Before the Minnesota Public Utilities Commission. State of Minnesota

Transcription

1 PUBLIC DOCUMENT TRADE SECRET DATA EXCISED Direct Testimony and Schedules Joshua J. Skelton Before the Minnesota Public Utilities Commission State of Minnesota In the Matter of the Application of Minnesota Power for Authority to Increase Rates for Electric Utility Service in Minnesota Exhibit GENERATION November, 01

2 Table of Contents Page I. INTRODUCTION AND QUALIFICATIONS... 1 II. OVERVIEW AND ENERGYFORWARD... III. FOSSIL GENERATION RESOURCES... 1 A. Boswell Energy Center... 1 B. Taconite Harbor Energy Center... 0 C. Laskin Energy Center... IV. RENEWABLE GENERATION... A. Hydro Resources... B. Biomass Resources Hibbard Renewable Energy Center.... Cloquet Energy Center.... Rapids Energy Center... C. Wind Generation... 1 V. GENERATION O&M COSTS... VI. COST CONTAINMENT EFFORTS... A. Small Coal Fleet Transition... B. Human Performance and Process Improvements... 0 C. Emission Reduction Reagents and Chemicals... D. Other Cost Savings... 0 VII. NOX ALLOWANCE SALES... 1 VIII. CONCLUSION... i

3 I. INTRODUCTION AND QUALIFICATIONS Q. Please state your name and business address. A. My name is Joshua J. Skelton and my business address is 0 West Superior Street, Duluth, Minnesota 0. Q. By whom are you employed and in what position? A. I am employed by ALLETE, Inc., doing business as Minnesota Power ( Minnesota Power or the Company ). My current position is Vice President Generation Operations for Minnesota Power. Q. Please summarize your qualifications and experience. A. I hold a Bachelor of Science degree in chemical engineering from Michigan Technological University in Houghton, Michigan, and a Master of Science degree in engineering management from the University of Minnesota Duluth. I am a licensed professional engineer in the State of Minnesota. I joined Minnesota Power at the Laskin Energy Center as an engineering intern in 1, and a full-time employee and engineer in 001. In 00, I was promoted to the Maintenance Superintendent role. I was named Renewable Operations Business Manager at the Rapids Energy Center in 00, working directly with our customer, UPM Blandin. In 00, I was promoted to Thermal Business Operations Manager at the Boswell Energy Center. In 01, I was promoted to General Manager of Thermal Operations, and in August of 01, I was promoted to Vice President Generation Operations for Minnesota Power. As the Vice President of Generation Operations, I am responsible for all of the generating areas of Minnesota Power including wind operations, thermal operations, hydro operations, co-generation operations, and various support services. These areas include approximately employees, with approximately 0 of those employees as members of International Brotherhood of Electric Workers ( IBEW ) Local 1. 1

4 Q. What is the purpose of your testimony? A. The purpose of my testimony is to provide an overview of our generating fleet and the changes in operation, mission, generation additions, and investments in the fleet since the last Minnesota Power rate filing in 0. Our generation fleet has seen significant transition as a part of the EnergyForward strategy, as well as improvements to maintain the reliability of our units. In addition, I will highlight some of our 01 capital projects at our generation stations, outline our 01 test year operations and maintenance ( O&M ) budget, and describe the cost control measures that we have put in place since our last rate proceeding. Q. Are you sponsoring any exhibits in this proceeding? A. Yes. I am sponsoring the following exhibits: Exhibit (JJS), Schedule 1 Generation s 01 Capital Additions. Exhibit (JJS), Schedule Summary of Generation Cost Control Measures. II. OVERVIEW AND ENERGYFORWARD Q. Please describe Minnesota Power s generation portfolio. A. Minnesota Power s generation facilities have a net maximum capability of nearly,000 megawatts ( MW ) and rely on a variety of fuel sources including coal, natural gas, biomass, hydro, and wind to generate power for our approximately 1,000 residential and commercial customers, 1 municipalities, and some of the nation s largest industrial customers. Figure 1 below is a geographical representation of our generating portfolio, and Table 1 below summarizes the details of Minnesota Power s generation resources and provides each facility s net capability.

5 Figure 1

6 Table 1 Minnesota Power Regulated Power Supply Unit No. Year Installed Net Capability (MW) Coal-fired Generation Boswell Energy Center in Cohasset, MN (a) Laskin Energy Center in Hoyt Lakes, MN 1 & 1 (b) Taconite Harbor Energy Center in Schroeder, MN (b) Total Coal-fired 1 Biomass/Coal/Natural Gas Hibbard Renewable Energy Center in Duluth, MN & 1, Laskin Energy Center in Hoyt Lakes, MN 1 & 1 1 Total Biomass/Coal Natural Gas 1 Hydro (c) Group consisting of ten stations in MN Multiple Multiple Wind (d) Taconite Ridge Energy Center in Mt. Iron, MN Multiple 00 Bison Wind Energy Center in Oliver and Morton Counties, ND Multiple 0-01 Total Wind Total Company Generation 1,1 (a) BEC net capability shown above reflects Minnesota Power s ownership percentage of 0 percent. WPPI Energy owns 0 percent of BEC. (b) Laskin Energy Center was converted from coal to natural gas in June 01 and Taconite Harbor Unit was retired in May 01. Future plans for Taconite Harbor are included in Minnesota Power s EnergyForward plan, which includes economic idling of Taconite Harbor Unit 1 and in the fall of 01 and the ceasing of coal-fired operation at Taconite Harbor in 00. (c) Hydro consists of ten stations with generating units and a total nameplate capacity of MW. Thomson returned to full production in the fourth quarter of 01. Our hydro stations are Prairie

7 1 River, Grand Rapids (non-regulated), Pillager, Sylvan, Little Falls, Blanchard, Knife Falls, Scanlon, Winton, Thomson, and Fond du Lac. (d) Taconite Ridge consists of wind turbine generators with a total nameplate capacity of MW. The Bison Wind Energy Center consists of 1 wind turbine generator units with a total nameplate capacity of MW. Minnesota Power produces the majority of its energy from coal-fired generation units, supplemented by a long-term purchase from Square Butte s Milton R. Young lignite coal-generating station in North Dakota, Next Era Energy s wind farm in Oliver County, North Dakota, and hydroelectric power from Manitoba Hydro. This is further explained in the Company s 01 Integrated Resource Plan ( 01 IRP ) filed in Docket No. E01/RP Q. How is Minnesota Power s generation mix changing? A. Minnesota Power was founded as a hydroelectric utility in. Over the years, the Company grew to serve its unique customer mix with predominantly coal energy. We are now in the process of rebalancing our generation mix and bringing more renewable power to customers, reducing our dependence on fossil fuel, and lowering carbon dioxide emissions through a resource strategy called EnergyForward. The execution of the EnergyForward strategy will result in a power supply that is more diverse, while still maintaining low-cost, reliable energy for our customers. The goal of EnergyForward is to bring Minnesota Power s energy mix to one-third coal, onethird natural gas, and one-third renewables. 0 Figure below shows how our generation mix has changed from 00 to 01, moving from percent coal generation in 00 to percent in 01. The percentages shown in Figure include power purchased through long-term Power Purchase Agreements ( PPAs ) and short-term market purchases in the Midcontinent Independent System Operator, Inc. ( MISO ) markets and from other power supplies as highlighted above. 1

8 Figure Q. Why is this the right generation mix to serve Minnesota Power s customers? A. Minnesota Power s retail customer mix is unique in that energy sales to large industrial customers, primarily in the taconite mining, iron concentrate, paper, pulp, refining, and pipeline industries, make up approximately percent of the Company s total retail energy sales. Many of these industrial customers operate /, which means our customers power usage is relatively constant. As a result, Minnesota Power s generation mix must be appropriately balanced between necessary baseload generation to serve these high load factor customers and intermittent renewable generation to reduce carbon emissions. Q. Can you provide some examples of fossil fuel-based generation changes that have been implemented as part of EnergyForward? A. Yes. For example, in February 01, the last trainload of coal was unloaded at the Laskin Energy Center ( Laskin ) and the plant was subsequently converted to use cleaner-burning natural gas as an environmental improvement project. In addition, in June 01, Minnesota Power s coal-fired Taconite Harbor Energy Center Unit ( THEC ) ceased generation after years. As a result of these changes, the percentage of coal-fired generation on the Minnesota Power system has declined from about percent in 00 to less than 0 percent in 01 as shown in Figure.

