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6.1a ERMUSR 08-14-2018 Elk River Municipal Utilities UTILITIES COMMISSION MEETING TO: FROM: ERMU Commission Troy Adams, P.E.— General Manager MEETING DATE: AGENDA ITEM NUMBER: August 14, 2018 6.1a SUBJECT: Staff Update ACTION REQUESTED: None DISCUSSION: • The Board of Directors of the Minnesota Municipal Power Agency (MMPA) met on July 24, 2018 at the offices of Elk River Municipal Utilities. Commissioner Al Nadeau and I were both in attendance. The unaudited MMPA financial report for 2Q2018 is attached. The MMPA Application For Integrated Resource Plan (IRP) Approval 2019—2033 has been submitted to the Minnesota Public Utilities Commission. The public version of the IRP is attached. Fitch Ratings upgraded MMPA's bond rating from "A" to "A+", citing the Agency's strong financial performance, effective management, and competitive rates. Moody's upgraded MMPA's bond rating from "Al"to "A2" with a stable outlook. The Fitch and Moody's rating reports are attached. The Board was informed that the Manitoba Hydro Board of Directors approved the capacity agreement in which MMPA will purchase between 65 MW and 105 MW over the period 2020 to 2030. Participation in MMPA's residential Clean Energy Choice program increased over June, with four different MMPA members having new customer signups during the month. Customer penetration of MMPA's Clean Energy Choice program for residential customers increased to 2.9%. Following the Board meeting, MMPA hosted its annual dinner meeting with city officials at the Rockwoods event center in Otsego, Minnesota, located in Elk River Municipal Utilities' service territory. The MMPA annual report for 2017 was released. The report is attached. Page 1 of 3 65 A representative from MMPA will be presenting to the Elk River Rotary on July 12 regarding the Clean Energy Choice program. Staff has met with representatives of MMPA regarding the implementation of this program. • On August 6 I participated in a Moody's bond rating call with Theresa Slominski, Lori Ziemer—City of Elk River Finance Director, and Terri Heaton— Springsted. The call is in preparation to bond sales for the second part of ERMU's MMPA buy-in. A few notes of importance from the call: o This is not a new expense, but rather a replacement for an existing expense. Therefore it doesn't result in an increase to rates. And the bigger ERMU gets through growth, the bigger the savings between Great River Energy (GRE) and MMPA. o The bonds are not general obligation; they are electric revenue bonds which do not impact the city or their ability to issue debt. o There's a"net revenues available for debt service" test that requires 1.25 time coverage. ERMU greatly exceeds that requirement with 5.12 times coverage. o Being designated as an American Public Power Association (APPA) Reliable Public Power Provider (RP3) utility was noted as being extremely positive from Moody's. They know APPA and the RP3 program well. o ERMU's growth and the City of Elk River's growth were noted as positives. o MMPA's recent rating upgrade from Fitch and from Moody's was noted. Moody's is going to have their MMPA analyst sit on the committee for ERMU's rating review; this is a good thing for us. Moody's will do their review the week of August 13 and provide their report the week of August 20. • Over the past month I have spent significant time working on Wage & Benefit Committee preparation and hiring. • I attended the Minnesota Municipal Utilities Association (MMUA) board meeting at their new office in St.Paul to review the draft 2018/2019 budget and the report from the cost of service initiative. • The MMUA Summer Conference is August 20-22 in Alexandria, MN. I will be presenting with John Miner on governance policy. I will officially roll off the MMUA board after the business meeting at the end of this conference. • The MMUA Technical & Operations Conference will be December 4-6 in St. Cloud. I will be presenting on a panel about employee retention and wages. • On July 6 ERMU, MMPA and GRE held another wholesale power migration conference call. Most items regarding the transition are resolved in either concept or implementation. A few remaining issues include the electric service GRE utilized from ERMU Substation 14 Bank 3 and issues/considerations regarding the fate of the GRE Energy Station generation facility and related facilities. There is a Joint Pricing Zone (JPZ) agreement which needed to be modified to reflect ERMU's transition to MMPA. This JPZ provides for transmission Midcontinent Page 2 of 3 66 Independent System Operator(MISO) transmission revenue distribution and network transmission service within the GRE MISO zone. This revised JPZ has been agreed upon and executed by all signatories and has been submitted to the Federal Energy Regulatory Commission (FERC) for approval. It is expected to be approved within 60 days. I have a copy of this 87 page submission to FERC but have not included it as an attachment to this memo. Please let me know if you are interested in reviewing this public document. This workgroup has scheduled their next meeting for August 27. • On July 22 I met with Tim Sullivan, President& CEO at Wright-Hennepin Cooperative Electric Association (WH). We meet annually to discuss legislative advocacy, issues, and opportunities. ERMU boarders WH in Otsego. ERMU and WH share a substation in Otsego as well. • On August 8 the city, county, and ERMU held a semi-annual fiber ring meeting to review our co-ownership of the eight miles of communication fiber within Elk River. • Information security committee's policy subcommittee met on August 6 to review policy draft. The next policy draft review meeting is scheduled for October 8. ATTACHMENTS: • MMPA— Second Quarter 2018 Unaudited Financials • MMPA—Application For Integrated Resource Plan— Public Version • MMPA—Fitch Rating Report • MMPA—Moody's Rating Report • MMPA—2017 Annual Report Page 3 of 3 67 Minnesota Municipal Power Agency Statement of Net Position As of June 30,2018-Unaudited Assets Current assets: Cash and cash equivalents $ 41,508,209 Restricted cash and cash equivalents 10,529,971 Accrued interest receivable 155,730 Power sales and other receivables 11,948,974 Fuel inventory 832,838 Plant inventory-spares 2,814,399 Prepaid expenses 1,072,345 Total current assets 68,862,466 Noncurrent assets: Capital assets: Electric generation assets 426,724,987 Land 7,066,719 Less accumulated depreciation (120,508,968) Property and equipment,net 313,282,738 Construction in progress 1,496,379 Total capital assets,net 314,779,117 Restricted cash,cash equivalents,and investments 19,705,474 Prepaid expenses 738,474 Future recoverable costs 47,421,118 Total noncurrent assets 382,644,183 Total assets 451,506,649 Deferred Outflows Deferred outflows of resources 1,687,994 Total assets and deferred outflows of resources $ 453,194,643 Liabilities Liabilities: Current liabilities: Accounts payable and accrued liabilities $ 11,147,653 Accrued interest payable 3,066,121 Long-term debt due within one year 9,923,333 Capital lease liability due within one year 1,000,587 Derivative instruments-futures 216,540 Total current liabilities 25,354,234 Long-term debt,net 274,230,457 Capital lease liability 17,513,721 Derivative instruments-futures 79,910 Total noncurrent liabilities 291,824,088 Total liabilities 317,178,322 Deferred Inflows Deferred inflows of resources-rate stabilization 33,071,000 Deferred inflows of resources-other 18,174,818 Total liabilities and deferred inflows of resources 368,424,140 Net Position Net position: Net investment in capital assets 38,791,317 Restricted for debt service 10,529,971 Unrestricted 35,449,215 Total net position 84,770,503 Total liabilities and deferred inflows of resources and net position $ 453,194,643 68 Minnesota Municipal Power Agency Statements of Revenues, Expenses and Changes in Net Position YTD June 30, 2018 -Unaudited Operating revenues—power sales to members $ 57,614,762 Operating revenues—power sales to non-members 670,601 Total operating revenues 58,285,363 Operating expenses: Power acquisition expense 22,577,736 Transmission 8,637,741 Other operating expenses 13,288,645 Depreciation 7,204,138 Total operating expenses 51,708,260 Operating income (loss) 6,577,103 Nonoperating revenues (expenses): Amortization of premium on long-term debt, net 566,291 Interest expense (6,723,551) Investment income 706,179 Loss on disposition of property (660,452) Loss on bond investment redemption (41,745) Net change in the fair value of investments (422,031) Total nonoperating revenues (expenses), net (6,575,309) Change in net position before future recoverable costs 1,794 Future recoverable costs 2,380,080 Change in net position 2,381,874 Total net position,beginning of year 82,388,629 Total net position,June 30,2018 $ 84,770,503 69 PUBLIC DOCUMENT TRADE SECRET DATA HAS BEEN EXCISED • A 'A nr .so`,a Municipal PcfNei- Agency APPLICATION FOR INTEGRATED RESOURCE PLAN APPROVAL 2019 - 2033 SUBMITTED TO THE MINNESOTA PUBLIC UTILITIES COMMISSION July 30, 2018 70 Table of