Northern States Power Company, a Minnesota corporation Before the Minnesota Public Utilities Commission

Transcription

1 Northern States Power Company, a Minnesota corporation Before the Minnesota Public Utilities Commission Application for Authority to Increase Electric Rates in Minnesota November 3, 2010 Volume 2A Testimony and Supporting Schedules

2 TESTIMONY AND SUPPORTING SCHEDULES Volume 2A 1. Policy 2. Overall Revenue Requirement, Rate Base, and Income Statement (2011) Step-In Adjustment 4. Financial Integrity, Capital Structure, Cost of Capital, and Insurance Expense 5. Return on Equity 6. Sales Forecast 7. Capacity Cost Forecast

3 Direct Testimony and Schedules Judy M. Poferl Before the Minnesota Public Utilities Commission State of Minnesota In the Matter of the Application of Northern States Power Company, a Minnesota corporation for Authority to Increase Rates for Electric Service in Minnesota Exhibit (JMP-1) Policy Testimony November 3, 2010

4 Table of Contents I. Introduction and Qualifications 1 II. Case Overview 2 A Test Year 3 B Step-In and Rider Consolidation 11 III. Addressing Future Challenges 16 IV. Filing Framework 19 V. Conclusion 23 Schedules Resume Schedule 1 Safety, Reliability, and Service Quality Performance Schedule 2 Compliance Matrix Schedule 3 i Poferl Direct

5 I. INTRODUCTION AND QUALIFICATIONS Q. PLEASE STATE YOUR NAME AND OCCUPATION. A. My name is Judy M. Poferl. I am the President and Chief Executive Officer ( CEO ) of Northern States Power Company, a Minnesota corporation ( NSPM, Xcel Energy, or the Company ). Q. PLEASE SUMMARIZE YOUR QUALIFICATIONS AND EXPERIENCE. A. I have been involved in energy and regulation for the past 25 years, working in both the utility industry and state regulatory agencies. As CEO, I am responsible for the overall operations of the Company. I am directly accountable for the distribution portion of the business and have responsibility for decisions affecting investments and operations in all other business areas to ensure that our customers receive quality service at a reasonable price. My resume is included as Exhibit (JMP-1), Schedule 1. Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS PROCEEDING? A. My testimony provides an overview of our filing, the key factors driving both this request and future challenges, and our proposals for the Minnesota Public Utilities Commission ( Commission ) to consider. Specifically, my testimony highlights that: Our request is needed to provide recovery of important infrastructure improvements to our system, to respond to trends in the overall economy, and to ensure compliance with increasing regulatory requirements. While we have worked hard to manage our costs, we have been unable to sufficiently offset these cost increases. Addressing this deficiency will 1 Poferl Direct

6 allow us to maintain the high quality, reliable electric service expected by our customers. Looking forward, we need to build on our constructive regulatory processes and implement a framework that most efficiently and effectively balances customer costs, quality service, state policy objectives, and utility financial health. Even with the requested rate increase, I believe customers will continue to receive great value, as we are well positioned to meet the challenges of the future. Q. PLEASE DESCRIBE HOW YOUR TESTIMONY ORGANIZED. A. I first summarize our 2011 rate request, the key costs driving the need for the request, and our efforts to improve efficiency and control costs. Next, I discuss the challenges that we face and introduce our proposals to manage them. Finally, I outline how our filing is organized and introduce the Company s other witnesses. II. CASE OVERVIEW Q. COULD YOU SUMMARIZE THE COMPANY S REQUEST IN THIS PROCEEDING? A. Xcel Energy requests authority to increase our electric rates by $150.1 million, or 5.6 percent. We base this request on a 2011 test year, using an percent rate of return on equity. In addition, we propose to simplify our use of rate riders, moving $158 million of costs recovered through riders into base rates. Finally, we request a step-in adjustment for 2012 to recover $48.3 million of known and measureable costs for that year. Together, the rate 2 Poferl Direct

7 increases requested for 2011 and 2012 would result in an increase of $198.5 million, or 7.4 percent, over current rates. A Test Year Q. WHAT FACTORS DRIVE YOUR REQUESTED INCREASE? A. This rate request is necessary for us to: Maintain, improve, and replace infrastructure on our system. Manage cost increases and slowed sales growth related to general economic trends that affect us and other businesses. Comply with new and increasing regulatory requirements. More than half of our request is due to new infrastructure investment and support, while economic and compliance trends account for a significant portion of the remainder. Q. LET S EXPLORE THE KEY DRIVERS YOU HAVE IDENTIFIED. FIRST, CAN YOU PROVIDE EXAMPLES OF YOUR INVESTMENTS TO MAINTAIN, IMPROVE, AND REPLACE INFRASTRUCTURE? A. Yes. Our 2011 rate base is approximately $500 million higher than our last rate case, not considering the shifts due to riders. Key contributors to this substantial growth are the life extension projects and electric power uprates at our Monticello and Prairie Island nuclear generation plants, projects that have been approved by the Commission. When fully operational, these projects will provide substantial cost savings to our customers compared to alternative sources and will help us manage exposure to future environmental regulations. Another key contributor to this growth is investment in our transmission and distribution systems to provide improved reliability and 3 Poferl Direct