9 Additionally, major emission reduction projects at Boswell Energy Center Unit ( BEC ) and Boswell Energy Center Unit ( BEC ), the two largest coal generators remaining on the Minnesota Power system, are contributing to the Company s significantly lower emission profile. A major environmental retrofit was completed at BEC in 00 and substantially completed at BEC in December 01. Both retrofits reduced mercury, particulate matter ( PM ), acid gases, and sulfur dioxide ( SO ) emissions and ensured continued compliance with existing emissions standards. Recently, on October 1, 01, Minnesota Power announced its plan to retire Boswell Energy Center Units 1 and ( BEC1& ) by the end of 01. This retirement announcement is discussed in more detail below. Q. Has the Company increased renewable wind generation as part of EnergyForward? A. Yes. Over the past decade, the Company has undertaken a systematic effort to increase its deployment of renewable energy. In 00 and 00, Minnesota Power began purchasing, through a PPA, the entire output of the Oliver 1 and Oliver wind farms (approximately 0 MW combined) built in North Dakota by NextEra Energy. In 00, Minnesota Power constructed and began operation of the MW Taconite Ridge Energy Center ( Taconite Ridge ), which was the first commercial wind generating station in northern Minnesota. Between 0 and 01, Minnesota Power constructed and began operation of the four Bison Wind Energy Center ( Bison ) phases in North Dakota. Bison is now the largest wind farm in North Dakota with just under 00 MW of generation. Combined, these wind projects added more than 00 MW of renewable generation to the Company s energy portfolio. Q. Have there been any changes to the Company s hydro facilities? A. Yes, primarily through the repair and refurbishment of several existing facilities. Minnesota Power is the state s largest producer of hydro power with federally-

10 licensed generating facilities capable of approximately MW of carbon-free energy, including the.1 MW non-regulated Grand Rapids hydro station operated under contract to UPM Blandin. In recent years, we have focused our efforts on repairing, maintaining, and improving the efficiency of these existing hydro facilities. Our most extensive project was at the Thomson Hydroelectric Station ( Thomson ) on the St. Louis River. In late 01, Thomson was returned to service months after a devastating flood breached the forebay canal and flooded the -year-old renewable energy facility, knocking it offline. The station was operating at full capability by the end of 01 after necessary repairs were completed. The Company also completed significant repair and refurbishment investments at its other hydro facilities, including work at Fond du Lac, Little Falls, Winton, Prairie River, and Birch Lake in the 0 to 01 timeframe. Q. Has the Company made any investments in solar generation as part of EnergyForward? A. Yes. Since the Solar Energy Standard was passed in 01 by the Minnesota legislature, Minnesota Power has made the necessary investments to ensure compliance with this standard. One such investment is the Camp Ripley Solar project near Little Falls, Minnesota. The MW array will be the largest solar energy installation on military property in the state and the largest at any National Guard base in the country. This project is expected to be completed in 01, despite delays associated with a tornado that struck the project on September, 01. Q. Do you expect additional changes to Minnesota Power s generation resources over the next several years? A. Yes. Over the next several years, we anticipate that Minnesota Power will continue to preserve key competitive baseload generating resources while further reducing emissions at these units and maintaining compliance with current and future emissions standards and regulations. We will also work to reduce reliance on coal-

11 fired generation while adding more renewable energy resources. These anticipated changes, as well as additional details about the changes that we have already implemented at our generation resources are discussed briefly below and in greater detail in Sections III and IV of my testimony. Q. What types of generation investments has the Company been making as part of the EnergyForward strategy? A. The Company has been making investments totaling nearly $1. billion in its generation fleet between 0 and 01 as part of the EnergyForward strategy. These investments have been focused on making our fleet more flexible, more diverse, and less carbon intense while maintaining the reliability of our generation units. Capital spending over this period can generally be categorized into three major areas: (1) base capital investments, () environmental improvement projects, and () renewable resource additions/refurbishments. Q. Please describe these three general categories of the generation capital investments. A. Minnesota Power s capital investments include: Base Capital Investments: These projects can be described broadly as projects that support the on-going function of our generating facilities as they are originally designed. Many of these projects are routine investments that replace worn or aging parts, improve the reliability of existing assets, or maintain the efficiency or effectiveness of the generation units. Typically, these investments are made during planned maintenance outage cycles or are in response to failed equipment components. This category also includes safety improvements. The costs for these projects are typically not recovered under a rider and are therefore designated as base capital investments. Environmental Improvement Projects: These projects are typically large investments with the intent to install systems or processes to support ongoing compliance with federal and state regulatory emissions requirements and

12 standards. These types of investments include additions or modifications to pollution controls, deployment of alternative technologies, or refueling a boiler. These projects are typically more complex than a base project and require additional planning to execute successfully. Also, in most cases, they are multiyear projects. Renewable Resource Additions/Refurbishments: These projects are typically capital projects that support the construction of new renewable generating assets (i.e., Bison and Taconite Ridge) or the modification of existing assets (i.e., Thomson and Hibbard) to meet renewable mandates or organizational goals. Figure below shows Generation s capital expenditures from 0 to 01 broken down by those investments that were eligible for inclusion in a rider versus those that were not rider eligible. Figure 1 1

13 As shown in Figure, Minnesota Power made significant investments in its generation resources in 01 and 01. These investments included Bison, BEC retrofit, and the Thomson restoration that were mentioned above. Since 01, Generation s capital expenditures have decreased markedly and we anticipate 01 capital investments totaling $. million and 01 investments of $0. million. Q. What are Generation s planned capital investments for 01? A. Generation s capital investments for 01 are planned to be $0. million, including capital expenditures and decommissioning costs. While we continue to move our resource portfolio to one-third gas, one-third coal, and one-third renewable, we will also need to maintain the assets currently serving our customers. Our planned capital investments for 01 reflect a movement from large investments in environmental and renewable projects to an optimize, maintain, and improve approach. The $0. million of planned capital investments can generally be characterized in the three categories: (1) $ million of base capital expenditures; () $. million for decommissioning expense related to the Coal Combustion Residuals ( CCR ) regulations ( Environmental Improvement Projects ), and () $. million in capital expenditures for remaining rider projects at Thomson ( Renewable Refurbishments ). Q. What are Generation s capital additions for 01? A. Generation s planned capital additions for 01 are $. million. Exhibit (JJS), Schedule 1 to my Direct Testimony provides information regarding Generation s 01 capital additions, listed by each capital project. In my next section of testimony, I will describe the key capital investments that Generation has undertaken since Minnesota Power s last rate proceeding, as well as Generation s planned capital additions for 01. Q. Please describe the process Minnesota Power uses to determine its annual capital investment for its generation fleet.

14 A. The annual budget for capital investments in the generating fleet is developed based on a balance between ALLETE s overall finances and the identified business needs in Generation to maintain a safe, reliable, flexible, and low-cost generation fleet. The budget process is explained further in the Direct Testimony of Company witness Mr. Steven Morris. Generation s annual capital budget reflects prudent utility expenditures planned with the intent of maintaining safe, competitive, and reliable energy sources for our customers and the region. Each and every capital investment in our Generation capital budget is carefully reviewed for its business need and intended impact. Longterm investment plans are considered carefully in our IRP for each facility. We also maintain a five-year and ten-year capital plan. To be included in our long-term plans, several factors are considered and reviewed with the Generation Leadership team and engineering/project teams as projects are prioritized. These factors include safety, environmental and regulatory compliance, efficiency, impacts to reliability, and timing with planned outage cycles. The generation component of the overall Minnesota Power capital spend is then reviewed by the senior management and ultimately approved as a part of the annual budgets by the ALLETE Board of Directors. III. FOSSIL GENERATION RESOURCES A. Boswell Energy Center Q. Describe the Boswell Energy Center. A. The Boswell Energy Center, located in Cohasset, Minnesota, is Minnesota Power s largest thermal facility. The Boswell Energy Center includes four units with a combined capability of nearly 1,000 MW that have historically provided approximately half the energy needs of Minnesota Power s customers. Major environmental and efficiency improvements have been made at the facility in recent years, with the most recent investment being the environmental retrofit of the BEC that was substantially completed in December 01. 1

15 Q. Please provide additional information regarding BEC and its contribution to Minnesota Power s generation portfolio. A. BEC was placed into service in and at that time had MW of net nameplate capacity, making it Minnesota Power s largest baseload generator. Subsequent turbine efficiency investments in 0 expanded the net nameplate capacity of this unit to MW. WPPI Energy (formerly Wisconsin Public Power, Inc.) has a 0 percent ( MW) ownership interest in BEC. BEC was originally constructed with first generation low oxides of nitrogen burners ( LNB ) and close-coupled overfire air, and a then-state-of-art wet spray tower absorber/particulate removal system. Q. What environmental improvements have been made to BEC? A. On August 1, 01, Minnesota Power submitted its mercury emissions reduction plan for BEC (Docket No. E-01/M-1-0). On November, 01, the Commission issued an Order approving the plan and associated cost recovery in the BEC Emission Reduction Rider ( BEC Rider ). As explained in the Company s BEC Rider petition, the proposed environmental upgrades involved replacing the BEC existing wet scrubber and PM control technology with a semi-dry system that uses less water and removes additional sulfur oxides and acid gases, installing a powdered activated-carbon injection system to capture flue gas mercury, and adding a fabric filter to further control particulates. In addition, as discussed on page of the August 1, 01, BEC Mercury Emission Reduction Plan petition (Docket No. E01-M-1-0), the proposed new circulating dry scrubber ( CDS ) technology has substantially less equipment than the existing wet system so equal or lower electrical loads than the current station service requirements were anticipated, likely increasing unit efficiency post-project. As anticipated, the retrofit is providing the benefit of a nominally lower station service draw by approximately 1. MW, overall making it slightly more energy efficient. These improvements were needed to comply with both the Minnesota Mercury Reduction Act ( MERA ) requirements and the mercury, PM, and hydrochloric acid emissions standards mandated by 1