Contents Section 1. Executive Summary 1 Section 2. About MMPA 3 Section 3. Business Environment 6 Section 4. Projected Energy Requirements—2019 to 2033 11 Section 5. Projected Demand Requirements—2019 to 2033 16 Section 6. Energy Conservation and Demand Side Management 24 Section 7. Existing Resources 28 Section 8. Additional Capacity Requirements 33 Section 9. Planning Approach 34 Section 10. Short-Range Plan 35 Section 11. Long-Range Plan 36 Section 12. RES Compliance and Rate Impact 37 Section 13. MMPA's Plan Is in The Public Interest 40 Appendix A. Load Projection Methodology A-1 Appendix B. Advance Forecast B-1 Appendix C. Renewable Energy Standard Rate Impact Report C-1 Appendix D. Regulatory Requirements Cross Reference Index D-1 Appendix E. Acronyms Index E-1 71 Section 1. Executive Summary This section is intended to provide a brief overview of the Minnesota Municipal Power Agency's (MMPA)Integrated Resource Plan (IRP). Electric Utility The electric utility industry is in a period of transition. The industry Industry in is experiencing a shift in the following areas: Transition • Decreasing cost of generation resources such as battery storage systems, solar, and wind; • Advancements in hardware and software technologies; and • Stagnant load growth; This transitional environment creates uncertainty in planning. Section 9 discusses MMPA's Planning Approach. Begin Serving Elk Elk River Municipal Utilities(ERMU) became the twelfth member River Municipal of MMPA in June 2013. ERMU serves 11,400 metered electric Utilities in October customers and has a peak demand of approximately 65 MW. 2018 MMPA's electrical power load is projected to increase by approximately 20 percent with the addition of ERMU. The Agency will begin providing wholesale power to ERMU on October 1, 2018, under a power sales agreement that runs through 2050. MMPA Strives to The Agency strives to meet its conservation goal for reducing Meet Its electricity use of its members' customers. MMPA focuses on Conservation Goal conservation strategies with the lowest cost per kWh of electricity saved. MMPA's conservation programs are discussed in Section 6 under Energy Conservation and Demand Side Management. Energy and Demand MMPA's energy and demand growth are projected to be lower than Growth Projected to historical levels. The 2004-2017 historical compounded annual Be Lower Than energy growth rate was 1.8%, whereas the projected annual energy Historical Levels growth rate for 2019-2033 is 0.8%. The 2004-2017 historical growth rate for non-coincident peak(NCP) demand was 1.4%, whereas the projected growth rate for 2019-2033 is 0.8%. The slower growth rates are attributed to projected population slowdowns and improved conservation efforts, among other factors. The table below shows MMPA's projected annual growth for energy,NCP demand, and coincident peak(CP) demand with the Midcontinent Independent System Operator(MISO). 72 2019-2033 Energy Growth 0.8% NCP Growth 0.8% CP Growth 0.8% Sections 4 and 5 and Appendix A provide further details on the projections and projection methodology. No Capacity Needed The Agency does not need capacity until planning year 2030. Since Until Planning Year capacity is not needed for the next eleven years, at the direction of 2030 the Department of Commerce staff, an evaluation of resource alternatives was not conducted for this IRP. However, MMPA will continue to evaluate the energy market to understand options to meet its future electric supply needs. Capacity requirements are discussed in Section 8. The short-range action plan is discussed in Section 10 and the long-range plan is presented in Section 11. MMPA Is Positioned MMPA is positioned to meet the Renewable Energy Standard to Meet the RES (RES). Since the last IRP the Agency has added the following renewable resources to its portfolio: • 78 MW Black Oak Getty Wind Farm (2016), • 7.1 MW AC utility-level solar facility, Buffalo Solar(2017) In addition, MMPA signed a power purchase agreement(PPA)for 170 MW of wind that is anticipated to be commercially available in December 2019. Section 12 addresses meeting the RES as well as the rate impact of complying with the RES. MMPA's Plan Is in MMPA's IRP is in the public interest. The Agency's plan allows The Public Interest MMPA to maintain flexibility during this electric industry transition period,reducing risks to its customers while keeping rates as low as practicable. MMPA's plan also minimizes negative environmental impacts through its emphasis on conservation and renewable energy. Section 13 further describes how MMPA's plan is in the public interest. 73 Section 2. About MMPA This section provides overview information about the Minnesota Municipal Power Agency. MMPA Is a MMPA is a municipal power agency formed in 1992 under Chapter Municipal Power 453 of Minnesota Statutes. The Agency is a political subdivision of Agency the state of Minnesota. MMPA provides electricity to its municipal utility members and they in turn sell that electricity to residential and business customers in their community. MMPA began supplying power to its members in 1995. MMPA is governed by a board of directors. Has 12 Member MMPA is composed of the following twelve Minnesota Cities communities: • Anoka • Arlington • Brownton • Buffalo • Chaska • East Grand Forks • Elk River • Le Sueur • North St. Paul • Olivia • Shakopee • Winthrop MMPA's member municipal utilities have approximately 74,000 retail customers in Minnesota with a combined population of approximately 160,000. MMPA Is Mission- MMPA's mission is to provide reliable, competitively-priced power Driven to its members and to create value for both the Agency and its members. In addition, MMPA is committed to supporting the communities it serves and does so by offering an energy education program, developing local power generation in member communities,providing conservation and renewable energy programs to members' customers, and converting waste from its 74 member communities into electricity at the Hometown BioEnergy facility. MISO Market MMPA is a market participant with MISO, a Federal Energy Participant Regulatory Commission (FERC) regulated regional transmission organization that provides grid management services and open access to transmission facilities for the midcontinent market. MMPA is a registered generation owner and load serving entity and is responsible for submitting demand bids and generation resource offers on behalf of its members. MMPA participates in MISO zone 1. Projected to Sell MMPA is projected to sell 1,925,452 MWh of energy in 2019. In 1,925,452 MWh in 2017, MMPA sold 1,515,800 MWh of energy. The increase in 2019 energy sales is largely from the addition of Elk River as a member community. MMPA will begin serving Elk River in October 2018. 2019 Projected Peak MMPA projects a peak load of 440 MW in 2019. MMPA's peak Load of 440 MW load during the summer of 2017 was 344 MW on July 17, 2017. This load includes adjustments for transmission system losses, the MISO planning reserve margin, Western Area Power Administration (WAPA) allocations, and CIP savings. First Owned Plant Faribault Energy Park(FEP), the first power plant to be owned by Completed In 2007 the Agency, was completed in 2007. The plant was built in two phases. The 159 MW simple cycle phase became operational in April 2005. The combined cycle phase, which increased both the capacity and fuel efficiency of the plant, became operational in the summer of 2007. MMPA's ownership of FEP marked a transition from a resource portfolio based solely on contracts to one that also includes Agency-owned assets. FEP is described in more detail in Section 7. First Owned Wind Oak Glen Wind Farm (OGWF) is MMPA's first owned wind farm. Farm Completed in It is 44 MW and located near Blooming Prairie, Minnesota. It was 2011 awarded a U.S. Department of Energy"2012 Public Power Wind Award"for leadership, innovation, project creativity, and benefits to customers. OGWF's innovative ownership and financial structure also qualified the wind project to receive a$25.4 million federal grant. OGWF is described in more detail in Section 7. 75 Became a MISO MMPA became a transmission owning member of MISO in 2013. Transmission Owner The Agency is the transmission owner of facilities in Chaska and in 2013 Anoka. Committed to MPPA is committed to economic renewable energy generation. In Renewable Energy 2025, MMPA anticipates that 53% of its wholesale sales will come from renewable resources. MMPA's renewable energy sources include wind, solar, and bioenergy. Avant Energy Minnesota Municipal Power Agency is governed by a board of Manages MMPA directors and Avant Energy provides management services to the Agency under long-term contracts. Avant's services to MMPA include: • Day-to-day management of operations including electricity purchasing and selling; • Overall long-term strategic planning and management; and • Accounting and financing. 