utilization. If MP retiresLEC, 41 jobs would be lost, and the associated support roles throughout the region would createa 2 percent increase in unemployment almost immediately for the area. An average of $10million would be lost in revenue each year for the area economy after the closure.

Taconite Harbor Energy Center

According to MPs MATS compliance screening, Taconite Harbor 1 and 2 require incrementalemissions controls to reduce SO2and particulate matter beyond that which was reduced as partof the Companys AREA project. Taconite Harbor 3 would require a much more substantialinvestment, a $60 million multi-pollutant investment to reduce SO2, mercury, acid gases, andparticular matter to meet MATS requirements.24

MP states that all THEC units operate at capacity factors of 60 to 75 percent on an annual basis.While Taconite Harbor 1 and 2 are well-positioned to meet MATS, Strategist dispatches themless because of the additional operating costs incurred by the requisite sorbent injection. Still,the decreased capacity factor is far less impactful to the system than the LEC refuel, as shown inAppendix I of MPs filing:

23MP Petition, Appendix I, p. 11.24Burns & McDonnell, Hitachi Power Systems of America, and MP developed preliminary designs and costestimates for the installation of the pollution control systems and equipment at Taconite Harbor 3. The componentsof the approximately $60 million project are summarized in Appendix M of MPs resource plan.


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Since no additional capital investment is required at Taconite Harbor 1 and 2 to meet MATS the additional sorbents reflect an operational cost MP concludes that continuing the units tooperate on coal is preferable to retiring them.

MPs analysis indicates that Taconite Harbor 1 and 2 should be considered for shutdown once aCO2value is factored into the model. MP tested mid- ($21/ton in 2017), low- ($9), and high-sensitivity ($34) CO2prices. According to MPs analysis, Taconite Harbor 1 and 2 are notretired in the low sensitivity, but the units are retired in 2017 at the mid- and high-level CO2prices.

MP has identified that the $60 million investment in retrofit technology for Taconite Harbor 3 isnot in the best interest of its customers. MPs retirement analysis shows retrofitting TaconiteHarbor 3 has a cost premium with or without carbon prices. MP believes retiring TaconiteHarbor 3 also avoids the risk of wasted capital investment required for MATS compliance shouldcarbon regulation materialize in the near future.

MP will cease coal operation at Taconite Harbor 3 before the April 2015 MATS compliancedeadline. The physical equipment at the unit will be used for the operations of the facility as awhole. MP will submit an Attachment Y with MISO in 2013 to confirm no additional regionaltransmission considerations will be needed before 2015.

THEC units 1, 2, and 3 have an original installed cost of $147 million, and a remaining plantbalance of approximately $105 million (as of December 31, 2012). Of this total, approximately$15 million in net remaining plant balance for Taconite Harbor 3 are expected to be retired.

3. Identify a Preferred Expansion PlanOnce MP determines the impacts of EPA rules (Step 1) and runs those impacts in Strategist todetermine its preferred coal plan (Step 2), MPs third step is developing its expansion plan. TheCompanys base case expansion plan (i.e. the Preferred Plan) therefore assumes:

BEC will continue to operate on coal throughout the planning period;

LEC will dispatch as a natural-gas fired peaking resource starting in 2015; Taconite Harbor 1 and 2 will operate on coal throughout the planning period, although at

a slightly less capacity factor due to increased operating costs; and

Taconite Harbor 3 will be removed from the system in April 2015.


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Since Taconite Harbor 3 is removed in the base case expansion plan, MP has 75 MW lesscapacity available. Thus, the starting point for the expansion planning (Step 3) is shown inFigure 17 of MPs Petition:

Without Taconite Harbor 3, MPs capacity deficit incrementally increases from approximately50 MW in 2015, up to roughly 100 MW until 2020. At this point, a 250 MW PPA withManitoba Hydro is used to meet MPs capacity and energy deficit starting in 2020.

In the long-term (post-2020), MPs expansion plan demonstrates that a partial ownership share ina larger natural gas combined cycle facility is likely to be the Companys next resource addition,other than renewables and DSM.

4. Scenario AnalysisMP ran four scenarios, each with 22 sensitivities:

Preferred Plan, which retires Taconite Harbor 3 and refuels Laskin; Preferred Coal with THEC Shutdown, which retires Taconite Harbor 1, 2, and 3, and

refuels Laskin;

Small Coal Retrofit, which does not retire any coal, but retrofits to comply with MATS(Mercury and Air Toxics Standards); and

MATS Shutdown, which retires Taconite Harbor 1, 2, and 3 and Laskin Energy Center.Table 11 below shows the Preferred Plan is cost-effective under base case conditions, and in 12of the 22 sensitivities. (The green shaded area represents the plan with the lowest cost.)