16 Mercury and Air Toxics Standards ( MATS ) issued by the U.S. Environmental Protection Agency ( EPA ). Q. Are the proposed emissions reduction upgrades at BEC complete? A. Minnesota Power has been at work on these improvements since 01 and the majority of these capital improvements were placed in-service in 01. We anticipate that all remaining site finishing work will be finalized at the end of 01. However, components of the Boswell Ash Management project will be incrementally completed and placed in-service during the coming years, concluding in 00. Q. What portions of the Boswell Ash Management project are yet to be complete? A. The portions of the Boswell Ash Management project that are still being constructed include the ash disposal facilities, construction of additional ash haul roads, the addition of heavy equipment dozers, trailers, and dust mitigation water trucks that are required as a complement to the emissions reduction upgrades that will be completed at BEC. Q. How is Minnesota Power s BEC Rider being handled in this rate case? A. As explained in greater detail in the Direct Testimony of Company witness Mr. Herbert Minke, the Company s proposal is to roll a portion of the BEC retrofit project into base rates but to continue recovery of the Boswell Ash Management project in the BEC Rider as this project is yet to be completed. Q. Have you quantified the emissions reductions at BEC as a result of these emissions improvements? A. Yes. The Minnesota Power fleet emissions reductions from 00 to 01 are shown in Figures,, and below. Specifically, these figures show the reductions in the criteria pollutants of mercury (Figure ), SO (Figure ), and PM (Figure ). These emissions reductions are demonstrated through June of 01 and estimated for the remainder of the year. The impact of the BEC retrofit project can be seen in the 1

17 dramatic reductions shown between 01 and 01. It should also be noted that the BEC retrofit project met and exceeded all of the performance guarantees for the installed systems. These recent upgrades, together with other investments since 00, have reduced our generation fleet s overall emissions by percent. Figure 1

18 Figure Figure 1

19 Q. What is the estimated final cost for these environmental upgrades at BEC? A. We anticipate that the total cost for these environmental upgrades will be approximately $00 million, with Minnesota Power s share at approximately $ million. Minnesota Power s initial petition to the Commission estimated the Company s share of the capital cost for these upgrades at $. million. Q. Did Minnesota Power provide updates to the Commission regarding the cost savings achieved in implementing these environmental upgrades? A. Yes. Minnesota Power provided updates to the Commission regarding these cost savings in its December 1, 01, Petition for Approval of a Cost Recovery Rider for Boswell (Docket No. E01/M-1-), its July, 01, Notice of Resolution Reached with the EPA (Docket No. E01/M-1-0), and its November, 01, Petition for Approval of a Cost Recovery Rider for Boswell (Docket No. E01/M- 1-0). As explained in these filings, these cost savings were a result of contract savings achieved through use of a competitive bidding process for both labor and materials. Additionally, during the detailed design phase, Minnesota Power was able to reduce the impact to wetlands and construct the improvements on a smaller footprint that was closer to the existing boiler house, which reduced the amount of ductwork and distance for large power runs, as well as created additional engineering opportunities to decrease costs. During the construction seasons of this project, the weather in northern Minnesota was also favorable which decreased the number of days when work could not be completed due to adverse weather conditions. The combination of all of these factors resulted in the ability to implement these upgrades both on time and under budget. Q. Are there any other capital additions planned for BEC in 01? A. Yes. The 01 capital additions for BEC are provided in Exhibit (JJS), Schedule 1 to my Direct Testimony and are aligned with routine investment aimed at 1

20 supporting the designed performance of the assets, replacing worn parts, maintaining efficiencies and environmental compliance, and supporting continued reliability to cost effectively serve a baseload resource for our customers. In addition, our capital investments include start-up, performance, and compliance testing for our new emissions control equipment at BEC and any modifications to that equipment to ensure reliability and efficiency of this equipment. For instance, in 01, we propose to inspect, repair, and rebuild the existing gear box as necessary for the BEC G pulverizer. The scope of this project is to assess and repair the gear box s internal bearings, gearing, and shaft for defects or damage and repair with like-in-kind components. The reliable function of this asset is necessary to maintain compliance with emission regulations as it plays a critical role in a clean and efficient combustion process. In total, capital expenditures for BEC are expected to be $. million in 01. Q. What is the status of BEC? A. BEC typically operates at a high load factor, providing baseload energy to the Minnesota Power system. In 00, Minnesota Power replaced the original turbine with a more efficient design that has nameplate capacity of MW of net output without increasing the steam flow or consuming additional fuel. This was an increase from the original design of approximately MW. In combination with the turbine efficiency upgrade, a major environmental upgrade was also completed at BEC in 00 to meet state and federal environmental requirements. Q. Are there any capital additions planned for BEC in 01? A. Yes. We are planning several capital projects in 01 at BEC. These projects are routine investments aimed at supporting the designed performance of the assets, replacing worn parts, maintaining efficiencies and environmental compliance, and supporting continued reliability of this important baseload resource for our customers. For instance, in 01 we will undertake an overhaul of the BEC pulverizers. These 1

21 pulverizers are exposed to considerable erosion and by replacing the internal components to original size and improving the wear properties of these components will allow BEC to operate with proper mill fineness, fuel balance, and improve the efficiency of the combustion process. Q. Please describe BEC1& and their contributions to Minnesota Power s generation portfolio. A. BEC1& operate at a high load factor, providing both baseload energy and ancillary services to the market. BEC1& each operate with a net capability of MW. The units provide station service to operate auxiliary equipment, as well as maintain a steady and reliable steam supply to heat the entire Boswell Energy Center during the winter months. BEC1& also house the water intake for the Boswell Energy Center, as well as the boiler water treatment systems that feed all Boswell units. Q. What are the Company s future plans for BEC1&? A. As noted above, Minnesota Power recently announced plans to retire BEC1& in 01. Q. Why did the Company decide to retire BEC1&? A. The retirement of BEC1& is part of our strategy to reduce small coal-fired generation on our system. In addition, under the terms of an agreement between Minnesota Power and the EPA, BEC1& will require additional SO emissions controls if they continue to operate as coal-fired units past 01. Options considered for BEC1& included retrofitting the units to reduce SO through use of the BEC scrubber, refueling the boilers to natural gas, or retirement. Considering in part that the Commission required the shutdown of these units by no later than 0 as part of its decision on the 01 IRP, the Company determined that the most cost-effective option for our customers was retirement of BEC1& by December 1, 01. 1

22 The Company s proposed plan for depreciation for Boswell, including BEC1&, is discussed in the Direct Testimony of Company witness Mr. Herbert Minke. Q. Are there any capital additions planned for BEC1& in 01? A. Yes. While we are planning to retire these units at the end of 01, they will continue to operate through 01 and we must make certain necessary investments to ensure they are capable of continued operation. For instance, in 01, we plan to replace all bags in eight compartments in the Unit 1 baghouse that have reached their end-of-life and require replacement to maintain permit compliance until retirement in 01. B. Taconite Harbor Energy Center Q. Please describe the Taconite Harbor Energy Center ( THEC ). A. THEC is located near Schroeder, Minnesota, on the North Shore of Lake Superior with an originally-designed generation capability of MW. THEC is comprised of three units Unit 1 ( THEC1 ), Unit ( THEC ), and THEC that were purchased from bankrupt LTV Steel Mining Co. in 001. The three units are each MW tangentially-fired coal boilers and steam generators. Q. What is the status of THEC? A. In May 01, after years of operation, Minnesota Power ceased coal-fired generation at THEC in response to the MATS regulation taking effect on April 1, 01. This unit was retired in place. Q. What is the status of THEC1 and THEC? A. Minnesota Power plans to cease coal-fired operations at THEC1& by the end of 00 and, as part of that transition, these units were idled in the fall of 01. This plan was recently approved by the Commission in its July 1, 01, decision on Minnesota Power s 01 IRP. 0

23 Q. What is the advantage of idling THEC1&? A. Minnesota Power decided to idle THEC1& so that these units can be called upon as needed to provide regional reliability. Specifically, these idled units could be restarted and produce electric power if needed to maintain grid reliability in an area where there are limited alternatives to address potential local transmission and distribution interruptions. Thus, THEC can be used when conditions require it to stabilize the bulk electric system until other generation or transmission alternatives can be executed. Idling of THEC1& also provides the Company with more flexibility during this time of significant change in state and federal energy and environmental policies. The THEC facility has several favorable attributes including a deep water port, rail line, and power generation infrastructure. These assets have been prudently maintained and could be used for alternative energy generation or other industrial infrastructure in the future. Q. What are the environmental benefits of idling THEC1& and retiring THEC? A. Minnesota Power expects that the idling of THEC1& and the retirement of THEC will reduce overall emissions in the region, in particular carbon emissions, by about 1,00,000 tons per year. Other environmental emission reduction benefits from the EnergyForward strategy regarding THEC are shown in Figures,, and above. Q. What O&M cost savings are expected as a result of idling THEC1&? A. Per the recent IRP, it is estimated the O&M savings in year 01 from idling THEC1& is approximately $ million. However, even while in the idled mode, THEC1& will need to fulfill permitted environmental obligations at the site in the event the units are called upon to run. The costs to meet all permit conditions regarding air, water, and waste will require resources and continued expenses. In addition, the equipment at the site needs to be idled and maintained in a used and useful condition to meet the obligations of the MISO market if called upon to run. Further, to demonstrate permitted compliance, as well as to maintain accredited capability in the MISO markets, there will be two time periods between mid-year 1