76 Section 3. Business Environment This section discusses the business environment in which MMPA operates. MMPA's IRP recognizes electricity market uncertainties that influence planning decisions. Energy Industry in The energy industry is going through a period of transition that Transition includes: • Decreasing cost of generation resources such as battery storage systems, solar, and wind generation that allow these generation technologies to better compete with traditional fossil fuel-fired generation; • Advances in hardware technology such as smart meters, as well as software technology such as energy management systems, that utilize artificial intelligence allowing customer access to real-time energy consumption information and providing better decision-making tools for utilities and their customers; • Evolution of customer preferences where more utility customers than ever before express increased interest in their utilities procuring energy from cleaner sources of energy; and • Scaling back of federal environmental regulations on one hand and ramping up of corporate commitment to solving environmental issues on the other. The aforementioned transition in the energy markets and the uncertainties of the future trajectory of delivering cost effective, reliable power with small or no environmental impact contribute to a challenging planning environment. Low Natural Gas Natural gas prices are low. The shale revolution continues to put Prices downward pressure on near to medium term gas prices. The U.S. became the largest producer of petroleum and natural gas in the world in 2012. The U.S. now produces nearly all the natural gas it consumes. Some studies project the share of shale in U.S. natural gas production is projected to rise to 45% by 2035. Despite the robust near-term supply of natural gas, long term prices are less certain because of factors such as coal to gas switching, increased consumption from industrial and commercial production, possible environmental regulations, and increase in LNG and oil exports. 77 U.S.Retail Electric Stagnant growth of electric sales presents planning challenges for Sales Stagnant many utilities. Recent Energy Information Administration(EIA) data show that since 2003, overall retail electricity sales have risen by less than 5.5%. However, between 2007 and 2017, there was a decrease, albeit small, in overall retail electricity sales. EIA reported that between 2003 and 2017, slight residential and commercial user growth was offset by a decline in industrial users' sales. Below are two graphs that show this phenomenon. Annual U.S.Retail Sales of Electricity 4,000,000 3,500,000 3,000,000 3 2,500,000 2,000,000 1,500,000 1,000,000 500,000 0 Source:U.S.Energy Information Administration Annual U.S. Retail Sales of Electricity by Sector 1,600,000 1,400,000 , �•. 1,200,000 1,000,000 0 800,000 600,000 —Residential 400,000 —Commercial 200,000 Industrial 0 Source:U.S.Energy Information Administration 78 EPA Emissions Possible changes to U.S. Environmental Protection Agency(EPA) Standards Uncertain emissions standards increase planning uncertainties. The EPA's Mercury and Air Toxics Standards (MATS) Final Rule, issued in April 2013, established emission limits for mercury, particulate matter, sulfur dioxide, acid gases, and certain individual metals for new power plants. The MATS Rule was expected to particularly affect the cost of future coal and oil-fired power plants if it fully went into effect. After reviews by courts, the D.C. circuit court suspended the case indefinitely. In 2015, the EPA also reviewed the research linking smog exposure to adverse health effects such as asthma. Subsequently, the EPA updated the ozone rules with stricter limits to tighten standards on ozone from 75 parts per billion (ppb)to 70 ppb. In a court filing in April 2017, the federal government said the EPA officials appointed by the new administration were reviewing the 2015 rule to determine whether the EPA should reconsider some or all of the rule. In addition, the federal government is reviewing the Clean Power Plan, which aims to cut emissions from existing power plants by 32% by 2030, and the Waters of the United States (WOTUS) rule. These emissions standards and rules could be scaled back or eliminated. In March 2017, in a broad executive order on energy,the Interagency Working Group on the Social Cost of Greenhouse Gases was disbanded. This order withdrew the group's technical documents that form the scientific and economic basis for calculating the social cost of carbon and provide federal agencies a key tool to measure the benefits of cutting greenhouse gas emissions. While the absence of guidance from the federal government on the cost of carbon and other emissions could lead to confusion in certain types of planning scenarios, the Minnesota Public Utilities Commission has established emission costs. The costs are in its order Updating Environmental Cost Values issued on January 3, 2018 and in its order Establishing 2018 and 2019 Estimate of Future Carbon Dioxide Regulation Costs issued on June 11, 2018. Initiatives to While the federal government has indicated a desire to the scale Decrease Carbon back or eliminate environmental regulations, individual states and Emissions some cities are taking initiatives and setting goals and rules to first cap and then decrease carbon emissions from certain sectors of their economies. In Minnesota,the legislature has a state CO?reduction 79 goal of 30% by 2025 and 80% by 2050 (Minn. Stat. § 216H.02). Some of the largest cities in the U.S, including New York, Chicago, Atlanta and more than 30 others have also set ambitious emissions reductions goals. Generation In January 2017, the Federal Energy Regulatory Commission Interconnection (FERC)conditionally approved Queue Reform 4.5 which revises the Risks MISO generation interconnection process. Queue Refoim 4.5 aims to improve the timeliness and efficiency of the interconnection process. MISO continues to incorporate Queue Reform 4.5 into the active interconnection study cycles and its Business Practices Manuals. Timing and cost risks from the generation interconnection process persist during implementation of queue reform and may remain into the near future. MISO launches two cycles of new interconnection study groups each year for different regions. Many of the active interconnection study groups are seeing delays in the cycle process schedule. It is unknown when or if the queue reform will improve the timeliness of the interconnection process. This creates planning challenges for interconnection timing. A provisional interconnection alternative exists,but this option could create operational and transmission upgrade cost risks. MISO Market MISO is the entity that manages the reliable and cost-effective Enhancements delivery of electricity and conducts transmission planning activities Continue in 15 states, including Minnesota, and the Canadian province of Manitoba. MISO commenced its market operations for energy and financial transmission markets in 2005, followed by ancillary services markets in 2009, and capacity markets in 2010. Since its inception, MISO has continued to introduce or propose market enhancements and rule changes. In 2011, MISO introduced the concept of a dispatchable intermittent resource (DIR) to address the uncertainties associated with the intermittency of wind resources. At that time, MISO had less than 10,000 MW of registered wind generation. MISO now hosts over 17,500 MW of registered wind. Over 12,500 MW of this wind is in Iowa, Minnesota, and North Dakota and MISO has managed the concentrated wind resources, locational prices, and reliability effectively. MISO is now in the process of incorporating energy storage into its markets and complying with FERC orders 841 and 845. On April 3, 2017, MISO made a compliance filing with FERC where it revised Module A of its Tariff to add a new term called Stored Energy 80 Product Type 2 that would participate in energy, capacity, and ancillary service markets through the storage and discharge of electrical energy in response to set point instructions. While the above market enhancements seem to address some of the immediate concerns of market participants, other enhancements have not had the desired effect. For instance, in 2013, MISO administered its first annual capacity auction. The system wide clearing price of$1.05 per megawatt-day for the 2013-2014 planning year reflected ample supply of generation and demand response resources in MISO and the robustness of the transmission system. The system-wide clearing price for the 2018-2019 planning year was $10.00 per megawatt-day for all zones except zone 1, which cleared at$1.00 per megawatt-day. Both clearing prices from the most recent MISO auction are low and suggest the abundance of capacity in the near term. However, the absence of long-term capacity markets and price signals for the cost of long-term capacity create planning challenges and discourage long-teiiu investment. The Independent Market Monitor(IMM)that monitors market activity in MISO reported in its 2016 State of the Market Report for the MISO Electricity Markets: "Capacity market design issues described in this report have contributed to understated price signals, which will become an increasing concern as the capacity surplus falls due to retirements and units exporting capacity to PJM. Economic In the context of long-term planning, uncertainty exists because of Uncertainty high budget deficits,the unknown future of entitlement programs, Necessitates Planning the rising cost of living, the challenges addressing climate change, Flexibility and deregulation. Increased economic uncertainty therefore necessitates the need for flexibility in energy supply planning. 