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Observations Common to Most Plans:

A 105 MW ND wind unit is added across all plans, reflecting the benefit of the windProduction Tax Credit.

All plans utilize some amount of short term bilateral bridge purchase or market capacitypurchases;

With the exception of the Retrofit Small Coal Plan, the next generation resourcealternative added (other than wind) is a 200 MW share of a combined cycle facility,reflecting the need for additional baseload/intermediate generation.

Observations for Preferred Plan:

Short term bilateral bridge purchases allow MP to delay further investment in newgeneration resources until beyond 2020 when a 200 MW share of a combined cycleresource is added.

The Preferred Plan retires Taconite Harbor 3, but not THEC 1 and 2.Observations for the Preferred Plan with THEC Station Shutdown Plan:

The retirement of Taconite Harbor 1 and 2, in addition to Unit 3, triggers the need for a200 MW share of a combined cycle resource in 2017.

In addition to the short term generation need, an additional combustion turbine is addedin 2024.

Observations for Retrofit Small Coal Plan:

Maintaining operations at existing generation fleet delays need for a new generationresource until 2025.


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With wind additions and the retrofit of MPs small coal units, baseload/intermediategeneration needs are met through the planning period. A simple cycle combustionturbine (a peaking resource) is the next generation resource.

Observations for MATS Shutdown Plan:

300 MW of coal-fired generation is retired in 2015. The bilateral bridge purchase allowsMP to delay investment in a new resource until 2017 when a combined cycle resource isavailable.

2017 is the earliest year that a combined cycle resource is available. If a bilateral bridgepurchase is not available at the capacity and prices assumed, it could have adverse costimpacts to MPs customers in the short term.


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Party Positions

Departments of Commerce

The Department recommends the Commission approve and modify MPs resource plan. DOC

recommends the Commission require MP to:

Add about 200 MW of intermediate capacity in the 2015-2017 time frame, as long as theresource is reasonably priced; and

procure energy savings equal to 1.87 percent of retail sales;The Department also recommends the Commission require MP to retire or sell Taconite Harbor 3by 2015, switch the fuel of Laskin units 1 and 2 to natural gas by 2015, and add 100-200 MW ofwind in 2014-2016. The Commission can decide whether or not findings on these actions arenecessary because they are consistent with MPs proposed action plan.

Modeling Review

DOCs first step in evaluating utilities modeling in resource plans is to replicate how a utilityarrives at its proposed expansion plan. The Department obtained from MP the Companys basecase, the Strategist commands necessary re-create the base case and each of the scenarios andcontingencies explored by the Company.

After replicating MPs model, DOC made changes to the baseline assumptions to establish theDepartments own base case. The Departments base case includes the following changes to

MPs base case: MISOs PRMUCAPaccredited capacity and reserve ratios were implemented; MPs forecast of the cost of NOXemissions credits was added; MPs forecast of the cost of SO2emissions credits was added; DOC deleted MPs expansion wind unit and replaced it with an optional wind unit; DOC added an estimate of transmission costs to the Taconite Harbor 1 and 2 retirement

analysis.

Table 8 of the Departments comments provides the unit additions and retirements in DOCsbase case:


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As shown in Table 8, DOCs base case expansion plan adds 200 MW of wind through 2016 andan intermediate unit in 2015. These additions coincide with retiring Taconite Harbor 3 in 2015.

The Departments base case also retires Taconite Harbor 1 and 2 in 2017. In its place, another100 MW wind unit is added in 2018, and a one-year, 50 MW intermediate PPA is added in 2017.After 2019, no expansion units are selected until 2024.

Trends in the Expansion Plans

Once a base case is created, the Department stresses the base case with contingencies (MP usesthe term sensitivities). DOC ran 31 different contingencies to test how variations in carbonvalues, fuel prices, and the energy and demand forecast changes the expansion plan.

The purpose for running so many contingencies is because a change in one contingency may ormay not affect the selection of resources in Strategists outputs. Therefore, acknowledging a 15-year planning period will inevitably result in unforeseen changes, the Department relies on trendsacross the range of values when making recommendations.

DOC also looks at how sensitive the Strategist model is to changing the assumptions in order tomeasure ratepayers exposure to volatility and risk. For example, since MP presently relies

heavily on coal and minimally on natural gas for its generation, the Department can assesswhether small increases in coal prices pose a greater risk than large increases in natural gasprices.