24 and mid-year 00 where the assets will need to be brought on-line and operated for a period of time to demonstrate air emissions compliance and market capabilities. These two time periods will be scheduled to maximize value to our customers, and meet the obligations of the air permits and market accreditation. The costs associated with the start-up and subsequent re-idling of these assets is projected to be $1. million per event. A start-up and re-idle sequence is included in the THEC O&M budget for the 01 Test Year, netting the savings between use as a baseload facility versus a peaking facility to $. million for 01. Q. Are there any capital additions planned for THEC in 01? A. No. There are no capital additions planned for THEC in 01 and any repairs or modifications required to return the units to service for the planned start-up and reidle sequence will be addressed on an as needed basis. C. Laskin Energy Center Q. Please describe Minnesota Power s Laskin Energy Center. A. Laskin is located in Hoyt Lakes, Minnesota, and was commissioned in 1 as a coalfired facility. Laskin has two MW net nameplate capacity generating units, Units 1 and, that are similar in design and intended operation. Q. Have there been any changes at Laskin as part of the Company s EnergyForward program? A. Yes. To help achieve the EnergyForward goal of having a mix of power generation that is one-third renewable, one-third-natural gas, and one-third coal, the conversion of Laskin from coal to natural gas was completed in July 01. In March 01, the two generating units were taken offline and the coal firing systems were replaced with new natural gas burners and electronic controls. In addition, a new mile-long natural gas pipeline was constructed to Laskin to provide fuel for these new natural

25 gas burners (Docket No. E-01/GP-1-). The capital costs for this conversion were approximately $1. million. Q. Are there any other changes at Laskin as a result of this conversion to natural gas? A. Yes. While the conversion to natural gas has changed the accredited output to MW for planning year 01 to 01, Minnesota Power is now operating Laskin as a peaking facility rather than a baseload resource. As a peaking facility, Laskin will operate considerably less than it did as a baseload resource. However, Laskin still provides value to our customers in that it provides a hedge against high regional power prices and provides needed capacity when called upon for grid reliability. With its new mission, Laskin was called upon to operate on nine occasions in August of 01. Q. Are there other benefits as a result of the Laskin natural gas conversion? A. Yes. Beyond the capacity mission change resulting in less time on-line, natural gas is also an environmentally-cleaner fuel so emissions from Laskin will be reduced as a result of its conversion to natural gas. The Laskin conversion to natural gas is estimated to reduce carbon dioxide ( CO ) emissions by 1,0 pounds per megawatt hour ( MWh ). In addition, SO, mercury, lead, and PM emissions are estimated to be reduced by over 0 percent and nitrogen oxide ( NOx ) emissions reduced by approximately 0 percent from prior coal emission levels. These emissions reductions bring significant environmental benefit to the region. These emission improvements are reflected in Figures,, and as estimated for 01 from 01 and 01 levels. Q. Are there any O&M savings as a result of the conversion to natural gas? A. Yes. As a coal-fired generation, Laskin employed 0 full time employees. With the facility s transition to natural gas, Laskin now employs 1 full-time employees and one part-time employee. In addition, contracted services, materials, maintenance

26 activities, and supplies have been reduced to levels that support Laskin s new mission, resulting in O&M cost savings of approximately $. million in total for 01 versus the coal operation budget of 01, which was the last full year of coal operation. The 01 O&M budget reflects the change in Laskin s mission to a natural gas peaking facility. IV. RENEWABLE GENERATION A. Hydro Resources Q. Please describe Minnesota Power s hydro resources and how they serve the region. A. From its earliest days, Minnesota Power has used water to generate energy. Today, Minnesota Power is the largest hydro energy producer in the state, with generating capability of approximately MW. The Company operates hydro stations on five rivers that are part of three main river systems in central and northern Minnesota the Mississippi River, St. Louis River, and Kawishiwi River (including the.1 MW non-regulated Grand Rapids hydroelectric station operated under contract to UPM Blandin). Thomson, the Company s largest hydroelectric station, has been generating renewable power for more than 0 years, as have the Little Falls and Sylvan stations. In addition to maintaining dams at each hydro station, Minnesota Power also maintains six headwater storage reservoirs. Minnesota Power operates its stations and reservoirs under eight federal licenses. The Federal Energy Regulatory Commission ( FERC ) oversees dam operations and safety in the United States, and FERC licenses specify operating parameters. Q. Has the Company made any recent capital investments in these hydro facilities? A. Yes. Many of our hydro facilities are older units. In fact, three of our hydro stations have recently marked 0 years of service. Little Falls, turned 0 years old in 00; Thompson celebrated its centennial in 00; and Sylvan turned 0 years old

27 in 01. Due to the age of these facilities, Minnesota Power has completed projects and capital refurbishments at most hydro facilities since the last rate filing. The investments have been consistent with the EnergyForward mission to increase diversity by maintaining existing and expanding new renewable energy supplies. In addition, we have made improvements to maintain our hydro assets to meet the safety and integrity standards of Minnesota Power and expectations of the public and FERC. Typical projects include refurbishment of dams and powerhouse structures, spill gate replacements, and generating unit overhauls. Q. What damages were sustained at Thomson as a result of the 01 flood event? A. The 01 flood event caused significant damage to the Thomson powerhouse and other facilities. Most significantly, on the afternoon of June 0, 01, the Thomson powerhouse basement was severely flooded and later that evening a section of the forebay embankment at Thomson was breached. The flooded powerhouse resulted in significant damage to the generating turbines and related electrical and mechanical infrastructure, while the breach in the forebay canal prevented water flow to the generating station, forcing Thomson offline. Q. What repairs has the Company made at Thomson to address the flooding damage? A. Since the flood, the Company worked with FERC and other regulatory agencies to develop and execute an approved plan to return Thomson to service. The Thomson reconstruction ( Thomson Restoration Project ) included elements of both a restoration to service, as well as some long-term improvements that were made while the units were off-line. Some examples of these projects include the forebay canal reconstruction, electrical restoration, generating unit refurbishment, mechanical and general civil rehabilitation, upgrades to the water conveyance system, and construction of additional spillway facilities at the Thomson main dam.

28 Q. Did the Company request Commission approval for recovery of the costs of the Thomson Restoration Project? A. Yes. On July, 01, Minnesota Power submitted a petition for recovery of the costs for capital projects included in the Thomson Restoration Project eligible for the Rider for Renewable Resources ( RRR ) (Docket No. E01/M-1-). On March 1, 01, the Commission approved the RRR recovery for $0. million in restoration activities at Thomson. Q. Did Minnesota Power receive any insurance payments to cover the cost of the Thomson Restoration Project? A. Yes. Minnesota Power received approximately $. million in insurance payments from claims associated with the powerhouse, mechanical, and electrical equipment. Our insurance policy did not include coverage of dams, dikes, damage to land, relocation of power lines, or business interruption. Q. Is the Thomson Restoration Project complete? A. The project is substantially complete. In November 01, Thomson began generating energy for the first time since the flood and full generating capability was attained in December 01 once all components in the station were re-commissioned following the restoration. The restoration projects improved the efficiency of the units, resulting in an increase of approximately MW of generation capability from prereconstruction levels, and the Thomson station is now capable of nearly MW at peak production. Q. What additional work remains to be done in 01? A. While restoration of the generating station is complete, two on-going projects associated with improving spill capacity are still in progress. These projects are the Thomson Spill Capacity and the Thomson Refurbish of Dam. As spill capacity alternatives were evaluated, the Company determined a phased approach to increasing spill capacity, as represented by these two projects, was in the best interest

29 of our customers and communities. The Company anticipates completing construction on the first phase of these spill capacity improvements to close out the Thomson Restoration Project in 01, which will increase the total spill capacity to approximately 0,000 cubic feet per second, compared to,000 cubic feet per second at the time of the 01 flood. These plans require FERC approval prior to starting construction, which is anticipated to occur in 01. Q. What portion of the Thomson Restoration Project is moving from the RRR to base rates? A. All projects that are expected to be placed in service by December 1, 01, will be moved from the RRR to base rates. This includes all projects associated with the Thomson Restoration Project except the Spill Capacity project and the Refurbish of Dam project described above. We anticipate the amount moving to base rates will be $. million, which is lower than the $0. million approved in the Company s initial request for RRR recovery of costs associated with the Thomson Restoration Project. Q. What is the Company s proposal with respect to the recovery of capital costs for two remaining capital projects? A. As explained in greater detail in the Direct Testimony of Company witness Mr. Minke, the Company s proposal is to continue recovery of the two remaining projects in the RRR as these projects are still under construction and will be in-service in 01. The cost recovery for these two remaining projects, including the final costs of the Thomson Restoration Project, will be addressed in the RRR docket. Q. What other key capital investments have been made at the Company s hydro facilities since the Company s last rate case? A. Other significant upgrades were made in recent years at Fond du Lac and Prairie River hydro stations and the Birch Lake dam. A new, more efficient turbine was installed at Fond du Lac along with rewinding the generator, slip-lining the penstock,