81 Section 4. Projected Energy Requirements — 2019 to 2033 This section discusses MMPA's historical and future energy requirements. Historical 1.8% Over the period 2004 to 2017, MMPA member energy requirements Energy Growth grew at a compound annual growth rate of approximately 1.8% for Rate all twelve MMPA members. The following graph shows historical MMPA member energy requirements for the years 2004 to 2017, the time period for which data is available for all twelve member cities. MMPA only served a portion of Shakopee's load until 2009. Therefore, the data has been adjusted to include all of Shakopee's load. MMPA has not historically served Elk River, but the data has been adjusted to include this load. Minnesota Municipal Power Agency Historical Member Energy Requirements (MWh) 3.000.000 2.5 00.000 2.000.000 T 1.500.000 1,000.000 500.000 0 O X00 00� 0 0-� �OOQ 0�0 - 0' 0' �0�� 0 0 O~^ r r 1r r �r r r r �r ti ti MMPA Will Begin MMPA will start providing electric service to Elk River in October Serving Elk River in 2018. The significant step up in projected energy in 2018 and 2019 October 2018 is attributable to this load addition. 82 Linear Regression A linear regression model was used to project energy usage for this Model Used to IRP. The variables in the model are: Project Energy • Weather(heating degree days and cooling degree days) • Population • Income per capita Details on the inputs and assumptions of the methodology can be found in Appendix A. Projected 1.8% MMPA's projected energy growth rate without new conservation is Energy Growth 1.8% for the 2019-2033 projection period. The following graph Rate without New shows historical and projected MMPA base energy requirements, Conservation without conservation adjustments, for the period 2004 to 2033. Minnesota Municipal Power Agency Historical& Projected Base Member Energy Requirements (MWh) Without Conservation 3,000.000 2,500,000 2,000.000 1,500,000 1,000,000 Historical Projected 500.000 0 CO 1�pb��`O��;• L�1, Li`l ti�~4 ti�LO ti�yL ti�•14 ti�y ti�1 ti��O ,s'1, New Conservation New conservation measures are assumed to reduce the Agency's Assumed to Reduce annual energy growth rate by approximately 1.0%. For further Annual Energy clarification,the base case of 1.3%conservation does not translate Growth Rate into a 1.3%reduction in the energy growth rate because the By 1.0% requirements for CIP savings calculations are based upon a lagging 3-year average of MMPA's energy consumption. MMPA's current level of energy conservation is built into the historical energy usage data that is an input into the linear regression model. Section 6 discusses in detail MMPA's current and future conservation efforts. 83 Lower CIP Savings MMPA continues its successful conservation improvement program Would Increase and strives to meet its CIP goals in the future. However, planning Energy Requirements processes need to take into consideration the uncertainties associated with longer-term effectiveness of CIP programs and the possibility of diminishing returns. This IRP contemplates three conservation rate cases for planning purposes: • 1.0% Low Case • 1.3% Base Case • 1.5% High Case Lower CIP savings in the future would increase energy requirements. The following chart shows MMPA's energy requirements for the three CIP savings cases: Minnesota Municipal Power Agency Projected Conservation-Adjusted Member Energy(MWh) 2,300,000 2,200,000 2.100.000 2,000,000 1,900.000 0 1,800.000 1,700.000 1,600,000 -4-1.0%Conservation —�-1.3%Conservation 1,500,000 1.5°O Conservation 1,400,000 ^O�b s,, ^OlO tib^`��1,�01^>'19 "9 n�ti��o1''19 '19 �or14 19 '19 �On�O ti�^`�O� ^;') '19 MMPA's CIP efforts and corresponding results are discussed in Section 6. Lower Population Slower population growth correlates with slower load growth in the Growth Rate Would energy projections. Historical and projected population compounded Lower Electric Load annual growth rates (CAGR) for MMPA member cities are shown Growth in the table below. Projections are based on Woods and Poole long term growth rates. Population growth rates are projected to be lower 84 than historical population growth rates for all MMPA members. [TRADE SECRET DATA BEGINS TRADE SECRET DATA ENDS] Additional Members MMPA's projected energy requirements would increase if the Would Increase Agency were to take on additional members. This IRP assumes that Energy Requirements the 12-member Agency does not take on any additional members during the projection period. Large Retail Load MMPA's projected energy requirements would increase if its Additions Would members were to take on new large retail loads. This IRP does not Increase Energy include any new large retail loads during the projection period. Requirements Less Supply from Two of MMPA's members currently receive allocations of energy WAPA Would (approximately 95,000 MWh per year) from the Western Area Increase Energy Power Administration (WAPA). Both members have long-term Requirements contracts for these energy allocations. However, WAPA could reduce the amount of energy and power available to its customers in the future. This would represent a policy change from the past. If WAPA decreases the energy available to its customers, MMPA's energy requirements would increase, because the Agency provides all of the energy to these two members that is not supplied by WAPA. This IRP assumes that WAPA allocations remain at the current contract amounts throughout the projection period. More Electric Use for In previous IRPs, we discussed electricity used as a fuel for Transportation transportation. This concept continues to hold the potential to reduce Could Increase oil reliance and reduce carbon emissions from transportation. Energy Requirements Increased market penetration of electric and hybrid vehicles in MMPA member communities could increase energy requirements. 85 A recent paper published by the California Energy Commission' analyzes the plug-in electric vehicle charging infrastructure needed to achieve California's goal of 1.5 million zero-emission vehicles (approximately 5% of vehicles) by 2025. The report estimates that in California, electric vehicles could add more than 1 GW of peak demand by 2025. Even though California has more than five times the number of vehicles on the road compared to Minnesota, the paper still demonstrates the significant increase in energy requirements that could occur once electric vehicles penetrate a market. MMPA recognizes the potential increase in energy requirements over the long term from electric and hybrid vehicles. However, this IRP assumes no increase in MMPA's electric load from electric vehicles, since in Minnesota and MMPA communities, this technology currently has a low penetration and its future penetration is unknown. MMPA Energy The table below shows MMPA's base energy projections as well as Projections energy requirements with and without new conservation. Plus Olivia Plus East Energy Energy Year Base Ener WAPA Grand Forks Requirements Plus 1.3% Requirements Adjustment WAPA without New Conservation with New Adjustment Conservation Conservation 2019 2,060,055 (22,307) (73,051) 1,964,697 (39,245) 1,925,452 2020 2,105,762 (22,381) (73,304) 2,010,077 (59,553) 1,950,524 2021 2,140,052 (22,307) (73,051) 2,044,694 (81,606) 1,963,088 2022 2,180,669 (22,307) (73,051) 2,085,311 (105,533) 1,979,777 2023 2,221,401 (22,307) (73,051) 2,126,043 (130,836) 1,995,207 2024 2,268,293 (22,381) (73,304) 2,172,608 (156,374) 2,016,234 2025 2,303,249 (22,307) (73,051) 2,207,891 (182,106) 2,025,785 2026 2,344,346 (22,307) (73,051) 2,248,988 (208,067) 2,040,921 2027 2,385,222 (22,307) (73,051) 2,289,864 (234,229) 2,055,635 2028 2,432,844 (22,381) (73,304) 2,337,159 (260,588) 2,076,571 2029 2,467,272 (22,307) (73,051) 2,371,914 (287,118) 2,084,796 2030 2,508,287 (22,307) (73,051) 2,412,929 (313,869) 2,099,060 2031 2,548,832 (22,307) (73,051) 2,453,474 (340,809) 2,112,665 2032 2,596,684 (22,381) (73,304) 2,500,999 (367,937) 2,133,062 2033 2,630,808 (22,307) (73,051) 2,535,450 (395,222) 2,140,227 Growth Rate(2019-2033) 1.8% 0.8% ' California Energy Commission, California Plug-In Electric Vehicle Infrastructure Projections 2017-2025,March 2018,CEC-600-2018-001. 