8 support customer demand. The transmission projects address needs identified in the Commission s biennial transmission planning dockets, while the distribution investments are needed to replace aging assets, maintain system reliability, and complete necessary facility relocation projects. Not all of the costs related to our infrastructure are capital investments, however; there is an operation and maintenance ( O&M ) component as well. For example, there are additional O&M costs associated with planned outages at Monticello and Prairie Island, costs that are necessary for the continued safe and reliable operation of those facilities. Likewise, an expanded transmission network will require higher O&M costs to plan for, operate, and maintain those facilities. Overall, the plant-related costs associated with new capital improvements and supporting O&M amount to approximately $80 million of our $150 million request. I note that, absent favorable bonus depreciation and extended lives at our Prairie Island and Black Dog plants, our infrastructure costs would have been $32 million higher than the amount reflected in this case. Q. LET S TURN TO THE SECOND DRIVER YOU IDENTIFIED. WHAT ARE SOME ECONOMIC TRENDS AND CONDITIONS THAT AFFECT YOUR BUSINESS? A. Like all businesses, general economic trends have important impacts on our Company. In 2011, we see particular impacts in the areas of sales growth, pension, and health care: Sales. Our sales dropped dramatically in 2009, and are expected to grow more slowly than normal over the next few years. While total retail sales increased at an annual average rate of 1.6 percent between 4 Poferl Direct

9 and 2007, we forecast only 1.0 percent growth in the test year. Slower sales growth diminishes our ability to offset cost increases and results in more frequent rate case filings, all else being equal. Our 2011 revenues will still be about 1.65 percent less than that included in our last rate case. Fortunately, we expect a significant portion of the decline in retail sales to be offset by an increase in our wholesale transmission revenues. Pension. Our pension costs are increasing as well. Like many, the value of our pension assets decreased during the financial crisis in 2008 and For the first time since 1994, returns on pension assets for our Northern States Power-Minnesota employees are insufficient to fully fund our pension obligations. We need to make contributions to the pension fund to comply with federal pension requirements and meet our responsibility to protect the interests of plan participants and beneficiaries. Health Care. We are experiencing health care cost increases at levels much greater than general inflation; in fact, despite numerous initiatives to control those costs, we are experiencing health care costs about four percent higher than the general medical inflation rate of seven percent. These trends are influenced by the average age of our workforce, the number of dependents insured under our plan, and high-cost claims compared to the average business. These impacts account for approximately one-third of our overall request. Q. PLEASE DESCRIBE THE NEW AND INCREASING COMPLIANCE COSTS DRIVING YOUR REQUEST. 5 Poferl Direct

10 A. We are seeing new and increasing regulatory requirements in many areas of our business. These are primarily federal requirements, from entities such as the North American Electric Reliability Corporation ( NERC ), the Nuclear Regulatory Commission ( NRC ), and the Environmental Protection Agency ( EPA ). Additionally, key provisions of recent federal legislation, such as the Pension Protection Act, and Patient Protection and Affordable Care Act, are now coming into effect. While our compliance costs must be prudently managed, increased costs associated with compliance are unavoidable. Additional compliance costs, including capital additions associated with safety and security at our nuclear facilities, account for over 10 percent of our overall rate request. Q. CAN YOU PROVIDE EXAMPLES OF SUCH ADDITIONAL COMPLIANCE REQUIREMENTS? A. Yes. For example, the NRC has imposed new and increasing requirements on the operation of our nuclear generation plants. Recent standards imposed or enhanced by the NRC focus on the safety and security at our plants, including additional fitness for duty standards, more stringent security rules, cybersecurity rules, and fire protection and emergency preparedness requirements. Similarly, in 2007 NERC replaced its voluntary reliability guidelines with a new mandatory compliance regime under the authority of the Federal Energy Regulatory Commission. Since that time, NERC has developed a number of new standards to manage and ensure the reliability of the electric grid, and we are now responsible for compliance with over 300 specific NERC requirements. In addition, compliance in and of itself is not sufficient we must be able to demonstrate and document compliance with each 6 Poferl Direct

11 requirement. Non-compliance can lead to substantial financial penalties. As a result, we are adding personnel, developing new documentation procedures, and adding or developing new information systems to track detailed compliance information. Q. HAS THE COMPANY WORKED TO MANAGE COSTS AND AVOID THIS REQUESTED RATE INCREASE? A. Yes, we have taken numerous steps to reduce and control our costs. For example, we have: Reduced travel and employee expenses from historic levels by implementing new procedures and limitations. Controlled supply chain costs by forming strategic supplier relationships. In addition, most areas are multiple sourced to ensure supply continuity and competition among suppliers. Limited the rate of medical cost increases by increased employee costsharing requirements, benefit reductions, and renegotiation of vendor contracts. Managed and offset labor cost pressures by a number of workforce deployment initiatives, such as strict management of overtime, employee replacements and hires, and work-planning efforts. We have controlled costs without compromising safety, reliability, or customer service. In fact, in recent years, we have exceeded the service quality standards set in our tariffs, have improved on our customer satisfaction measures, and have consistently improved our safety performance. Exhibit (JMP-1), Schedule 2 provides an overview of our performance. 7 Poferl Direct