30 and other modernizations. At Prairie River, the Company refurbished and modernized the facility after a fire struck in December 00. The Company constructed a modern powerhouse and substation, installed new generators, refurbished the turbine, and modernized related plant systems. In 01, the Company completed a transformation of the Birch Lake dam from a wooden structure to a concrete one. Q. Are there any planned capital additions at the hydro facilities for 01? A. In addition to the capital additions at Thomson discussed above, we also plan to make improvements at other hydro facilities to replace aging facilities and to ensure compliance with FERC requirements. For instance, we plan to replace several of the tainter gates at the Little Falls hydro station. Based on recent inspections and a risk assessment, we determined that these gates need to be replaced as the existing gates have deteriorated such that it impacts their reliability and serviceability. In addition, we plan to increase the spill capacity at the Sylvan hydro station as the Sylvan dam does not have adequate spill capacity to meet FERC requirements for an inflow design flood. B. Biomass Resources 1. Hibbard Renewable Energy Center Q. Please describe the Hibbard Renewable Energy Center ( Hibbard ). A. Hibbard is located in west Duluth, Minnesota. In 1, Duluth Steam District # ( DSD ), an affiliate of the City of Duluth, was formed to retrofit and own Hibbard Units and boilers to supply steam to the newly constructed paper mill and Minnesota Power s electric generating units in the facility. Hibbard Units and have been providing a portion of Minnesota Power s renewable generation, regulation services, and spinning reserves for over twenty years, and currently provides MW of net capacity along with dispatchable renewable energy for Minnesota Power customers. Hibbard is capable of burning wood and wood wastes, coal, and natural gas. As such, much of the energy generated at Hibbard is a qualified renewable

31 energy product pursuant to Minn. Stat. 1B., subd.. 1 As a dispatchable renewable asset, Hibbard is a key part of our EnergyForward strategy as its renewable capability not only provides fuel diversity and lower carbon intensity, but its flexibility also enables deployment of variable renewable generation such as solar and wind. Q. How has the ownership structure of Hibbard evolved? A. Prior to 00, Minnesota Power owned the electric generation assets and related facilities at Hibbard, and received steam for generation of electricity from the DSD. The City of Duluth owned the steam production assets at the Hibbard facility and sold steam to both Minnesota Power and the adjacent steam customer, NewPage (now Verso Paper). Under DSD ownership, ongoing operating, maintenance, and capital expenditures were determined by a joint board with representatives from the City of Duluth, the paper mill, and Minnesota Power. Although the DSD ownership and governance structure was a successful model for initiating the redevelopment of Hibbard, the three-party governance structure complicated and limited reinvestment for the long-term sustainability of the facility. In 00, Minnesota Power entered into a Redevelopment Agreement with the City of Duluth and on September, 00, received an Order from the Commission (Docket No. E01/M-0-) approving the purchase of the steam production assets, Hibbard Units and boilers, and related facilities, from the City for $. million. The Redevelopment Agreement recognized the need for reinvestment in Hibbard to maintain long-term reliability of the operation and included public policy covenants related to ongoing steam supply and a minimum reinvestment of $1 million in the Hibbard boilers. 1 See In the Matter of a Petition for Approval of a Redevelopment Agreement for the M.L. Hibbard Units & Boilers and Related Facilities from the City of Duluth and for Approval of Inv. and Expenditures at the M.L. Hibbard Energy Center Through Minn. Power s Renewable Res. Rider Under Minn. Stat. 1B.1, Docket No. E01/PA-0-, ORDER APPROVING PURCHASE AND MAKING FINDINGS RELEVANT TO RECOVERY OF UPGRADE EXPENDITURES THROUGH THE RENEWABLE ENERGY RIDER at (Sept., 00).

32 On September 0, 00, the assets were transferred to Minnesota Power and investments were made to repair, replace, and modify the steam generating assets to support reliability to our customers, meet new environmental regulations, and sustain the life of the assets to prudently meet the intended mission of the facility. Today, Minnesota Power supplies steam directly to Verso Paper (formerly NewPage) under a long-term contract while providing capacity and dispatchable renewable energy generation to Minnesota Power s other customers Q. Did the Commission s 00 Order approve additional investment in Hibbard? A. Yes. In addition to approving the purchase of the Hibbard boilers and fuel handling facilities from the City of Duluth for $. million, the Commission s September, 00 Order also approved Minnesota Power s proposed expenditure of $ million to optimize the steam plant for meeting the Company s Renewable Energy Standard ( RES ) obligations. These improvements, if completed, would have facilitated an increase in renewable generation of up to,000 MWh per year. More specifically, in 00 we anticipated making the capital improvements outlined in Table from 00 through Table System Improvement Capital Cost Estimate Overfired Air System & Combustion Control System Upgrades $,000,000 Ash System Improvements $,0,000 New Wood Hog $,000,000 Truck Dumper Deck & Cylinder Replacement $1,00,000 Continuous Emission Monitoring System $0,000 Sootblower System Improvements $0,000 New Fuel Feeders $,00,000 Control System Improvements $0,000 Boiler Grate Replacement $,00,000 Total Costs $,000,000 0

33 Q. Did the Company re-evaluate its capital investment plans for Hibbard at some point? A. Yes. The 00 list of capital improvements was originally contemplated for the primary purpose of increasing biomass generation by up to,000 MWh/year to assist in meeting the RES. In 0, the Company compared the cost of making these improvements to increase generation at Hibbard to other sources of renewable generation. By this time, changes in market conditions and federal tax policy, as well as improvements in manufacturing for wind and solar generation lowered the cost of these renewable energy sources as compared to increasing Hibbard s biomass generation. As a result, the Company determined it was most appropriate to pursue wind and solar renewable generation sources rather than increasing the output of Hibbard. Q. Were there other improvements that needed to be made at Hibbard even after the Company decided not to pursue increasing its generation output? A. Yes. To allow Hibbard to continue reliable operation, we needed to make investments to address the ongoing reliability of the aging and worn equipment and to comply with new environmental regulations (e.g., MATS and National Ambient Air Quality Standard ( NAAQS )). As a result, a number of projects, some similar to those identified in Table and several additional projects, were required and completed to comply with the new environmental regulations requiring reduction in the percentage of coal in Hibbard s fuel supply. The Company discussed certain Hibbard investments planned for 0, specifically boiler grate, dust collector replacements, and electrical system improvements to meet federal standards as part of its last rate proceeding (Docket No. E01/GR-0-1). Q. What changes in Hibbard s fuel supply were required by the MATS regulation? A. Prior to these regulation changes, Hibbard s fuel mix was to 0 percent coal and 0 to percent biomass. To achieve compliance with MATS, capital improvements were completed to facilitate increasing and constantly maintaining at least 0 percent 1

34 1 biomass in Hibbard s fuel supply, thus reducing the coal utilization to less than percent. This compliance approach was chosen because it was the most cost-effective solution of the alternatives considered, which included converting to new natural gas boilers and installing additional pollution control equipment. Q. Did the Hibbard improvements result in a reduction in the use of coal in Hibbard s fuel supply? A. Yes. Today Hibbard s coal utilization is less than percent. Figure below shows Hibbard s shift in fuel supply from 0 to 01 as compared to after the improvements were in-serviced in 01. Figure Q. What was the final cost for the Hibbard improvements? A. The final cost for the Hibbard improvements of similar nature to the 00 project list was approximately $1. million. However, additional capital improvements necessary to maintain reliability of the units, upgrade to current electrical safety

35 Project List standards, and comply with new environmental regulations resulted in an additional investment of approximately $. million, for a total reinvestment of $. million in the Hibbard boiler assets. In addition to investing in necessary improvements to the Hibbard boiler assets, approximately $. million was invested in necessary turbine overhauls, controls upgrades, roof replacements, and other refurbishment to meet current safety and environmental standards for the site, for a total capital investment of approximately $. million between 00 and 01. After depreciating investments over the time period, this has resulted in a net plant balance of approximately $0 million for the Hibbard facility. A summary of the capital investment at Hibbard from 00 to 01 is provided in Table. System Table Overfired Air System & Combustion Control System Upgrades Original Estimate Actual Investment $,000,000 $,1,000 Ash System Improvements $,0,000 $,,000 New Wood Hog $,000,000 $1,,000 Truck Dumper Deck & Cylinder Replacement $1,00,000 $1,,000 Continuous Emission Monitoring System $0,000 $0,000 Sootblower System Improvements $0,000 $0 New Fuel Feeders $,00,000 $0 Control System Improvements $0,000 $1,000 Boiler Grate Replacement $,00,000 $,0,000 Subtotal 00 Project List $,000,000 $1,,000

36 Base Boiler & Environmental Base Boiler Refurbishment $,0,000 Boiler Environmental & Efficiency Upgrades $1,,000 Electrical Arc Flash Safety & Reliability $,,000 Base Fuel System Refurbishment $,1,000 Water System Refurbishment $,0,000 Subtotal Base Boiler & Environmental $,,000 Total Hibbard Boiler Asset Reinvestment (00-01) $,1,000 1 Building & Turbine Building Systems, Safety & Site Environmental $,000 Building Roof Replacements $1,,000 Turbine Overhaul & Control Upgrades $,0,000 Subtotal Hibbard Building & Turbine Asset $,,000 Grand Total Hibbard Boiler, Turbine & Site Reinvestment (00-01) $,0,000 Net Plant in Service (01) $0,000,000 Q. Can you summarize the emissions reductions achieved at Hibbard as a result of these improvements? A. Yes. Following these investments, emissions reductions were achieved at Hibbard for all categories of pollutants as summarized in Figure.