2 U.S.Department of Transportation Federal Highway Administration,State Motor Vehicle Registrations- 2016, November 2017,https://www.fhwa.dot.gov/policyinformation/statistics/2016/mv1.cfm. 86 Section 5. Projected Demand Requirements — 2019 to 2033 This section discusses MMPA's historical and future demand requirements. This IRP examines both MMPA's Non-Coincident Peak(NCP) demand requirements and MMPA's Coincident Peak (CP) demand requirements with MISO. In accordance with Department of Commerce (DOC) instruction and in compliance with MISO, MMPA uses its CP demand requirements for planning purposes in this IRP. Historical 1.4% Over the period 2004 to 2017, MMPA member NCP demand NCP Demand requirements grew at a compound annual growth rate of Growth Rate approximately 1.4% for all twelve MMPA members. The following graph shows historical MMPA member NCP demand requirements for the years 2004 to 2017, the time period for which data is available for all twelve member cities. MMPA only served a portion of Shakopee's load until 2009. Therefore, the data has been adjusted to include all of Shakopee's load. MMPA has not historically served Elk River, but the data has been adjusted to include this load. The demands recognize a 2.3% transmission loss factor, and an 8.4% planning reserve margin. Actual planning reserve requirements have varied from 2004-2017, but for consistency across historic years, this IRP assumes 8.4%for all periods. Minnesota Municipal Power Agency Historical Member NCP Demand (MW) 600 500 400 300 200 100 0 64) 6'e 6 >yczq s' \b n0 0 ^ ^, 87 Weather Normalized NCP demand for the Agency was projected using a weather Load Factor normalized historical average load factor (approximately 56%) Approach Used to which was applied to MMPA's projected base energy requirements Project Demand net of conservation. Details on the inputs and assumptions of the methodology can be found in Appendix A. Projected 1.8% MMPA's projected NCP demand growth rate without new NCP Demand conservation is 1.8%for the 2019-2033 projection period. The Growth Rate without following graph shows historical and projected MMPA NCP New Conservation demand requirements for the years 2004 to 2033. The demands recognize a 2.3% transmission loss factor, and an 8.4% planning reserve margin. Minnesota Municipal Power Agency Historical& Projected Base Member NCP Demand (MW) Without New Conservation 600 500 400 300 200 Historical Projected 100 0 cvO 0. b + ,o '10 .190 ^�O � n`vff` y0' New Conservation New conservation measures are assumed to reduce the annual Assumed to Reduce growth rate of MMPA's NCP requirements by 1.0%. The base case NCP Demand of 1.3% conservation does not translate into a 1.3% reduction in the Growth Rate demand growth rate because the requirements for CLP savings By 1.0% calculations are based upon a lagging 3-year average of MMPA's power consumption. Section 6 discusses in detail MMPA's current and future conservation efforts. 88 Projected 0.8% MMPA's projected NCP demand growth rate including new NCP Demand conservation is 0.8%for the 2019-2033 projection period, shown in Growth Rate with the table below. New Conservation 2019-2033 NCP Growth Rate Without New Conservation 1'8% Effect of Conservation 1.0% NCP Growth Rate With New Conservation 0.8% The following graph shows historical and projected MMPA NCP demand requirements for the years 2004 to 2033. Both recognize a 2.3%transmission loss factor, and an 8.4% planning reserve margin. Minnesota Municipal Power Agency Historical& Projected Conservation-Adjusted Member NCP Demand (MW) 600 500 400 v it 300 U 1 200 Historical Projected 100 0 ti0� ti0szc) ti0zot � L� Oak sst, `§` ', "✓ Coincidence Factor MMPA's demand at the time of MISO's peak(CP demand)was Approach Used to projected using a coincidence factor approach. An average historical Project CP Demand coincidence factor(for summer months during the years 2005 to 2016, approximately 94%) was utilized to obtain MMPA's CP demand projection. Details on the methodology can be found in Appendix A. 89 Projected 0.8% MMPA's projected CP demand growth rate including new CP Demand Growth conservation is 0.8% for the 2019-2033 projection period. The Rate with New following graph shows historical and projected MMPA CP demand Conservation requirements for the years 2005 to 2033. Because MISO's market opened in 2005, coincident peak data is not available in 2004. This data includes conservation adjustments,transmission losses of 2.3%, and a planning reserve margin of 8.4%. Minnesota Municipal Power Agency Historical &Projected Conservation-Adjusted Member CP Demand (MW) 600 500 400 2 300 a 200 Historical I Projected 100 0 LOO, '19 '19^✓O� LOQ\ , LO�� n9 ^5 �L�� �, O' SOL, ^O MMPA uses CP demand requirements for planning purposes in this IRP. Lower Conservation Lower conservation rates would increase capacity requirements. Rates Would Increase This IRP assumes a 1.3% energy conservation rate for planning Capacity purposes, however, high and low cases of 1.5% and 1.0% are also Requirements considered. See Section 6 for further details on conservation. The graph below shows MMPA's CP demand projections based upon 1.0%, 1.3%, and 1.5% conservation levels. Both sets of projections recognize a 2.3%transmission loss factor, and an 8.4% planning reserve margin. 90 Minnesota Municipal Power Agency Projected Conservation-Adjusted CP Demand (MW) 500 480 460 440 420 2 400 U 380 360 -4-1.0% 340 t 1.3%Conservation 320 -•a-1.5%Conservation 300 —0\°e 01 ti019 0\ tiOyv ne n01b 0 �1 e�1 n.% 1„ ti��� Lower Population Slower population growth correlates with slower load growth in Growth Rate Would demand projections. Demand is calculated using energy projections Lower Electric Load which are correlated to population growth. A comparison of Growth historical and projected population compounded annual growth rates for MMPA member cities shows a deceleration in population growth across all MMPA members for the projection period. Please see Section 4 for details. Additional Members MMPA's projected demand requirements would increase if the Would Increase Agency were to take on additional members. This IRP assumes that Demand the 12-member Agency does not take on any additional members Requirements during the projection period. Large Retail Load MMPA's projected demand requirements would increase if its Additions Would members were to take on new large retail loads. This IRP does not Increase Demand include any new large retail loads during the projection period. Requirements Less Supply from Two of MMPA's members currently receive allocations of power WAPA Would (approximately 15.7 MW) from the WAPA. Both members have Increase Demand long-term contracts for these power allocations. However, WAPA Requirements could reduce the amount of energy and power available to its customers in the future. This would represent a policy change from the past. If WAPA decreases the power available to its customers, MMPA's demand requirements would increase, because the Agency 91 provides all of the demand to these two members that is not supplied by WAPA. This IRP assumes that WAPA allocations remain at the current contract amounts throughout the projection period. The Effect of Electric In Section 4, it was discussed that MMPA's energy requirements Vehicles on Peak would increase with an increase in electric vehicle use. However, Demand is Unclear the effect of electric vehicle use on demand is unclear. The California Energy Commission (CEC) report discussed in Section 4 estimated electric vehicles in California could add more than 1 GW of peak demand by 2025, assuming California reaches its goal of 1.5 million zero-emission vehicles (approximately 5% of all vehicles). The report described an electric vehicle charging profile consisting of a small at-home charging load ramp in the morning, work-place charging during the day, and a steep at-home charging load ramp in the early evening. This charging profile would likely increase peak demand. However, an alternative electric vehicle charging profile, where the majority of charging occurs during overnight off-peak hours, may have limited impact on peak demand. This IRP assumes no increase in demand requirements during the projection period because the level of electric vehicle penetration and the effect of electric vehicles on peak demand is not clear. Higher MISO Historically, MISO's planning reserve margin(PRM) has varied by Planning Reserve planning year as shown in the chart below. This IRP uses a PRM of Margin (PRM) 8.4%, consistent with the most recent planning year, to calculate Would Increase MMPA's planning resource margin requirements(PRMR). Future Capacity increases in PRM would increase MMPA's capacity requirements. Requirements MISO Planning Reserve Margin 10.0% 9.0% 8.0% �,—"�♦ 7.0% 6.0% c 5.0% a 4.0% 3.0% 2.0% 1.0% 0.0% 2013 2014 2015 2016 2017 2018 92 Higher Transmission This IRP assumes a 2.3%transmission loss factor for the projection Losses Would period. Historically,transmission losses have varied by MISO Zone, Increase Capacity Local Balancing Area(LBA), and planning year. Needs MMPA's entire load is in MISO Zone 1. The Agency currently serves load in two LBAs within Zone 1. The vast majority of MMPA's load is in the NSP LBA, where transmission losses are 2.4%. The remainder of MMPA's load is in the OTP LBA, with transmission losses