12 Q. YOUR MOST RECENT ELECTRIC RATE CASE WAS BASED ON A 2009 TEST YEAR, WHICH WAS THE HEIGHT OF THE FINANCIAL DOWNTURN. HOW DID THE COMPANY RESPOND? A was an exceptionally challenging year for us, given reduced sales due to the economic downturn. Weather-normalized sales were 4.64 percent lower than the level assumed in our rate case, and actual sales were even lower as the result of cooler-than-normal summer weather. We worked throughout the year to manage our costs, reducing and deferring employee base pay increases, driving down employee expenses and consulting costs, delaying work that could be addressed in 2010, and finding new ways to operate our business more efficiently. Many of these initiatives were reflected in our 2009 test year costs, as we adjusted the deficiency throughout the case as certain initiatives became known. Although our overall costs for the year were lower than the level assumed in final rates, the Company still did not achieve the authorized rate of return on equity. Simply put, our cost management initiatives were not sufficient to offset the lower sales. In 2009, we reported an actual return on equity of 9.75 percent and a weather-normalized return on equity of percent, compared to an authorized return of percent. Although economic factors are stabilizing and slowly improving, our efforts created efficiencies and cost controls that we continue to employ. Consistent with that effort, each of our business area witnesses will identify, explain, and support all significant deviations from their 2009 costs in preparation for this case. We recognize the impact this case has on our customers, and have taken 8 Poferl Direct

13 significant care to explain and justify our costs to ensure transparency and support for our request. Q. PLEASE DESCRIBE YOUR PROPOSED RATE DESIGN FOR THIS CASE. A. We are not proposing significant changes to our current rate design, but are proposing to bring class rates moderately closer to cost responsibility. As noted above, we recognize the impact of our request to customers and seek to achieve a reasonable balance among classes. By not proposing any significant change to rate design, we ensure greater customer understanding and rate continuity. Q. WHAT IS YOUR RATE OF RETURN ON EQUITY REQUEST? A. Our proposed revenue requirement reflects an overall rate of return ( ROR ) on investment of 8.74 percent, based on an average common equity ratio of percent and a rate of return on equity ( ROE ) of percent. Mr. John J. Reed provides a detailed analysis of the appropriate overall ROR and ROE for the Company. He explains that the significant scale of our proposed capital investments and challenging capital market conditions makes it especially important that an adequate ROE is adopted in this proceeding. Q. PLEASE DESCRIBE THE SCALE OF YOUR PROPOSED CAPITAL INVESTMENTS. A. Through our Resource Plans and Certificate of Need filings, the Commission is aware of our significant capital investment program to modernize our generation fleet and increase the transmission capacity on our system. For example, we invested nearly $1 billion in our system in both 2008 and 2009, and expect to invest over $1 billion in each year between The projects underlying our investments have been shown to be necessary and 9 Poferl Direct

14 cost-effective. We believe these investments position us very well to meet the challenges of the future. Q. GIVEN THIS SIGNIFICANT CAPITAL INVESTMENT PROGRAM, WHAT IS THE IMPORTANCE OF THE LEVEL OF RETURN ON EQUITY? A. An appropriate ROE and a supportive state regulatory framework are key contributors to our ability to raise significant capital at reasonable rates. We will need to turn to the capital markets to support the required level of investment. Given the magnitude of investment we need to make in our system, we have a common interest with our regulators and customers in having the Commission both set an appropriate ROE and ensure we have a reasonable opportunity to earn that ROE. Absent these conditions, the cost of capital for the investments we need to make to serve our customers would be higher than otherwise necessary, increasing the rate impact on our customers. Q. WHAT VALUE DO YOUR CUSTOMERS RECEIVE FROM THESE INVESTMENTS? A. These investments position the Company very well to provide excellent service and manage the significant environmental, technology, and fuel price risks facing our industry. We have demonstrated in proceedings before the Commission that these investments are not only necessary to provide reliable, safe and high-quality electric service for our customers, but also that these projects are prudent investments relative to alternatives. The rate increases requested in this and future rate cases to support these investments would likely be greater and our ratepayers exposed to considerably more risk if we were to forego these planned investments in favor of those alternatives. Our early and on-going activities to prepare our system for the future allow us 10 Poferl Direct

15 to continue to provide our customers with great value, both now and over the long term. B Step-In and Rider Consolidation Q. ARE THERE OTHER COMPONENTS TO YOUR RATE REQUEST? A. Yes, there are two additional features that I would like to address. Our capital investment plans and forecasted growth will result in substantial revenue deficiencies after These deficiencies occur despite the recovery provided by rate riders for certain major investments (such as our CapX2020 transmission projects) because other major investments or cost pressures (such as nuclear life extension or power uprates) are not eligible for such rate treatment. We project these deficiencies to be between $95 million and $150 million each year from 2011 until Each annual deficiency by itself is of sufficient magnitude to warrant a rate case. It is important that we collectively begin to address how we will review and address these deficiencies through the regulatory process, and to manage the resulting rate impacts on our customers. To that end, we have two proposals that will help resolve our short-term issues, while giving us the opportunity to work with regulators, customers, and other stakeholders to develop a longer-term solution. They are: Rider Consolidation. We propose to simplify our use of rate riders by moving substantial costs from existing rate riders to base rates. Specifically, we propose to either zero out or reduce the amounts recovered through the riders and instead incorporate those costs into base rates. 11 Poferl Direct