Because the Department makes recommendations on trends, overall system impacts, and itsjudgment of the best resource plan, its base case results may or may not be DOCs recommendedplan. In this instance, the top ten plans (in terms of those with the least societal costs) have


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similar results in the near-term. Because the Departments long-term results are not asconclusive, DOC does not make any recommendations regarding long-term unit additions.

The same three, 100 MW each, wind additions (shown in Table 8 above) were chosen in all ofthe ten least-cost plans. Moreover, all ten plans selected a 200 MW intermediate unit in 2015.

The only other two expansion units from Table 8 include a 50 MW PPA in 2019 and another 200MW intermediate unit in 2024. The selection of these two units has more mixed results.According to the Strategist results:

The one-year, 50 MW intermediate PPA was selected in 2019 in four plans and notselected in six plans.

The second 200 MW intermediate unit was selected in 2024 in three plans, but in otherplans it was changed to a peaking unit.

The Department makes no recommendations on the 2019 and 2024 unit additions because theresults are inconclusive and the additions are far enough into the future that they can beevaluated in MPs next resource plan. According to the Department:

The initial wind units and the 2015 intermediate unit are consistently selected.Beyond that, additional capacity is typically selected, but Strategist togglesbetween peaking and intermediate units. Given that inconsistent results occurfurther in the future and the fact that these resources are dependent upon thequantity of retirements ordered by the Commission, these issues can be furtherevaluated in MPs next IRP.

The Department recommends that the Commission require MP to obtain the intermediatecapacity (and associated energy) in 2015. The Department notes that MP could pursue thisaddition by constructing the resource itself, sharing in the ownership of the resource, or byprocuring the resource through bilateral contracts, whichever option is most cost-effective.

Scenario Analysis

Including the base case, the Department ran a total of 15 different scenarios. A scenario isdifferent from a contingency because a scenario can restrict Strategist from choosing a particularresource, force Strategist to consider a particular resource, or force certain amounts of resources

(e.g. variations of DSM). The contingencies test how different circumstances affect eachscenario.

For MPs resource plan, the Department ran scenarios evaluating three levels of marketavailability: Full Market (MPs design), Limited Market (less energy, no capacity), and NoMarket. Additional scenarios include various levels market reliance with and without CO2costs.


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As MP relies on the market less, and as the scenarios change from the Full Market to LimitedMarket to No Market, the Departments modeling results show the following trends:

1. More wind units are added as less energy is drawn from the market;2.

The number of intermediate units added increases;

3. There are almost no contingencies that select peaking units when the spot market isturned off. On the other hand, virtually every contingency selects peaking units when thefull spot market is available.

The availability of the wholesale market also has implications for the retirement analysis. Table10 from the Departments comment shows the expansion plans under the three marketavailability scenarios, with and without CO2costs:

The Limited Market, With CO2Costs scenario in Table 10 mirrors the Departments base caseexpansion plan. In this scenario, two intermediate natural gas units and 300 MW of wind areadded. Taconite Harbor 3 is retired in 2015, and Taconite Harbor 1 and 2 are retired in 2017.Without CO2costs, only Taconite Harbor 3 is retired in the Limited Market scenario.

In the Full Market, Without CO2Costs scenario in Table 10 (the box in the upper right corner),Strategist is allowed to consider the wholesale market to an unlimited extent. The Departmentused MPs assumptions for wholesale prices. Under these conditions, none of the TaconiteHarbor units are retired, and instead Laskin Energy Center is retired because spot market energyand capacity is preferable to refueling Laskin with natural gas, in terms of cost.


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The Department believes MPs Full Market availability is unreasonable and could lead to MPscustomers facing significantly higher costs than MP assumes in its analysis. There could also bereliability issues if the spot market capacity selected by the model is simply not available.

The Department concludes that some form of future CO2cost needs to be considered by the

Commission when it deliberates about what resource plan to approve.

If the Commission does not choose to consider restrictions on the wholesale market or CO2costs,the Departments modeling suggests that closing Taconite Harbor 3 is not cost-effective.Moreover, refueling Laskin Energy Center to operate on natural gas is also not cost-effective ifCO2costs are not considered, and MPs modeling can choose the option to rely on the wholesalemarket instead.

Retirement Analysis

It is important to note that the Departments base case expansion plan retires Taconite Harbor 1and 2, but the Department does not recommend this action to the Commission at this time. Table10 on the previous page shows that retirement of all three units at Taconite Harbor is generallythe least cost plan in scenarios that include the mid-point of the Commissions CO2costs.

However, the matter at hand is not whether two plans are close in cost, but which actionsrepresent the best resource plan. For example, the Department does not believe MP should relyexcessively on the MISO energy market, especially at a time when wholesale energy is expectedto become more scarce as a result of regional retirements.