37 Figure Beyond categorical pollutants, decreased coal combustion at Hibbard resulted in a substantial reduction in CO emissions from the facility in 01 once coal combustion was reduced as shown in Figure below. Figure

38 Q. Did Minnesota Power pursue cost recovery through the RRR for its investments in Hibbard? A. No. Since the change in market and environmental regulations required a substantial change in the projects completed at Hibbard, it was determined the revised expenditures did not exclusively fit the definition for the RRR. Thus, the Company decided that it would be in the best interest of our customers to make the investments as part of the Company s base capital expenditures, deferring recovery of the investment until the Company s next rate proceeding. Q. Did the Commission s 00 Order approving the Hibbard purchase impose any ongoing compliance obligations? A. Yes. The Commission s 00 Order required Minnesota Power to address, in the first rate case after Hibbard goes into service and in all subsequent rate cases until the Commission orders otherwise, whether the Hibbard facility is used and useful in providing retail utility service and whether the investments and related expenses and revenues are reasonable and prudently incurred. Q. How is Hibbard used and useful in providing retail utility service? A. Hibbard is capable of and originally designed for baseload operation and supports capacity and baseload energy generation when energy is required. Hibbard s multifuel boilers provide steam that drives Hibbard Units and turbine generators, as well as supports papermaking processes at the adjacent Verso paper mill. In recent years, there has been a shift in the strategic operation of Hibbard to run when market prices and grid reliability warrant, causing Hibbard to be used more as a capacity and dispatchable renewable energy resource, rather than a baseload energy resource. As a dispatchable renewable energy resource, Hibbard provides a ready source of renewable energy, offering an economic cost hedge for Minnesota Power customers as a flexible resource to support the expansion of variable renewable energy. Under this mission, Hibbard continues to be offered under an economic

39 dispatch model and is called to support Minnesota Power customer demand when needed. Hibbard has been called upon to support customer needs many times in 01 during the peak summer energy months, running roughly one-third of the days in July and August alone. In addition to capacity and dispatchable energy operation, the Company partnered with the City of Duluth in 01 to address the disposal of several thousand tons of storm damaged trees, which resulted in economical generation of approximately,000 MWh for Minnesota Power customers while providing an economical outlet for the City of Duluth s waste material. Flexibility in running and dispatching Hibbard under a range of generation options (e.g., spin, regulation, or baseload) provides a renewable fueled energy hedge for Minnesota Power customers, while the capacity availability provides an accredited resource to meet Minnesota Power s capacity requirements. Q. Were the investments and related expenses and revenues [at Hibbard] reasonable and prudently incurred? A. Yes. Given their age and condition it was necessary to refurbish the building and roof, overhaul turbines, and reinvest in the steam generating assets to improve and sustain reliability and performance of these facilities. For instance, the turbines were last overhauled prior to the restart of Hibbard and were in need of inspection, refurbishment, generator rewind, and modernization of controls. The roofs had exceeded their expected life, were leaking, and required replacement. Many electrical systems were original equipment from the s and required upgrading to include modern safety protections. In addition, new and more stringent environmental regulations have been implemented over the past several years that required additional investments to ensure compliance with these new standards. In order to meet MATS and NAAQS regulations, improvements to fuel handling and boiler systems were required. Fuel

40 handling improvements included a new higher-capacity wood hog, wood shed augers, metering bin screws, and refurbishment of the truck dumper. In the boiler, it was necessary to install an over-fired air system, upgrade the dust collectors, and replace economizers, air heaters, and gas burners for reliable, efficient, and stable operation when co-firing with less than percent coal. Finally, as demonstrated in Figures and, the improvements made at Hibbard had a positive impact in reducing both the SO and CO emissions from this facility. These emissions reductions provide environmental benefits to our region. Q. Are there any capital additions planned for Hibbard for 01? A. Yes. We plan to replace the wood/coal feeders in Units and as the feeders are original and need to be replaced. These feeders are needed to maintain adequate fuel supply and distribution to the boilers. In addition, we plan to replace the boiler grates in Unit as they are at the end of their useful life. These grates are critical to allowing the use of solid fuel; if these grates are not replaced, they have a tendency to warp or jam causing the solid fuel capability to be shut down.. Cloquet Energy Center Q. Please describe the Cloquet Energy Center. A. Cloquet Energy Center is a single pressure reducing turbine generator ( MW) set located at the Sappi Fine Paper North America Mill in Cloquet, Minnesota, that was installed in 001. The turbine generator set was owned by Minnesota Power and operated by Sappi. It is a pressure-reducing turbine coupled with a generator that operates on the steam system between Sappi s chemical recovery boilers and its paper machines. The boilers are fueled by wood and natural gas. The contract specified that after 1 years of operation (001 to 01), ownership of the asset would be transferred to Sappi prior to July 1, 01, if a contract extension agreement cannot be reached.

41 Q. Did Minnesota Power and Sappi reach an extension agreement prior to July 1, 01? A. No. An agreement between the parties could not be reached and as a result, ownership of the Cloquet Energy Center transferred to Sappi on June 0, 01. Q. Does Minnesota Power have any continuing obligations at this site after the transfer? A. No. Sappi now owns and operates the turbine generator set. Minnesota Power does not have any capital or O&M costs associated with Sappi in the 01 test year. This is a small O&M savings to Minnesota Power of approximately $,000 a year (Total Company). Q. How does this transfer impact Minnesota Power s generation portfolio? A. After the transfer, the generation that was part of Minnesota Power s generation portfolio will displace what Sappi previously purchased from Minnesota Power. The transfer does not impact Minnesota Power s net load or capability balance.. Rapids Energy Center Q. Please describe Rapids Energy Center ( Rapids ). A. Rapids, located in Grand Rapids, Minnesota, is an efficient combined heat and power facility capable of burning wood, wood wastes, coal, and natural gas and has a combined generation capacity of. MW. The use of wood and wood waste makes the energy generated from Rapids a renewable energy product. Rapids assets consist of two wood-fired boilers, two natural gas-fired boilers, air compressors, two steam turbines, and two small hydroelectric turbine sets. Total Company refers to total Minnesota Power regulated, without Minnesota Power s non-regulated entities.

42 Q. How is the generation from Rapids used? A. Rapids is located on-site and is interconnected to the UPM Blandin paper mill. The equivalent energy output from Rapids is dedicated to serve UPM Blandin as specified in the agreement under which Minnesota Power purchased the generation assets from UPM Blandin in 000 (Docket No. E-01/M--1). Rapids supplies only a portion of the power and energy for the mill. With typical energy production in the 1 to 1 MW range, UPM Blandin also receives another 0+ MW of capacity and energy as a retail electric customer from Minnesota Power. The energy from Rapids is allocated to UPM Blandin and UPM Blandin pays all associated energy costs. The energy sales to UPM Blandin are therefore accounted for as non-regulated sales in order to isolate this energy and not incorporate it into Minnesota Power s energy supply for all other regulated retail sales. Under certain operating scenarios, there is also a limited amount of surplus energy from Rapids that can be used to serve other Minnesota Power customers. This energy is available during the times when Minnesota Power customers need additional energy and it is not needed for UPM Blandin s requirements. Q. How does Minnesota Power account for the capital and O&M associated with Rapids? A. Rapids is a non-regulated unit separated from regulated operations with its financial transactions recorded in non-regulated asset accounts in the Company s fixed asset records. Asset-related expenses, such as depreciation and property taxes, are also recorded to non-regulated accounts. Rapids staff is assigned to a specific Minnesota Power Responsibility Center to which all their labor and expenses are recorded. All expenses associated with Rapids, including labor and employee expenses, are recorded in non-regulated expense accounts. Q. Has the Company ever addressed whether to move Rapids into rate base? A. Yes. In Minnesota Power s 00 rate proceeding, the Department of Commerce recommended that Rapids be moved into rate base because it is used to serve retail 0

43 load. Minnesota Power did not oppose this transition but stated that contract amendments would be needed with UPM Blandin to facilitate this transition. Between 00 and 01, Minnesota Power and UPM Blandin entered negotiations to facilitate a contractual arrangement that would allow integration of Rapids into rate base. In 01, Minnesota Power filed petitions with the Commission to approve an amended electric service agreement between the Company and UPM Blandin that would have allowed the transfer of Rapids assets into regulated operations (Docket Nos. E01/M-1-1 and E01/M-1-1). On October, 01, the Commission denied Minnesota Power s request, without prejudice, to transfer the assets of Rapids from non-regulated to regulated operations as there was not sufficient information in the docket as to whether Rapids revenues would exceed its costs. Q. Does the Company propose to transfer Rapids to regulated operations as part of this filing? A. No. Minnesota Power has not included Rapids in rate base as part of this Initial Filing. However, we continue to evaluate a transition of Rapids to regulated operation under conditions that make sense for all stakeholders. I note that such a change would require Minnesota Power to renegotiate its existing contract with UPM Blandin. C. Wind Generation Q. Please describe the Company s renewable wind generation facilities. A. The Company owns two wind generation facilities, the MW Taconite Ridge facility that began operating in 00 and the nearly MW Bison facility in North Dakota that was completed in late 01. In addition to these wind generation sites, Minnesota Power also purchases wind energy from the Oliver County Wind Energy Center near Center, North Dakota from NextEra Energy. 1

44 Q. Please describe the Taconite Ridge facility. A. Taconite Ridge, the first commercial wind energy center in northeastern Minnesota, began operating in June 00. The MW facility is located on property owned by U.S. Steel in Mountain Iron, Minnesota. Q. Please describe the Bison facility. A. The Bison facility, located in Oliver and Morton counties, is the largest wind farm in North Dakota at MW. Bison was built in four phases. The Bison 1 Wind Energy Center, located southwest of Center, North Dakota, was completed at the end of January 01 and includes 1 turbines that supply MW. Bison and each consist of turbines and together supply MW of renewable energy. The commissioning of Bison and was completed in December 01. The 0 MW Bison has turbines and commissioning was completed in late 01. Q. In its July, 00, Order (Docket No. E01/M-0-) approving the Bison I Wind project, the Commission required Minnesota Power to address any cost overages for this project in its next rate case. Was this project completed on budget? A. In our March, 00, Petition for Approval of Investments and Expenditures in the Bison I Wind Project for Recovery through Minnesota Power s Renewable Resources Rider, we estimated the total capital costs for the Bison I Wind project to be $1.0 million and the associated upgrades to the DC Line to be estimated at $. million ($1. total). The final overall project costs for the Bison I Wind project was $. million and the associated upgrades to the DC Line were $.1 million or $1. total. The final costs for the DC Line, in service in 01, were slightly above ($00,000) the estimated costs due to weather delays and engineering changes from initial design to final engineering.