16 Step-In Adjustment. We request an additional revenue requirement for This step-in rate adjustment would allow for recovery of known capital projects and certain O&M costs that occur during or just beyond the test year. Q. COULD YOU PROVIDE MORE DETAIL ON YOUR RIDER CONSOLIDATION PROPOSAL? A. Yes. As part of the settlement on the Metropolitan Emissions Reduction Project ( MERP ) projects, we agreed to zero out the Environmental Improvement Rider, which recovered the costs of MERP. In addition, we propose to zero out the State Energy Policy Rider (which recovers the costs of various energy policies and initiatives enacted by the Minnesota Legislature) and significantly reduce the Renewable Energy Standard Rider (which primarily recovers the costs of our owned wind projects). While these actions will not change the net amount paid by customers, it will move $158 million currently recovered under these riders into final general rates. In addition to these rider costs, we have also included in our request for the 2011 test year $11 million of new costs that would otherwise have been eligible for rider recovery $7 million in transmission costs and $4 million in mercury emission control costs. The reduction in the mercury rider allows us to zero out that rider as well. Q. WHAT IS THE BASIS FOR THIS RIDER CONSOLIDATION PROPOSAL? A. First, it implements the Settlement Agreement adopted by the Commission for the MERP project. That Settlement requires the costs of the projects to be rolled into base rates during the first rate case following a full year of implementation of that project. Second, I believe it is consistent with the 12 Poferl Direct

17 findings of the report the Commission submitted to the Minnesota Legislature earlier this year, titled the Utility Rates Study as Required by the Laws of Minnesota 2009, Chapter 110. Taking these actions will reduce the amount of costs we are recovering in multiple riders. In so doing, we reduce the administrative burden on our regulatory agencies and stakeholders to review all of our costs through multiple proceedings, addressing one of the issues raised by the Commission s report. Q. LET S TURN TO YOUR SECOND PROPOSAL REGARDING A 2012 STEP-IN AS PART OF FINAL RATES IN THIS PROCEEDING. A. Resolution of our 2011 request is essential, but it does not resolve the known and measurable revenue deficiencies we will experience in Specifically, we will experience a significant revenue deficiency immediately after the close of this rate case due to costs we will incur early in or before 2012 in four cost categories. These four categories are: Costs incurred for the Monticello Extended Power Uprate and Lifecycle Management project; Costs incurred for transmission plant that will go into service during 2011 Costs incurred for distribution plant that will go into service during 2011; and Nuclear plant outage costs, the majority of which are from outages in 2010 and 2011 that have been deferred and scheduled to be amortized over the useful life of the outage. In total, we request recovery of $48.3 million to be reflected in rates to recover these specific 2012 costs. Combined with the proposed 2011 increase 13 Poferl Direct

18 of 5.6 percent, the total increase for 2012 rates would be 7.4 percent over current rates. Q. HAS THE COMMISSION EVER APPROVED A STEP-IN ADJUSTMENT? A. Yes, the Commission has approved recovery of several non-test-year costs or events since 1980, and has considered others. While consideration of out-oftest-year expenses is context- and fact-specific, the Commission generally considers the following factors when making its determination: The cost component is known and measurable. The cost change occurs immediately after the close of the test year. The need is compelling. The step-in adjustment does not set current rates higher than current costs. Q. IS YOUR PROPOSED 2012 STEP-IN CONSISTENT WITH COMMISSION PRECEDENT? A. Yes, I believe so. Specifically: Our proposed step-in would recover costs that are quantifiable with a high degree of accuracy. It would recover the costs of known capital improvements and increased nuclear O&M that we believe our regulators will find reasonable, but are otherwise not recoverable outside of a general rate case. We will incur most of these costs prior to the end of this rate case, such that the full-year impact of these costs will be felt right after the close of the test year. The costs associated with the step-in adjustment will be part of the cost of providing service in Since the rates proposed in these 14 Poferl Direct

19 proceedings do not reflect these costs, without these adjustments the rates charged in 2012 will be deficient. The overwhelming majority of the costs associated with the step-in adjustment will be incurred prior to or very early in 2012, so 2012 rates will not reflect more costs than the Company incurs in that year. Indeed, the step-in represents only about half of our projected 2012 deficiency of approximately $100 million. Q. WHAT ARE THE BENEFITS OF ADOPTING OUR PROPOSAL? A. Absent approval of this step-in request, we would face the need to file for additional rate relief immediately after the close of this proceeding, as $100 million is far too great an amount to manage or absorb. I believe that finding a reasonable way to avoid a subsequent case is in the interests of all stakeholders. Specifically, approval of this 2012 step-in adjustment provides the far greater efficiency to both Company and regulatory agency resources, as we can use the review of this case to understand and justify the step-in costs. Further, this proposal will likely keep customer rates lower than they otherwise would be if we pursued subsequent-year rate cases; as I indicated, our proposed stepin is about half of our projected 2012 revenue deficiency. Finally, approval of this request provides us, our customers, our regulators, and other stakeholders the time and opportunity to work toward development of a longer-term, more sustainable resolution of our future deficiencies. 15 Poferl Direct