DOC recommends a plan that retires only Taconite Harbor unit 3 in part because the Departmentfocused upon the low CO

2cost contingencies and the scenarios with limited reliance on the

wholesale market.

In the ten least cost plans the Department modeled, the following trends exist for retirementdates:

Boswell units 1 and 2 were not selected for retirement in any of the ten plans; Taconite Harbor unit 3 was retired in 2015 in eight of the plans and not retired in two

plans;

Taconite Harbor units 1 and 2 were retired in 2016-2017 in six plans, retired in 2020 inthree plans, and not retired once; and

Laskin units 1 and 2 were retired in 2024 in three plans, before 2020 in one plan, and notretired in six plans.

Rapids Energy Center


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The Department ran two scenarios (one with CO2costs, one without) that shut down Rapids totest its cost effectiveness. The Departments modeling indicates retiring Rapids decreases MPssystem cost by about $5 million when CO2costs are included and by about $11.7 million whenCO2costs are not included. DOCs results are highly sensitive to several contingencies, although

retiring Rapids is economic in several instances.

MP did not include the cost to shut down the Rapids unit. The Department recommended in theirinitial comments that MP run a Rapids retirement scenario, but MP responded:

Minnesota Power currently has before the Commission a Petition to request thatRapids be moved to the Companys regulated rate base in order to providevaluable and flexible renewable biomass energy to its customers.

Because several aspects of Rapids and Blandins operations are interdependent, ashutdown evaluation of Rapids would require that the Blandin paper mill also be

shut down as it requires steam from Rapids to operate. The implications of ashutdown of this magnitude in Minnesota would bring significant job losses andcosts that have not been contemplated to date.

Minnesota Power does not believe it is appropriate or advisable to modelremoving Rapids from its system.

The Department recommends that MP perform the analysis such that the Commission has theproper record to base a decision upon whether to keep Rapids in operation or retire it altogether.

DSM Scenarios

The Department modeled additional conservation scenarios incremental to that which isembedded in MPs forecast. The Department generally assumes that the amount of energysavings built into the forecast is an average of the last five years of energy savings.

Table 12 below shows the energy savings that MP achieved from 2007 to 2011.


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Staff circled in red the amount of energy savings which DOC assumes is included in the forecast.From 2007-2011, MP saved an average of approximately 55.1 million kWh per year, whichrepresents 1.67 percent of retail sales net CIP opt-out customers. Five-year savings for MPstotal energy sales to retail customers (i.e., including CIP opt-out customers) is 0.65 percent.

DOC Information Request #16 asked MP to conduct two additional DSM sensitivities assumingachievement of energy savings equal to 1.7 percent and 2.0 percent of retail sales (excluding opt-out customers). MP responded by modeling the impact of increasing energy conservation beyondamounts already embedded in its forecast embedded amounts by 0.2 percent and 0.5 percent.According to the Company:

Minnesota Power ran the two requested additional sensitivities in the Strategistmodel with conservation savings goal increased to 1.7 percent and 2.0 percent.With 1.5 percent conservation savings already built into the energy sales forecast,the incremental increase in conservation of 0.2 percent and 0.5 percent was

modeled as a new conservation program in the Strategist model for the PreferredPlan and the three alternative swim lanes.

The cost to implement conservation programs that would achieve an incrementalincrease in conservation of 0.2 percent and 0.5 percent was assumed to be zero forthis sensitivity, giving the programs the most benefit possible. With no costattributed to the incremental increase in conservation, the change in power supplycost with the incremental increase in conservation represents the avoided costthese programs could bring to the customer.

MP calculated the benefit from the incremental conservation would be in the form of decreasedpower supply costs. However, MP did not calculate any program costs to determine whetherthese DSM scenarios would be cost-effective.

Because MP did not include any costs for the incremental conservation achievement, theDepartment assumed the potential CIP budget for the incremental conservation achievement asthe cost for conservation. This cost for conservation was compared against the decreased powersupply costs MP estimated.

The Departments analysis indicates that an additional 0.2 percent of energy savings may becost-effective. Currently, the Commission-approved Shared Savings DSM financial incentivemechanism encourages MP to maximize its savings, and the Company is on a path to achieve thehigher energy savings represented by the incremental 0.2 percent energy savings scenario.

The 0.2 percent additional DSM does not change the Departments preferred expansion path,(i.e., the supply-side resources needed do not change). Thus, the Commission could approve thehigher energy savings amount without concern that MP could face a reliability problem if theCompany did not achieve the energy savings over the long term.