45 Q. In its September, 0, Order (Docket No. E01/M--) approving the Bison Wind project, the Commission stated that the Company will have the opportunity to seek recovery of any costs beyond its initial estimate in its next rate case. Was this project completed on budget? A. The project was completed under budget. In our March, 0, Petition for Approval of Investments and Expenditures in the Bison Wind Project for Recovery through Minnesota Power s RRR, we estimated that the Bison Wind project would have total capital costs of $1 million. The overall Bison Wind project was finalized at $1. million, or $. million under the original budget. Q. In its November, 0, Order (Docket No. E01/M--) approving the Bison Wind project, the Commission stated that the Company will have the opportunity to seek recovery of any costs beyond its initial estimate in its next rate case. Was this project completed on budget? A. The project was completed under budget. In our June, 0 Petition for Approval of Investments and Expenditures in the Bison Wind Project for Recovery through Minnesota Power s Renewable Resources Rider, we estimated that the Bison Wind project would have total capital costs of $1 million. The overall Bison Wind project was finalized at $.1 million, or $. million under the original budget. Q. In its January 1, 01, Order (Docket No. E01/M-1-0) approving the Bison Wind project, the Commission stated that the Company will have the opportunity to seek recovery of any costs beyond its initial estimate in its next rate case. Was this project completed on budget? A. The project was completed under budget. In our September, 01 Petition for Approval of Investments and Expenditures in the Bison Wind Project for Recovery through Minnesota Power s Renewable Resources Rider, we estimated that the Bison Wind project would have total capital costs of $. million. The overall Bison Wind project was finalized at $.1 million, or $. million under the original budget.

46 Q. What is the Company s proposal with respect to the recovery of capital costs for Bison? A. As all four phases of Bison are now in-service, we propose to move cost recovery of Bison and its associated Production Tax Credits ( PTCs ) from the RRR to base rates. As discussed further in the Direct Testimony of Company witness Ms. Jamie Jago, the 01 budgeted level of PTCs would be included in base rates, and a true-up for actual differences each year will be included in the RRR. The RRR and cost recovery for Bison is also discussed in the Direct Testimony of Company witness Mr. Minke. Q. What is the Company s approach to operating and maintaining the Minnesota Power-owned Taconite Ridge and Bison? A. Minnesota Power uses ALLETE Renewable Resources Inc. ( ARRI ) for site wind technician labor services and contractors for specialized repair services. ARRI is a service organization that was formed in 00 to create a labor force that could support either regulated or non-regulated renewable projects and operations. As an internalto-allete service company, ARRI can more cost effectively support Minnesota Power s regulated renewable projects and ALLETE s non-regulated renewable projects as compared to using internal labor. Currently, ARRI provides O&M services to both Minnesota Power regulated facilities (Bison and Taconite Ridge). At Taconite Ridge, Minnesota Power is responsible for all of the O&M activities of the assets. At Bison, Minnesota Power is responsible for the O&M of the 1 Siemens. MW gear-driven turbines that comprise a portion of Bison 1. For the 1 directdrive turbines that comprise the rest of Bison 1,, and, Minnesota Power has contracted with Siemens for wind turbine maintenance services.

47 Q. How does the long-term service agreement with Siemens aid in controlling O&M costs at Bison? A. The long-term service agreement covers the years following expiration of the original -year equipment warranty and service maintenance agreement. Under the agreement, Siemens provides labor resources, component warranty coverage for parts, and technical support for maintaining the wind turbines. The agreement also includes a performance guarantee on wind turbine availability. This long-term service agreement provides maintenance cost certainty and risk mitigation, while ensuring equipment reliability. As alternatives to the long-term service agreement, Minnesota Power considered options ranging from the ability to self-perform all O&M to hiring a third-party service provider for wind turbine maintenance labor. With these alternatives, Minnesota Power recognized the assets would still be heavily dependent on Siemens for materials and technical support, but without any cost certainty, risk mitigation, or timeliness guarantee under any non-siemens options. Since replacement materials and technical support are key drivers of wind turbine availability, and therefore energy production, the long-term service agreement with Siemens was pursued. The long-term service agreement provides cost certainty and risk mitigation through its defined pricing and component parts warranty, while ensuring timeliness through the wind turbine availability guarantee. V. GENERATION O&M COSTS Q. Please describe Generation s O&M budget. A. The Generation O&M budget is based on expenses incurred while operating and maintaining the assets in our generation portfolio. The majority of our O&M budget is comprised of the internal and contractor labor that is required to operate our facilities on a day-to-day basis, as well as to perform necessary maintenance and repairs of these facilities to ensure their reliable operation. Another major cost driver in our O&M budget is for chemical reagents to reduce emissions at our coal-fired

48 generation facilities. We utilize reagents such as ammonia, halogenated activated carbon, and lime continuously whenever these generation facilities are operating. In addition, we also incur O&M costs for equipment purchases such as safety equipment, office supplies, and small tools and equipment. These three categories of costs form the basis of our O&M budget and are necessary to run our facilities to provide power generation to serve our customers. As described in more detail in the Direct Testimony of Company witness Mr. Morris, budgets for each business area are developed at the Responsibility Center level based on the needs of that area and the plants served. As part of that budget development, we are routinely carefully considering our cost levels Q. What is Generation s O&M budget for the 01 test year? A. The 01 O&M for Generation is provided in Table below. The costs are broken down by each Generation Responsibility Center. Table Generation Responsibility Center 01 Generation O&M Budget Hibbard $,, Laskin $1,,1 BEC1& $,, BEC $,, BEC $1,0,1 Taconite Harbor $,000 Cloquet Energy Center 0 Taconite Ridge Wind Energy Center $1,, Fuel Handling $,0, Eng. Services $,0, Generation Operations $,, Hydro $,, Solar-Camp Ripley $, Bison Wind Energy Center* $1,,00 Total O&M $,, *Prior to this rate case, Bison O&M was considered part of the RRR. 1

49 Q. What additional steps has Generation taken to control O&M expenses in recent years? A. Minnesota Power s Generation Operations O&M expense management efforts in recent years include many facets. Broadly, these efforts can be categorized in three ways: (1) improved human performance/process efforts, () small coal fleet transition, and () optimized reagent usage. As a result of these efforts, the generation O&M budget has remained generally flat and near 0 levels while the Company has executed its EnergyForward strategy. This is despite the addition of incremental O&M expense from additional renewable generation resources and costs associated with environmental improvement efforts including reagents, service contracts, and additional maintenance activities. Q. Can you provide more detail illustrating how Generation s 01 O&M budget compares to recent years? A. Yes. Figure below depicts the O&M spend for Generation from 0 to 01. In this figure, the green line labeled Combined represents the total O&M costs incurred during this time frame (01 is the current forecast and 01 is the budget) for the generation fleet. The black line labeled Base are those costs of the existing facilities that were incurred prior to any addition of renewables, or the result of environmental improvement projects, forming the base budget for each facility. The red line labeled Rider represents incremental expenses related to operating and maintaining new or refurbished renewable assets (i.e., long-term service agreements, additional staffing at Bison, etc.) and newly-installed pollution control equipment (i.e., chemical reagents, new maintenance and parts, service contracts, etc.).

50 Figure *includes MP &WPPI portions O&M Figure shows that despite incremental costs of nearly $1 million in rider-eligible projects, the rest of the fleet has reduced O&M expense to keep the overall O&M expense from 0 to 01 generally flat at 0 levels (black line + red line = green line). I describe Generation s more specific efforts to control Company costs, below. Q, Has the Company s ability to keep O&M levels in line with 0 levels and contain costs impacted the reliability of the Company s generation units? A. No. In fact, in addition to controlling costs through these efforts, we have also seen improved reliability of the assets, as demonstrated in Figure below. In this figure, the total Fleet Equivalent Unplanned Outage factor is shown for 0 through August of 01, with the trend decreasing. This indicates fewer unplanned outage and maintenance needs in total.

51 Figure VI. COST CONTAINMENT EFFORTS Q. What is the purpose of this section of your testimony? A. In this section of my testimony, I describe Generation s broad cost control focus areas, including small generation, human performance and process improvements, and emission reagent cost controls. Consistent with Order Point 1 from Minnesota Power s prior rate proceeding, I also discuss additional, quantifiable cost savings measures the Company has implemented since our last rate proceeding. A. Small Coal Fleet Transition Q. What efforts has the Company undertaken to control costs with respect to the transition of its small coal fleet? A. As highlighted earlier in my testimony, the Company has implemented a mission change at Laskin to a natural gas-fired capacity resource, as well as retired THEC and subsequently idled THEC1&. These changes had the primary purpose of reducing the Company s emissions while also serving to control Company costs since the time of the mission change, retirement, and idling of these plants.