20 III. ADDRESSING FUTURE CHALLENGES Q. WOULD ADOPTING YOUR PROPOSALS RESOLVE ALL ISSUES ASSOCIATED WITH FUTURE REVENUE DEFICIENCIES AND LIKELY BACK-TO-BACK RATE CASES? A. Unfortunately, no. While a successful resolution of this case is of utmost importance to the Company, it only begins to address our going-forward revenue deficiencies. We project that our infrastructure investments and operational cost trends will continue to increase for the foreseeable future, while our sales will grow slowly. As noted previously, these dynamics will cause us to experience significant revenue deficiencies in each of the next several years, each of a sufficient magnitude to drive its own general rate case. Under the current ratemaking paradigm, this situation would require multiple rate cases and rate rider petitions. I don t believe this result is sustainable from the perspective of any stakeholder. Thus, we have a shared interest with our customers, regulators, and stakeholders to find mutually beneficial and sustainable solutions. We have researched what other utilities and regulators in similar situations have done to gain insight on possible regulatory frameworks to address these concerns. We have come to believe that a multi-year rate plan is well worth exploring as a possible solution. Q. PLEASE ELABORATE. A. The current ratemaking framework has done an excellent job of balancing the interests of customers, regulators and policymakers, utilities, investors, and other stakeholders. Under this model, regulators review factors affecting utility operations, scrutinize all revenue and cost categories, and establish just 16 Poferl Direct

21 and reasonable rates based on a representative test year of costs. Previously, this approach has worked well and rate cases have been relatively infrequent first, because utilities were growing into the systems built under previously set rates, and later, because Minnesota policymakers authorized recovery of certain costs outside of general rate cases, primarily to encourage utility investments that promote state energy policy goals. Now, however, utilities in Minnesota and around the country must make significant investments to modernize and expand capacity to meet customer needs, ensure reliable service, and improve environmental performance. At the same time, the use of rate riders has grown and now strains regulatory resources, perhaps to the point of inefficiency. This effect is especially realized when the rate riders are not sufficient to avoid rate proceedings, such that parties face both multiple rider proceedings and general rate cases. When our projected scale of investments and resulting revenue deficiencies are layered on top of this foundation, it becomes clear that a new ratemaking model will be needed. The goals of that new framework must be the same as that of the current framework ensuring just and reasonable rates, facilitating needed investments, and promoting efficiency of operations but must have additional flexibility and transparency to be able to meet the coming challenges. Q. WHAT IS THE RATIONALE BEHIND A MULTI-YEAR RATE PLAN? A. A multi-year rate plan builds on the current, cost-based ratemaking model. However, instead of considering a snapshot of a utility s revenues and costs during a single test year, a multi-year rate plan considers the costs and 17 Poferl Direct

22 revenues of a number of years in one proceeding. As such, it should create efficiencies in the regulatory process and provide greater insight into future costs for all stakeholders. Q. PLEASE ELABORATE. A. A primary benefit of a multi-year rate plan is that it allows customers and regulators to have a more accurate picture of a utility s costs and rates over time. Under the current regulatory regime, there can be a significant gap between the time an infrastructure investment has been approved by regulators and when the costs appear on customers bills. A multi-year plan can facilitate better understanding of the rate impact of such significant investment decisions; even though cost-effective resources are selected in such processes, a multi-year plan can make the cumulative impact of such decisions more transparent to all stakeholders. In addition, a multi-year plan can make the regulatory process itself less burdensome, reducing the number of rate cases and rate rider dockets that must be processed. Finally, incentives for prudent investments and operational efficiency can and should be incorporated into the design of a multi-year rate plan to ensure rates are as low as reasonably possible. Q. DO YOU PROPOSE A MULTI-YEAR RATE PLAN IN THIS CASE? A. No, not as a part of this case. Although a multi-year rate plan builds on the processes and standards in the current regulatory process, it is a significant change that must be carefully and broadly assessed to ensure successful implementation. Our current process provides significant protection to all stakeholders and has achieved great results; we must ensure that any change 18 Poferl Direct

23 to that process achieves comparable results, but facilitates the current infrastructure needs and cost trends. To encourage consideration of these issues, we have begun discussions with stakeholder to share interests, concerns, and ideas. In the coming weeks, we will make a filing outlining a potential framework and assessing these issues for the Commission to consider. That filing will ask the Commission to establish a workgroup or other collaborative forum to explore an alternative regulatory framework, identify issues and options, and develop principles the outcome of which would be an actionable proposal for the Commission s consideration. In addition, we may seek supportive legislation in the upcoming 2011 legislative session, clarifying the Commission s authority to approve such a plan. Q. WHAT ARE THE BENEFITS OF SUCH AN APPROACH? A. Cooperative efforts among a broad group of stakeholders have been the hallmark of our success in facilitating major energy initiatives in Minnesota. We are committed to using that same approach when addressing our current challenges. While timely resolution of these issues is important, we need to do so in a way that appropriately balances interests and achieves the great results our current processes have produced. The Company looks forward to working with stakeholders on this important effort, and we are confident it can achieve a successful outcome. IV. FILING FRAMEWORK Q. CAN YOU EXPLAIN HOW THE INITIAL FILING IS ORGANIZED? 19 Poferl Direct