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Currently, the Department estimates that energy savings equal to 1.67 percent of retail sales isembedded in MPs forecast. The additional 0.2 percent of retail sales to non-opt-out customersresults in energy savings of 1.87 percent (1.67 percent of embedded conservation plus 0.2percent of incremental energy savings). The Department recommends that the Commissionapprove an IRP energy savings goal of 1.87 percent of retail sales.

Environmental Intervenors

The Environmental Intervenors (EIs) consist of the Izaak Walton League, Fresh Energy, theSierra Club, and the Minnesota Center for Environmental Advocacy.

The EIs comments address two main categories of MPs resource plan, the CompanysStrategist modeling and its energy efficiency potential. The two categories are separatelyaddressed because energy efficiencys relationship to the Strategist model exists only to theextent that it is embedded in MPs load forecast. However, the EIs urge the Commission torequire MP to evaluate additional energy savings, especially for the vast majority of MPs loadwhich is CIP-exempt.

1. Modeling commentsA. The Commission should modify MPs expansion plan to initiate the process of

retiring all three coal units at Taconite Harbor by 2017.

The Departments modeling shows that retiring Taconite Harbor 1 and 2 is cost-effective in mostcontingencies which consider CO2costs. The EIs recommend the Commission consider theseresults when approving the appropriate resource plan.

The EIs believe there is significant CO2regulatory risk exposed to MPs customers, andretirement of its aging small coal units reflects the least risky course of action.

B. MP overstates the performance of its existing coal fleetThe EIs observe that MPs modeling demonstrates minimal cost differences for its preferred coalplan versus non-coal alternatives. This result is in spite of MPs overstated performance of itsexisting coal fleet.

As shown on page 28 of this document (and discussed in Appendix I of MPs Petition), MPexpects little change in the capacity factor of Taconite Harbor 1 and 2 as a result of MATS

compliance. MPs base case assumes the units will be dispatched at a 59 percent capacity factor,and once MATS compliant, Strategist dispatches the unit at a 57 percent capacity factor.Boswell 1 and 2 have an expected dispatch range of 70-80 percent over the planning period.

The EIs contend that since THEC 1 and 2 and Boswell 1 and 2 are over 50 years old, it isunreasonable for MP to assume historical operational performance during the planning period.To the contrary, MPs older coal units will incur higher operating costs and decliningperformance over time. Therefore, the EIs do not believe Strategist can provide an optimal


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resource plan because it dispatches MPs existing coal units far more than which can reasonablybe expected.

Even with MPs model set up as it is, retiring Taconite Harbor 1 and 2 appears to be the leastcost plan when CO2is considered. In addition to the CO2regulatory risk, MPs modeling

overstates the benefit and understates the cost of Taconite Harbor 1 and 2. Thus, the EIs believethe Commission should pursue retirement of these units by 2017.

Likewise, the assumed dispatch cost of Boswell 1 and 2 does fully capture its actual variableoperation and maintenance costs. This causes Boswell 1 and 2 to be dispatched more frequently,thereby improving its relative benefit to other alternatives, such as a natural gas combined cycleoption. Such modeling deficiencies restrict Strategist from selecting an optimal resource plan.The EIs disagree that MP has appropriately considered a natural gas alternative at BEC andbelieve the Commission should consider refueling Boswell 1 and 2 on natural gas as a cost-effective option.

C.

MPs resource plan is incomplete

MPs modeling assumes a future Commission decision approving the Companys Boswell 4Retrofit Petition and does not reconcile differing IRP assumptions with modeling in the Boswell4 docket.

Since the Commission has not decided on MPs proposal to retrofit the unit in Docket 12-920,the Company should not assume that Boswell 4 will be fully retrofitted as proposed and continueto operate on coal through 2034. Similarly, the modeling from the Boswell 4 Retrofit Petitionassumes that Laskin 1 & 2 and Taconite Harbor 3 continue to operate on coal through 2034.Therefore, MPs analysis is not complete and does not evaluate MPs system under retirement ofmultiple units, including Boswell 4. Consequently, the Commission does not have a completepicture of the options available.

Additionally, MPs Boswell 4 Retrofit Project does not include a least cost plan that meets 50percent and 75 percent of thepower generated by Boswell 4 through energy conservation andrenewable energy resources.25

2. MP should capture higher levels of energy efficiencyThe EIs recommend the Commission modify MPs action plan to incorporate more cost-effectiveenergy conservation than the proposed savings in MPs plan.

Overall, the EIs do not believe MPs resource plan reflects the energy policy of the state ofMi

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