52 Q. How has the small coal fleet transition affected Company costs? A. At Laskin, the new mission O&M cost savings is approximately $. million as budgeted for 01 versus the last full year of coal operation in 01. At Taconite Harbor, the forecasted O&M savings from idling THEC1& is estimated to be $. million in 01. These savings are reflected in Exhibit (JJS), Schedule, which reflects the quantifiable cost containment efforts specific to Generation and which is a subset of the broader cost containment schedule attached to Company witness Mr. Morris Direct Testimony at Exhibit (SWM), Schedule. B. Human Performance and Process Improvements Q. Can you describe what human performance and process improvements have been made in Generation since 0? A. Yes. Since 0, the generation fleet has made significant investment in human capital with a focus on improving our work planning and execution, as well as our O&M practices. This was done to assure critical equipment is given the right level of care at the right frequency, to maximize the expected and designed life cycles of our equipment, and to reduce the overall costs. These focus areas have included deploying critical asset management strategies based on reliability-focused programs and principles. A summary of these basic principles is displayed in Figure 1 below. 0

53 Figure 1 Generation Operations Reliability Centered Principles & Behaviors Problem solving will take a systems thinking approach and drive to root cause solutions.. Betterment efforts are a never ending perpetual process.. Units will run as long as risks can be safely managed. Business vs. Technical Odds vs. Impact Proactive vs. Reactive. Communicate the facts in an open and honest way and develop a situational communication plan.. Research new methods, approaches and technology for betterment and prudent consistent applications.. RCPB is a cross functional process that relies on the transfer of knowledge and active participation of everyone. These principles guide our capital planning as well as our O&M work planning, and considerable time has been spent since 0 training and emphasizing these principles with our employees. This guidance has been critical to our O&M expense management efforts and our reliability improvement efforts. Q. Can you provide an example of how these principles have achieved cost savings for Minnesota Power? A. One prime example in the recent past was the execution and completion of the BEC retrofit outage in the fall of 01. For this outage, planning and work identification efficiencies and reallocating resources and job assignments to critical roles allowed the delivery of the work scope to be completed ahead of schedule and $. million under budget. This was important to the overall success of the retrofit project as there were immense challenges to integrate new pollution control equipment and a number of other major improvements at the site to be able to return BEC to service in a timely fashion. This savings is reflected in Exhibit (JJS), Schedule to my Direct Testimony. 1

54 Q. Can you provide other examples where improved efficiencies have resulted in lowered O&M costs? A. Yes. Three additional key areas or examples where these program and process efficiencies are evident is in (1) lower overall headcount, () reduced overtime costs, and () reduced external contractor utilization for general maintenance and repairs. Q. How has the number of Generation employees changed since 0? A. As shown in Figure 1 below, amidst workplace transition and fleet mission transition, there were fluctuations in the total number of employees between 0 and 01. The general trend, however, demonstrates the number of employees in our fleet has decreased since 0, resulting in lower overall labor costs. Over this same timeframe, the quality of the work and reliability of the units have improved (as shown in Figure 1), indicating we are improving our efficiency to execute critical work despite having fewer people on staff. For 01, we have budgeted total Generation employees. Figure 1 1 1

55 1 1 1 The savings associated with these employee levels are reflected in the cost containment efforts discussed in the Direct Testimony of Company witness Ms. Nicole Johnson. Q. Has this lower headcount increased overtime costs? A. No. As shown in Figure 1, we have been able to decrease overtime costs during a similar time frame (0 to 01). We were able to reduce overtime through gains in efficiency from the work process improvements and deployed reliability principles. In addition, there were fewer emergent work projects that required the need to pay overtime premiums. In sum, assuring equipment is run effectively and efficiently, and that work is planned carefully and intentionally, has allowed the overall overtime costs to generally decrease since 0. Figure Q. What is Minnesota Power s trend with regard to contractor utilization during this time frame? A. As depicted in Figure 1, the overall trend for contractor utilization from our primary contracting partners that provide craft support for maintenance work, has generally

56 decreased since 0 in terms of total spend. There is some variation for planned outage activities year-to-year, but the efficiencies in the work processes and reliability principles has generally reduced the need to contract additional support to maintain our reliability and support our facility missions. In combination, these human performance and process efforts have greatly supported our ability to generally keep O&M budgets flat to 0 levels in the generation fleet. Figure C. Emission Reduction Reagents and Chemicals Q. What role do reagents/chemicals play in emissions reduction? A. We utilize reagents to reduce emissions at our generation plants, specifically all four Boswell Units and at THEC. Typically the reagents are introduced during combustion or post combustion and use kinetics to drive pollutants into forms that can be scrubbed or removed from the flue gas streams. The reagents can also be used to avoid the formation of certain pollutants.

57 Q. What types of reagents/chemicals does the Company use? A. The main chemicals that we use include: urea, ammonia, sodium bi-carbonate ( SBC ), lime, limestone, activated carbon, and halogenated activated carbon. Urea is used in BEC1& and BEC, as well as THEC for NO x reduction while ammonia is used in BEC for NO x reduction. Limestone is utilized at BEC for SO control and BEC uses lime to control SO. THEC also uses additional SBC for SO reductions. BEC uses a standard activated carbon to remove mercury, while BEC and THEC use a halogenated activated carbon to reduce mercury. Q. What factors impact the amount of reagents used by the Company in a given year? A. Our consumption of reagents at a particular plant is directly correlated to the number of hours and generation levels (load) a plant is running in a particular year and the particular fuel blend used during this production period. There also can be variability from planned and unplanned outage schedules in total volume. In addition, the condition and efficiency of the pollution control equipment and the firing and boiler systems could greatly impact the amount of reagents consumed to meet permitted limits. The quality of the reagents as delivered can have marginal impacts and variability, so assuring the right products are procured can have an impact on the total volume consumed for the same generation output. Finally, while we have utilized strategic sourcing to minimize our commodity costs for these reagents, commodity pricing is also a variable factor as we have been unable to secure long-term contracts for our reagents. Q. How do you estimate reagent costs? A. Chemical or reagent usage budgets are initially set with expertise provided by Owner s Engineers, Original Equipment Manufacturer ( OEM ) performance guarantees on procured equipment, and insight from consultants who have designed, built, or operated this type of equipment at other generating facilities. These specific and qualified inputs are typically combined with thermal and fluid dynamic models

58 used in the equipment design to predict actual performance from the resulting heat inputs and flue gas streams. These estimates look to provide guaranteed performance and compliance on a range of fuels and varying load ranges. The forecasted reagents are then adjusted for anticipated levels of generation, as well as weighed against potential procured fuel blends. Procurement and delivery costs for each of our generating sites are then assigned to these estimated quantities of reagent to create the total budget. Q. Can you describe how optimization efforts have resulted in lower chemical reagent consumption and support your O&M cost reduction efforts? A. The optimization in reagent consumption is the result of many combined efforts and programs. It starts with the fuel supply and procuring fuel blends that are beneficial for our units environmental performance. Having a stable fuel source and fuel blend allows for continued adjustments and modifications of the operations, with fewer variables, driving positive results. From 0 to 01, there has been little variability in the fuel supply to our sites in terms of supply mines, although adjustments regarding blends of the fuels have required continuous attention. Q. What are the other aspects of your optimization efforts? A. The optimization efforts require constant supervision of the online performance monitoring systems. These systems are sometimes supported by experts from contracted engineering firms, or internally with experienced employees. In all cases, remote monitoring of key plant parameters takes place and trends are then investigated through plant walk-downs, data reviews, and other means on a weekly or biweekly basis. Over time, key performance indicators are observed by a number of varying load conditions and fuel changes, resulting in optimization of the reagent additions for desired conditions. In addition, the flue gas scrubbing processes have been improved with physical upgrades, control scheme improvements, and enhanced operations training and procedures.

59 Q. What have been the results of these optimization efforts? A. While many factors influence a unit s reagent consumption, including new emissions limits or obligations or subsequent equipment additions to meet compliance, BEC s reagent consumption from 0 to 01 is illustrative of these optimization efforts and the results, and can be seen in Figures 1 and 1 below. As shown in Figure 1, the general trend for all three major reagents (limestone, ammonia, and carbon) at BEC has been decreasing over time. In addition, Figure 1 below illustrates how these optimization efforts then generally translate to lower O&M costs for BEC. Figure 1 1

60 Figure While BEC has had the most stable operation in terms of emissions targets and installed pollution control equipment over this time frame, the approach to optimizing reagents is a fleetwide and continuous effort. Across our generation fleet, the actual reagent consumption since 0 has been $ million under original estimates or approximately $. million per year. Q. Are there any other cost savings related to Generation s reagents? A. Yes. In addition to the optimization efforts to reduce chemical reagent costs, as markets and supplier networks have evolved, we have used strategic sourcing (i.e., competitive bids, alternative products, and other specifics from purchasing) to provide favorable pricing for reagents for our generating sites. These efforts are described in the Direct Testimony of Company witness Mr. Morris. But for our optimization efforts and sourcing initiatives, our reagent costs would be even higher due to increased emission controls at our coal-fired plants.