24 A. Yes. Volume 1 contains our Notice of Change of Rates and Interim Rate Petition. Volumes 2A and 2B include the Direct Testimony and supporting schedules of each of the witnesses. Volume 2C contains our proposed Tariff sheets. Volume 3 includes the Required Financial Information. Volume 4 includes the workpapers primarily supporting the cost of service study prepared at the direction of Company witness Ms. Anne E. Heuer. Volumes 5 and 6 include the Budget Documentation relied on as the foundation of our test year. An additional volume of supplemental budget information is also provided. Q. WHAT PROCESS DID THE COMPANY USE TO IDENTIFY COMPLIANCE REQUIREMENTS IN THIS RATE CASE? A. To ensure the Company complied with all previous compliance requirements, we undertook a comprehensive review of prior proceedings and orders to determine compliance requirements for this case. Exhibit (JMP-1), Schedule 3 lists the relevant Commission directives from Orders since our previous rate case. In that Schedule, we also provide references to the portions of this Application that comply with the requirements. We believe we have exercised due diligence in ensuring full compliance with all Commission requirements for this proceeding. In addition, we have taken extra care in the preparation of this case, providing additional support for our requested costs in the testimony and exhibits of our witnesses. Q. COULD YOU PLEASE INTRODUCE THE WITNESSES THE COMPANY IS SPONSORING IN THIS PROCEEDING? A. Yes. In addition to my Policy Testimony, the Company sponsors the following witnesses: 20 Poferl Direct

25 Anne E. Heuer, who sponsors the overall revenue requirement for the rate case. Ms. Heuer will discuss the extra measures taken to ensure accuracy and integrity of the budget figures we used in this rate case. Ms. Heuer also sponsors the schedules supporting our income statement, rate base, revenue deficiency, and jurisdictional allocations. Her schedules incorporate and reflect the recommendations of a number of our witnesses, including the cost of capital and sales forecast. Richard A. Ostberg, who sponsors testimony on the 2012 step-in adjustment. George E. Tyson, II, who sponsors our capital structure, cost of debt, and overall cost of capital. John J. Reed, of Concentric Energy Advisors, who sponsors testimony on the ROE and ROR, including capital structure, and the cost of debt. Jannell E. Marks, who sponsors the sales forecast used in Ms. Heuer s determination of the revenue deficiency. David G. Horneck, who provides the short- and long-term view of our capacity forecast using the sales forecast prepared by Ms. Marks. Kimberly S. Locker, who sponsors our allocations from Xcel Energy Services Inc. to the Company. Ms. Locker also presents an overview of Xcel Energy Inc. and its subsidiaries organizational structure and a Cost Assignment and Allocation Manual that assigns and allocates costs between business units and jurisdictions within the Company. Dennis L. Koehl, who sponsors testimony regarding our nuclear program and the reasonableness of our nuclear-related O&M costs and capital investments. 21 Poferl Direct

26 Pamela K. Graika, who sponsors testimony supporting the reasonableness of O&M costs and investments related to energy supply. Ian R. Benson, who sponsors testimony providing an overview of recent and upcoming transmission investments and the O&M costs associated with operating a transmission network. Mr. Benson also describes the significant changes in NERC requirements and the impact on our costs. Lawrence R. Crosby, who supports the reasonableness of our O&M and capital expense associated with operating the distribution system. Emily A. Ahachich, who provides support for the overall business systems and information technology needs essential to the operations of our business, including all computer hardware, computer software, voice and data networks, and the software that facilitates the communication necessary between multiple systems. Michael C. Gersack, who provides testimony on the requested level of expenses related to all aspects of customer care and bad debt. Lisa H. Perkett, who provides testimony on depreciation and remaining lives for all plant and plant-related items. Darla Figoli, who sponsors testimony in support of our employee compensation and benefits policies, including incentive compensation, which helps manage labor costs while ensuring adequate and competitive compensation for our employees. Mark P. Moeller, who sponsors testimony about the level of our pension cost request and associated pension accounting. Phillip J. Zins, who sponsors our class cost of service study and selected rate design proposals. 22 Poferl Direct

27 Steven V. Huso, who sponsors the general rate design and tariff changes in this case. Together, these witnesses provide the information and advocacy needed to evaluate and approve our Application. V. CONCLUSION Q. PLEASE SUMMARIZE YOUR TESTIMONY. A. This rate request is needed to support infrastructure improvements to our system, to fund cost increases in health care, pension, and other costs that are related to trends in the overall economy, and to ensure compliance with increasing regulatory requirements. Our requested step-in adjustment would address four specific known and measureable costs in 2012, will help forestall another rate case immediately following this one, and will allow all parties more time to develop a longer-term, more sustainable regulatory framework. This effort will allow us to build on our past successes and address the issues we currently face. Q. PLEASE SUMMARIZE THE COMPANY S REQUEST TO THE COMMISSION. A. We respectfully request that the Commission approve: Our requested rates that provide a net increase of $150.1 million in revenues. An overall ROR on investment of 8.74 percent, based on an average common equity ratio of percent and an ROE of percent. Our rider consolidation proposal to move $158 million from various rate riders into base rates. 23 Poferl Direct

28 Our request for a 2012 step-in adjustment, to recover $48.3 million of known and measurable costs for that year. Our proposed rate design and tariffs. Q. DOES THIS CONCLUDE YOUR TESTIMONY? A. Yes, it does. 24 Poferl Direct