of 3.1%. In October 2018, MMPA will begin serving Elk River load in the GRE LBA, with transmission losses of 1.4%. For the purposes of this IRP,the Agency assumes aggregate 2.3% transmission losses. Future increases in transmission losses would increase MMPA's capacity needs. Higher Generation An increased generation forced outage rate, as measured by Forced Outage Rate equivalent demand forced outage rate (EFORd), would decrease the Would Reduce capacity market credits MMPA would receive for its generation Recognized Capacity resources. EFORds for the planning horizon were based on the resource-specific EFORds for the 2018-19 planning year. If EFORds increase during the planning horizon, MMPA's capacity requirements would increase. Conversely, if EFORds decrease, MMPA's capacity requirements would decrease. MMPA's Energy, The table below summarizes MMPA's energy,NCP demand, and NCP Demand,And CP demand projections from 2019 to 2033. The energy projections CP Demand have been adjusted for conservation and WAPA allocations. The Projections NCP and CP projections have been adjusted for these same factors, as well as for transmission losses and the MISO PRM. 93 Minnesota Municipal Power Agency Energy and Demand Projections Year Energy MMPA NCP MMPA CP (MWh) (MW) (MW) 2019 1,925,452 440.4 412.6 2020 1,950,524 444.9 416.9 2021 1,963,088 449.0 420.7 2022 1,979,777 452.7 424.2 2023 1,995,207 456.2 427.5 2024 2,016,234 459.8 430.8 2025 2,025,785 463.2 434.0 2026 2,040,921 466.6 437.2 2027 2,055,635 469.9 440.3 2028 2,076,571 473.4 443.6 2029 2,084,796 476.5 446.6 2030 2,099,060 479.8 449.6 2031 2,112,665 482.9 452.5 2032 2,133,062 486.2 455.6 2033 2,140,227 489.1 458.3 94 Section 6. Energy Conservation and Demand Side Management This section discusses MMPA's energy conservation and demand side management efforts. The Agency's energy conservation programs delay the need for new generation and reduce energy consumption. State Legislature In 2007, the State Legislature revised the Conservation Improvement Established a CIP Program (CIP) statute to set an annual energy savings goal for each Energy Savings electric utility beginning in 2010. Target Seven of the twelve MMPA member communities participate in the CIP program managed by the Agency. The other five member communities manage their own energy efficiency programs at the municipal utility level. In 2017 State In 2017, the State Legislature revised the CIP statue to exempt electric Legislature utilities with fewer than 1,000 customers from participating in the Exempted Small program. Two MMPA member communities qualify for this Utilities from CIP exemption, however, both utilities have opted to continue to participate. MMPA Strives to MMPA strives to meet its CIP spending requirement and energy Meet Its CIP savings target. MMPA has undertaken significant efforts to develop a Spending CIP portfolio to meet its CIP energy savings target now and into the Requirement and future. Energy Savings Target Agency-Managed MMPA has consistently met its annual CIP spending goal of 1.5%. CIP Spending 2015- The table below shows annual CIP dollars spent and the percentage of 2017 gross operating revenue(GOR) over the period 2015 through 2017. CIP Spending—MMPA-Managed Portfolio 2015 2016 2017 CIP Spending $522,895 $537,421 $558,071 % of GOR 1.5% 1.5% 1.5% Agency-Managed MMPA's annual CIP kWh savings are slightly below the State's CIP kWh Savings savings goal of 1.5%. The table below shows annual kWh saved over 2015-2017 the period 2015 through 2017. 95 CIP Energy Savings—MMPA-Managed Portfolio 2015 2016 2017 kWh Savings 3,767,808 4,889,312 4,547,594 of Sales 1.1% 1.4% 1.3% Agency-Managed Based upon data for 2017, MMPA's CIP program cost an average of CIP Program Cost $0.12/kWh of electricity saved. MMPA's Agency-managed CIP $0.12/kWh of Energy portfolio aims to incorporate programs that help to maintain an average Saved rebate cost-to-electricity savings ratio of$0.10/kWh or less. This IRP Assumes This IRP assumes a CIP savings rate of 1.3%, although a low case of 1.3% Energy Savings 1.0% and a high case of 1.5%were also analyzed. The Agency strives for Projections for a 1.5% savings rate, however, planning processes need to take into consideration the uncertainties associated with longer term effectiveness of CIP programs and the possibility of diminishing returns. Lighting Rebates Are In 2017, 54% of MMPA's Agency-managed CIP rebate spending went a Cost-Effective Use toward lighting projects. Lighting rebates are a cost-effective means of of CIP Funds achieving energy savings. The table below highlights the return on investment in MMPA's 2017 CIP cycle. Lighting Program Effectiveness—MMPA-Managed Portfolio Program kWh saved Cost/kWh saved Commercial Lighting—New 349,850 $0.10 Commercial Lighting- Retrofit 2,719,646 $0.07 Residential LED 16,834 $0.23 Lighting Giveaway 137,975 $0.21 LED Street Lighting 191,685 , $0.15 All Lighting Combined 3,415,990 $0.09 Rebates with High The appliance recycling bonus rebate, the variable frequency drive Energy Savings rebate, and custom rebates all have high energy savings potential. The Potential appliance recycling bonus rebate($0.05/kWh electricity saved) creates customer incentives to unplug inefficient refrigerators and freezers and the variable frequency drive rebate ($0.05/kWh electricity saved) incentivizes improving heating, ventilation, and air conditioning (HVAC) system operation. Custom rebates are unique in that they give MMPA flexibility to support its members' customers on projects with high energy savings potential. Custom commercial and industrial projects also achieve a 96 good return on investment, averaging$0.07 spent per kWh of electricity saved in 2017. Custom rebates made up 7% of MMPA's Agency-managed CIP rebate spending in 2017. A Variety of Programs offered in the Agency-managed 2018 CIP Portfolio include: Programs Offered to Residential, Residential: Commercial,and Industrial • ENERGY STAR Appliance Rebate (Clothes Washer, Customers Dishwasher, Refrigerator,Freezer, Dehumidifier) • Secondary Refrigerator or Freezer Recycling Rebate • LED Lighting Rebate • Quality Installed Central Air Conditioning(AC) and Air Source Heat Pump Rebate • AC Tune Up Rebate • Custom Rebates Commercial and Industrial: • Lighting Retrofit Rebate • Lighting New Construction Rebate • Variable Frequency Drives(VFD) Rebates • Vending Machine Controller Rebate • Custom Rebates Members Pursue In 2017, the Agency-managed CIP members spent an estimated Direct Low-Income $45,570 on low-income energy conservation projects. CIP Projects Low-income spending is measured at the city level and each member city must meet its own individual spending requirement. MMPA continues to pursue low-income programs that provide direct benefits to low-income customers such as purchasing energy efficient lighting and appliances for section 8 housing and offering free light bulbs to low-income customers. CIP Energy Savings It is anticipated that CIP energy savings goals will become more Goals Will Become challenging to achieve in the future. Lighting rebates and custom More Challenging to rebates for equipment such as HVAC equipment are some of the most Achieve in the successful programs. These installations have long useful lives, Future therefore, in the future, there will be fewer available projects for updates. Additionally, energy-saving technological advancements are likely to slow down in areas such as lighting. Despite this, MMPA still believes it will have a continuing energy savings impact during the 2019-2033 projection period by focusing on 97 developing CIP strategies with the lowest cost per kWh of electricity saved,focusing on new energy-efficient technologies, and communicating with customers. Industrial and Participation by industrial and commercial customers is critical for Commercial achieving energy savings goals. Industrial and commercial customers Programs Are are larger energy users and therefore have greater energy savings Important to potential. MMPA works to create relevant, cost-effective programs for Program Success these users. MMPA Regularly MMPA continues to evaluate its program offerings and consider new Reevaluates Its CIP programs. MMPA aims to direct its CIP spending to the most cost- Offerings effective programs. Since the 2013 IRP filing, MMPA added residential rebates for freezers and dehumidifiers, recycling of secondary freezers, and commercial rebates for a variety of new LED lamps and fixtures. MMPA Continues MMPA currently has no demand side management programs, but to Reevaluate continues to reevaluate potential options. The Agency had a load Demand Side curtailment program and retired it when it became a less competitive Management option to acquire capacity as market prices for capacity became less Programs expensive. 98 Section 7. Existing Resources MMPA's existing resource portfolio is a mix of owned generation and power purchase agreements and a combination of renewable and conventional resources. 