29 Judy M. Poferl CEO & President 414 Nicollet Mall Minneapolis, MN Exhibit (JMP-1), Schedule 1 Page 1 of 1 EDUCATION Master of Arts, Hubert H. Humphrey Institute of Public Affairs University of Minnesota, 1984 Bachelor of Arts, Government College of St. Benedict, 1982 CURRENT RESPONSIBILITIES I am responsible for electric and natural gas business operations within Northern States Power Company s Minnesota, North and South Dakota retail jurisdictions and accountable for customer service, financial and regulatory results. PREVIOUS RATE CASE TESTIMONY Company Docket Number Topic Xcel Energy E002/GR Policy Xcel Energy E002/GR Merger Synergies Capacity Additions Demand-Side Management Xcel Energy G002/GR Merger Synergies Partial Decoupling Filed on behalf of the Minnesota Department of Public Service (n/k/a Office of Energy Security): Northern States Power E002/CN Policy Northern States Power E002/GR Conservation Financial Incentives Load Management Minnesota Power E015/GR Contract Issues Interstate Power E001/GR Rate Design Northern States Power G002/GR ,165 Rate Design Interstate Power G001/GR Cost of Service Conservation Northern States Power E002/GR Cost of Service Western Gas G012/GR Rate Design

30 NSPM Safety, Reliability, and Service Quality Performance Exhibit (JMP-1), Schedule 2 Page 1 of 1 Performance Area Electric Reliability Safety Customer Satisfaction Measure System Average Interruption Duration Index ( SAIDI ) System Average Interruption Frequency Index ( SAIFI ) OSHA Recordable Incident Rate ( ORIR ) for NSPM Company Residential Customer Satisfaction (percent positive) 1 Customer Complaints to the Commission Telephone Response Time (percent of calls answered in less than 20 seconds) Standard in Tariff or Commission Rules 98 minutes or less Performance 2009 Performance 2010 Performance (through September, except as noted) or less N/A N/A 91% 93% 93% or less % or more % 84.8% 82.3% NOTES: All results, with the exception of the ORIR and Residential Customer Satisfaction metrics, are for the Minnesota jurisdiction of NSPM. Indicated Performance Results for SAIDI, SAIFI, Customer Complaints to the Commission, and Telephone Response Time are as reported in our Annual Service Quality Reports filed in Docket No. E,G002/CI on April 1, 2009, April 1, 2010, and in our monthly report filed October 25, 2010 in the same docket. Final 2010 performance results will be submitted to the Commission in April 2011, therefore, the numbers for 2010 listed above are subject to change. 1 Percent of Residential Customers who responded positively to a question regarding their overall satisfaction with NSPM. 2 Standards prescribed by our Service Quality Tariff, Electric Rate Book, General Rules and Regulations, Section 6, Sheet Numbers Standard prescribed by Minn. R , subp. 1 and our Service Quality Tariff. 4 Performance through July 2010.

31 1 of 36 Information Required by Commission Rule Minnesota Rules, Part General Information The utility s proposal for a change in rates shall summarize the notice of change in rates and shall include the following information: A. name, address, and telephone number of the utility without abbreviation and the name and address and telephone number of the attorney for the utility, if there be one; Volume 1 Notice of Change of Rates B. date of filing and date modified rates are effective; Volume 1 Notice of Change of Rates C. description and purpose of the change in rates requested; Volume 1 Notice of Change of Rates D. effect of the change in rates expressed in gross revenue dollars and as a percentage of test year gross revenue; and E. signature and title of utility officer authorizing the proposal Filing requiring determination of gross revenue. Volume 1 Notice of Change of Rates Volume 1 Notice of Change of Rates Subpart 1. Subpart 2. Summary. A utility filing a general rate case or other filing that requires determination of its gross revenue requirement shall include, on a separate page, a brief summary of the filing, sufficient to apprise potentially interested parties of its nature and general content. Service. A utility filing a general rate change request shall serve copies of the filing on the department and Residential Utilities Division of the office of the Attorney General. The utility shall serve the filing or the summary described in subpart 1 on the persons on the applicable general service list and persons who were parties to its last general rate case or incentive plan proceeding. Volume 1 Summary of Filing Volume 1 Certificate of Service

32 Page 2 of 36 Subpart 3. Information Required by Commission Rule Notice to public and governing parties. A utility seeking a general rate change shall give notice of the proposed change to the governing body of each municipality and county in its service area and to its ratepayers. The utility shall also publish notice of the proposed change in newspapers of general circulation in all county seats in its service area. Volume 1 Proposed Notices An unqualified agreement, signed by an authorized official of the utility, to refund to the customers or credit to customers accounts within 90 days from the effective date of the commission order any portion of the increase in rates determined to be unreasonable together with interest at the average prime interest rate computed from the effective date of the proposed rates through the date of refund or credit Revised or new pages to the rate book previously filed with the commission and by identifying those pages which were not changed. In addition, each revised page shall contain the revision number and the page number of the revised page Expert opinions and supporting exhibits shall include written statements, in question and answer format, together with supporting exhibits of utility personnel and other expert witnesses as deemed appropriate by the utility in support of the proposal. Volume 1 Agreement and Undertaking Steve Huso, Exhibit (SVH-1), Vol. 2C, Schedule 6. Volumes 2A, 2B, and 2C A jurisdictional financial summary schedule as required by part shall be filed showing: A. the proposed rate base, operating income, overall rate of return, and the calculation of income requirements, income deficiency, and revenue requirements for the test year; Anne Heuer, Exhibit (AEH-1), Vol. 2A, Schedule 6, and Vol. 3, Section II, Part 2.

33 Page 3 of 36 Information Required by Commission Rule B. the actual unadjusted average rate base consisting of the same components as the proposed rate base, unadjusted operating income, overall rate of return, and the calculation of income requirements, income deficiency, and revenue requirements for the most recent fiscal year; and C. the projected unadjusted average rate base consisting of the same components as the proposed rate base, unadjusted operating income under present rates, overall rate of return, and the calculation of income requirements, income deficiency, and revenue requirements for the projected fiscal year. Anne Heuer, Exhibit (AEH-1), Vol. 2A, Schedule 19, and Vol. 3, Section II, Part 2. Anne Heuer, Exhibit (AEH-1), Vol. 2A, Schedule 19, and Vol. 3, Section II, Part The following rate base schedules as required by part shall be filed: A. A rate base summary schedule by major rate base component (e.g. plant in service, construction work in progress, and plant held for future use) showing the proposed rate base, the unadjusted average rate base for the most recent fiscal year and unadjusted average rate base for the projected fiscal year. The totals for this schedule shall agree with the rate base amounts included in the financial summary. Anne Heuer, Exhibit (AEH-1), Vol. 2A, Schedule 19, and Vol. 3, Section II, Part 3, Tab A. B. A comparison of total utility and Minnesota jurisdictional rate base amounts by detailed rate base component showing: (1) total utility and the proposed jurisdictional rate base amounts for the test year including the adjustments, if any, used in determining the proposed rate base; (2) the unadjusted average total utility and jurisdictional rate base amounts for the most recent fiscal year and the projected fiscal year. Anne Heuer, Exhibit (AEH-1), Vol. 2A, Schedule 19, and Vol. 3, Section II, Part 3, Tab B, Schedule B-1. Volume 3, Section II, Part 3, Tab B, Schedule B-1

34 Page 4 of 36 Information Required by Commission Rule C. Adjustment schedules, if any, showing the title, purpose, and description and the summary calculations of each adjustment used in determining the proposed jurisdictional rate base. D. A summary by rate base component of the assumptions made and the approaches used in determining average unadjusted rate base for the projected fiscal year. Such assumptions and approaches shall be identified and quantified into two categories: known changes from the most recent fiscal year and projected changes. E. For multijurisdictional utilities only, a summary by rate base component of the jurisdictional allocation factors used in allocating the total utility rate base amounts to the Minnesota jurisdiction. This summary shall be supported by a schedule showing for each allocation factor the total utility and jurisdictional statistics used in determining the proposed rate base and the Minnesota jurisdictional rate base for the most recent fiscal year and the projected fiscal year. Volume 3, Section II, Part 3, Tab C Volume 3, Section II, Part 3, Tab D Volume 3, Section II, Part 3, Tab E The following operating income schedules as required by part shall be filed: A. A summary schedule of jurisdictional operating income statements which reflect proposed test year operating income, and unadjusted jurisdictional operating income for the most recent fiscal year and the projected fiscal year calculated using present rates. B. For multijurisdictional utilities only, a schedule showing the comparison of total utility and unadjusted jurisdictional operating income statement for the test year, for the most recent fiscal year and the projected fiscal year. In addition, the schedule shall provide the proposed adjustments, if any, to jurisdictional operating income for the test year together with the proposed operating income statement. Volume 3, Section II, Part 4, Tab A Volume 3, Section II, Part 4, Tab B

35 Page 5 of 36 Information Required by Commission Rule C. For investor-owned utilities only, a summary schedule showing the computation of total utility and allocated Minnesota jurisdictional federal and state income tax expense and deferred income taxes for the test year, the most recent fiscal year, and the projected fiscal year. This summary schedule shall be supported by a detailed schedule, showing the development of the combined federal and state income tax rates. D. A summary schedule of adjustments, if any, to jurisdictional test year operating income and detailed schedules for each adjustment providing an adjustment title, purpose and description of the adjustment, and summary calculations. E. A schedule summarizing the assumptions made and the approaches used in projecting each major element of operating income. Such assumptions and approaches shall be identified and quantified into two categories: known changes from the most recent fiscal year and projected changes. F. For multijurisdictional utilities only, a schedule providing, by operating income element, the factor or factors used in allocating total utility operating income to Minnesota jurisdiction. This schedule shall be supported by a schedule which sets forth the statistics used in determining each jurisdictional allocation factor for the test year, the most recent fiscal year, and the projected fiscal year. Volume 3, Section II, Part 4, Tab C Volume 3, Section II, Part 4, Tab D Volume 3, Section II, Part 4, Tab E Volume 3, Section II, Part 4, Tab F The following rate of return cost of capital schedules as required by part shall be filed: A. A rate of return cost of capital summary schedule showing the calculation of the weighted cost of capital using the proposed capital structure and the average capital structures for the most recent fiscal year and the projected fiscal year. This information shall be provided for the unconsolidated parent and subsidiary corporations, or for the consolidated parent corporation. Volume 3, Section II, Part 5, Tab A