434 MW of Projected MMPA projects that its power supply portfolio will consist of 434 MW Power Supply of both contractual resources and Agency-owned generation for Resources in 2019 planning year 2019. The graph below shows MMPA's existing resources for the period 2019 to 2033. Minnesota Municipal Power Agency Power Supply Resources—Summer Capacity in MW 2019 to 2033 500 450 400 I iiiiIIIII 11111 350 MN Manna pi 300 iiiiiuiiiui ; ii III 250 200 150 111 11 I 11111 100 50 0 O oho O> o,L'L O'� O�' O� otic Off^ O�'� Otis oho O�' o�L O^� /ti 'L �. 'L ti 'L ', ', '1, /ti ', 'L 'ti 1• •FEP IN SEP •MRS BOGF •OGWF ■HTBE ■BSF ■Net Purchases Key: FEP: Faribault Energy Park OGWF: Oak Glen Wind Farm HTBE: Hometown BioEnergy BSF: Buffalo Solar Facility MRS: Minnesota River Station SEP: Shakopee Energy Park BOGF: Black Oak Getty Wind Farm Net Purchases: Bilateral Purchases 99 MISO Capacity MISO capacity is measured by Unforced Capacity(UCAP). UCAP is Measured by calculated by multiplying the Installed Capacity(ICAP) of a generating Unforced Capacity resource by 1 minus the Effective Forced Outage Rate (EFORd). Once (UCAP) the UCAP of a resource is calculated, market participants can convert UCAP to Zonal Resource Credits (ZRCs)to get capacity. FEP Projected UCAP: Faribault Energy Park(FEP) is the first power supply resource financed 257.3 MW and built by MMPA. The plant was built in two phases, with simple cycle operation beginning in April 2005. The combined cycle phase began operations in the summer of 2007, improving the fuel efficiency and increasing the maximum accredited summer output of the plant to 261 MW. The plant uses natural gas as its primary fuel. FEP is an innovative power plant that uses a series of created wetlands for water management at the plant. Rainwater is collected and filtered before being used for steam production and equipment cooling. The wetlands area is open to the public as a park with several small trails. The plant is also designed to be a"working classroom," with an observation room where visitors can view both the steam turbine and the plant's control room. FEP's ICAP for PY 2018 is 261.3 MW. The EFORd used to calculate FEP's 2018 UCAP is 1.53%. This IRP assumes that FEP's EFORd will continue to be 1.53%for the 15-year planning horizon of 2019- 2033. FEP 2018 2019-2033 ICAP 261.3 261.3 EFORd 1.53% 1.53% UCAP/ZRC 257.3 257.3 SEP Projected UCAP: Shakopee Energy Park (SEP) is a 46.4 MW distributed energy 42.6 MW resource. Located in Shakopee near Canterbury Park, SEP uses fuel- efficient reciprocating engines to generate local, reliable power for the City of Shakopee as well as contributing to the overall power supply for all MMPA member communities. SEP's ICAP for PY 2018 is 46.4 MW. The EFORd used to calculate SEP's 2018 UCAP is 8.19%. This IRP assumes that SEP's EFORd will continue to be 8.19%for the 15-year planning horizon of 2019- 2033. 100 SEP 2018 2019-2033 ICAP 46.4 46.4 EFORd 8.19% 8.19% UCAP/ZRC 42.6 42.6 MRS Projected The Minnesota River Station (MRS)plant is a peaking resource. The UCAP: 35.6 MW City of Chaska, one of the Agency's members, owns the plant and sells the entire output to MMPA under a long-term contract. MRS became operational in the summer of 2001 and is accredited for approximately 40 MW in the summer. Minnesota River Station uses natural gas as its primary fuel. MRS's ICAP for PY 2018 is 39.6 MW. The EFORd used to calculate MRS' 2018 UCAP is 10.00%. This IRP assumes that MRS's EFORd will continue to be 10.00% for the 15-year planning horizon of 2019- 2033. MRS 2018 2019-2033 ICAP 39.6 39.6 EFORd 10.00% 10.00% UCAP/ZRC 35.6 35.6 BOGF Projected At the end of 2016, the Minnesota Municipal Power Agency(MMPA) UCAP: 9.7 MW expanded its portfolio of renewable resources to include power from the 78-megawatt(MW)Black Oak Getty Wind Farm (BOGF) located in Stearns County, Minnesota. MMPA signed a long-term contract with Sempra U.S. Gas & Power for the output of the Black Oak Getty Wind Farm. The wind farm, composed of 39 wind turbines, entered commercial operation in December 2016. The term of the contract is 30 years. BOGF ICAP for PY 2018 is 78 MW. For wind resources, MISO uses capacity credit instead of EFORd. The UCAP is simply calculated by multiplying the ICAP by the capacity credit. The capacity credit used to calculate BOGF's 2018 UCAP is 12.44%. This IRP assumes that BOGF will continue to receive the 2018 capacity credit for the 15-year planning horizon. BOGF 2018 2019-2033 ICAP 78 78 Capacity Credit 12.44% 12.44% UCAP/ZRC 9.7 9.7 101 HTBE Projected Hometown BioEnergy(HTBE) is an 8 MW biomass facility, located in UCAP: 7.2 MW the MMPA member community of Le Sueur. It provides dispatchable, on-peak renewable energy to the Agency. Hometown BioEnergy supports the local community by collecting and processing local wastes to create a renewable source of electricity that flows directly into the Le Sueur power system. The facility was recognized by POWER Magazine as a 2014 Top Renewable Plant. HTBE ICAP for PY 2019 is projected to be 8 MW. The EFORd used to calculate HTBE's 2019 UCAP is 10.42%,which is the class average for diesel generation in MISO in 2018. This IRP assumes that HTBE's EFORd will match the 2018 class average for diesel generation for the IRP period through 2033. HTBE 2019-2033 ICAP 8 EFORd 10.42% UCAP/ZRC 7.2 OGWF Projected The 44 MW Oak Glen Wind Farm (OGWF) is MMPA's first owned UCAP: 7.6 MW wind farm and is located near Blooming Prairie, Minnesota. The U.S. Department of Energy awarded OGWF with the "2012 Public Power Wind Award"for leadership, innovation, project creativity, and benefits to customers. OGWF's innovative ownership and financial structure qualified the wind project to receive a$25.4 million federal grant. OGWF ICAP for PY 2018 is 44 MW. For wind resources, MISO uses capacity credit instead of EFORd. The UCAP is simply calculated by multiplying the ICAP by the capacity credit. The capacity credit used to calculate OGWF's 2018 UCAP is 17.35%. This IRP assumes that OGWF will continue to receive the 2018 capacity credit for the 15-year planning horizon. OGWF 2018 2019-2033 ICAP 44 44 Capacity Credit 17.35% 17.35% UCAP/ZRC 7.6 7.6 102 Buffalo Solar The Buffalo Solar Facility(BSF), a 7.1 MW AC utility-scale solar Projected UCAP: 3.6 facility located in the Agency's member community of Buffalo, entered MW commercial operation at the end of 2017. MMPA signed a 22.5-year, long-turn contract with HQC Tatanka Wi Solar Power Generation LLC, for the output of the solar facility. BSF 2018 2019-2033 ICAP 7.1 7.1 Capacity Credit 50.00% 50.00% UCAP/ZRC 3.6 3.6 MMPA Purchased MMPA has purchased between 65 and 105 MW of MISO Zonal Capacity for PY 2019- Resource Credits (ZRCs)for 2019 through 2029. 2029 Minnesota Municipal Power Agency Capacity Purchases (ZRCs) 2019-2029 120 100 so i 60 40 20 0 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 Planning Year 103 Section 8. Additional Capacity Requirements This section describes MMPA's projected additional capacity requirements over this IRP's planning period. No Capacity MMPA projects that it will not need new capacity until planning Needed Until 2030 year 2030. The chart below shows MMPA's projected capacity position by year during the projection period. Minnesota Municipal Power Agency Projected Capacity Position 2019-2033 40 22 21 12 13 14 16 18 20 16 18 20 20 (20) (40) (60) ;6)(S9) 92 (80) Projected Excess(Deficit) ( )(95) (100) (120) e e &.\ O��r Otis O^� O�� O�� O�� O�� O^r� O�� O�� O�� O�� `L ^r 'L ti ^✓ ti ti ^✓ � �r ^v ti ^✓ 'L 'fir Planning Year Projected Capacity MMPA projects that its first year of capacity need is PY 2030 for 86 Need Grows From 86 MW. The expiration of a capacity contract and member load growth MW in 2030 To 95 are the main reasons for the capacity need. MW in 2033 Planning Reserve MMPA currently participates in the MISO PRM pool. This IRP Margin Requirement assumes a PRM of 8.4%for the projection period, as discussed in of 8.4% Is Assumed previous sections. Transmission Losses Transmission losses of 2.3% are assumed for this IRP, as discussed Assumed to Be 2.3% in previous sections. 104 Section 9. Planning Approach This section outlines MMPA's planning approach. No Capacity Needed As discussed in Section 8, MMPA projects no capacity need until Until PY 2030 planning year 2030. Maintain Flexibility MMPA seeks to maintain flexibility in its power supply plan during in Time of a time of technological change. The rapid changes occurring with Technological renewable and storage technologies make flexibility vital to any Transition planning process. Securing additional capacity in the market allows MMPA to later reevaluate the changing market and capture opportunities that do not currently exist. Continue to MMPA will continue to reevaluate resource alternatives to Reevaluate determine what option is the most effective to meet future Feasibility of requirements. Included in these alternatives is the option to buy Resource capacity. MMPA maintains long term relationships with many Alternatives MISO market participants and looks for opportunities to buy capacity when cost effective. Committed to The Agency is committed to renewable energy. MMPA plans to Renewable Energy meet or exceed Minnesota's Renewable Energy Standard(RES). Section 12 further discusses MMPA's plan to meet renewable requirements. 105 Section 10. Short-Range Plan This section outlines MMPA's short-range action plan. Projected Capacity MMPA is not projected to need capacity until planning year 2030. Needs Met Through Planning Year 2029 MMPA Signed 170 MMPA has signed a wind PPA for 170 MW of energy. The resource MW Wind PPA is anticipated to begin commercial operation at the end of 2019. This PPA will help MMPA to meet the Renewable Energy Standard that is discussed in Section 12 and to meet its incremental energy needs with renewable energy. Cover Capacity As discussed in Section 8, MMPA is projected to have adequate Needs in the Short- capacity through planning year 2029. However, in the future if Term Market MMPA instead has a deficit, the incremental difference could be covered in the short-term capacity market. Continue to Develop MMPA will continue to develop and market cost-effective and Market Cost- conservation programs for its member utilities to offer to their retail Effective customers. The Agency's philosophy is to focus on programs that Conservation generate the most energy savings per dollar spent. MMPA also Programs remains committed to providing energy efficiency programs that benefit Minnesota's low-income households. 106 Section 11. Long-Range Plan This section describes MMPA's long-range plan. Capacity Not Needed MMPA is not projected to need capacity until planning year 2030. Until Planning Year The costs of different technologies for capacity are expected to 2030 change by the time the capacity is needed. For this reason, discussions with the Department of Commerce staff concluded that a detailed evaluation of resource alternatives is not needed for this IRP. Monitor Cost of During this time, MMPA will continue to monitor the cost of Generation generation technologies. In addition, MMPA will track Federal and Technologies State regulations, consumer preferences, and advances in technology. Evaluate Resource When MMPA's capacity need becomes near term,the Agency Alternatives would conduct a detailed evaluation of resource alternatives. The Agency anticipates considering new generation and power purchases to meet its needs. For new generation, a variety of technologies would be considered such as simple cycle gas, combined cycle gas,reciprocating engines, battery storage, solar, and wind. Consider Capital, In its evaluation of resources, MMPA would consider capital, Operating,Fuel,and operating, fuel, and externality costs of all resources. Externality Externality Costs costs would include environmental and regulatory costs of emissions as determined by the PUC. 107 Section 12. RES Compliance and Rate Impact This section describes MMPA's efforts toward meeting the State of Minnesota's Renewable Energy Standard(RES) and the estimated rate impact of complying with the RES. RES Requirement MMPA's annual RES requirements are projected to grow from Projected to Grow to approximately 312,000 in 2019 to 511,000 in 2033. This is mainly 511,000 MWh because of ERMU's addition as the twelfth member to MMPA as well as the increasing RES requirements. The RES requirements are based on total retail electric sales. The calculations account for a 4.49% system loss between wholesale and retail sales. The table below summarizes the RES obligation for MMPA for the period 2019-2033. Minnesota Municipal Power Agency Projected RES Requirements Projected Wholesale RECs for Load RES Year (MWh) Obligations 2019 1,925,452 312,617 2020 1,950,524 372,574 2021 1,963,088 374,974 2022 1,979,777 378,162 2023 1,995,207 381,109 2024 2,016,234 385,125 2025 2,025,785 483,687 2026 2,040,921 487,301 2027 2,055,635 490,814 2028 2,076,571 495,813 2029 2,084,796 497,777 2030 2,099,060 501,183 2031 2,112,665 504,431 2032 2,133,062 509,301 2033 2,140,227 511,012 108 RECs for Clean In addition to its RES obligation, MMPA has retired RECs for its Energy Programs green pricing program and Clean Energy Choice Programs. While RECs retired for these programs are not significant(approximately 6,000 RECs for 2017),participation in these programs is increasing and would increase the total RECs needed. Notwithstanding the foregoing, MMPA's current and future resources are projected to satisfy all of its future REC obligations. 970,000 RECs in The Agency currently has over 970,000 RECs in its inventory. Inventory MMPA actively follows the REC markets and seeks opportunities to buy RECs to satisfy its future requirements. Below is the breakdown of MMPA's current REC inventory: 2014 Vintage RECs 119,648 2015 Vintage RECs 176,349 2016 Vintage RECs 169,724 2017 Vintage RECs 398,221 2018 Vintage RECs 109,559 Total 973,501 Five Existing MMPA's five existing resources are projected to generate Renewable Resources approximately 466,000 MWh per year. Projected to Generate 466,000 MWh/Year The table below shows the projected annual generation from these existing renewable resources: Resource Annual Generation (MWh) Black Oak Wind Farm 307,000 Oak Glen Wind Farm 132.000 Buffalo Solar 14,000 Hometown BioEnergy 12,000 Hometown Wind 800 Total 465,800 Signed PPA MMPA has signed a 30-year wind power purchase agreement with Projected to Generate NextEra for 170 MW of generating capacity from the Dodge County 600,000 MWh/Year Wind Farm. The facility has not yet been constructed, but has a contract commercial operation deadline of December 2019. The wind farm is projected to generate approximately 600,000 MWh of renewable energy per year. 109 MMPA Projects In 2033, MMPA's energy requirements of 2,140,227 MWh will be Meeting All of Its 214,776 MWh over its projected 2019 requirements. MMPA's Incremental Energy renewable energy requirement for 2033 of 511,012 MWh is 238% Needs with of its incremental energy needs. By satisfying the RES, MMPA will Renewables meet all of its incremental energy needs through renewables. The effects of MMPA's conservation efforts are included in the base calculations. MMPA Is Positioned MMPA is positioned to continue to meet the RES through its mix of to Meet the RES purchases and resources. Rate Impact of MMPA's 2005 to 2017 RES rate impact ranged between 0.00 cents Complying with RES per kWh and 0.96 cents per kWh. MMPA's projected RES rate impact for 2019-2033 ranges between 0.64 cents per kWh and (0.53) cents per kWh. Details of these projections are included in Appendix C. Dodge County The Dodge County project is necessary to meet the RES rate impact Project Necessary to projections. MMPA's competitively priced PPA with Dodge County Meet RES Rate Wind Farm reduces the rate impact beginning with 2020. This project Impact Projections is projected to provide benefits between 0.09 cents per kWh and 0.55 cents to kWh. Greenhouse Gas MMPA's generation assets and power purchase agreements that Emission Reduction contribute to meeting the RES also support meeting Minnesota's Goals Were Achieved greenhouse gas emission reduction goals that are established in in 2015 and Are Minn. Stat. § 216H.02. Minnesota established a goal to reduce Projected to Be statewide greenhouse gas emissions across all sectors at least 15% Achieved in 2025 below 2005 levels in 2015 and at least 30%below 2005 levels in 2025. The following table summarizes MMPA's greenhouse gas reductions for 2015 and 2025. Minnesota Municipal Power Agency Greenhouse Gas Reductions from 2005 Levels 2015 2025 Total Emissions 34% 63% (lbs CO2) Emission Rate 42% 76% (lbs CO2/MWh) 110 Section 13. MMPA's Plan Is in The Public Interest This section discusses how MMPA's Integrated Resource Plan is in the public interest. MMPA's Plan MMPA's IRP gives the Agency flexibility to accommodate future Provides Flexibility uncertainties such as technological changes, penetration of electric vehicles, and energy policy. The Agency created this flexibility by purchasing capacity through planning year 2029. As 2029 approaches, MMPA will reevaluate load and costs to determine the best options for meeting its future capacity and renewable energy requirements. MMPA's Plan Limits The Agency's plan limits negative environmental effects. MMPA Environmental projects that 53% of its wholesale sales will be from renewable Effects resources in 2025. MMPA also continues to pursue increased energy conservation. MMPA's Plan Meets MMPA's plan meets the public interest criteria set out in the Public Interest Commission Rule 7843.0500 Subp. 3, which are: Criteria in Rule 7843 • Maintain or improve the adequacy and reliability of utility service • Keep the customers' bills and the utility's rates as low as practicable, given regulatory and other constraints • Minimize adverse socioeconomic effects and adverse effects upon the environment • Enhance the utility's ability to respond to changes in the financial, social, and technological factors affecting its operations • Limit the risk of adverse effects on the utility and its customers from financial, social, and technological factors that the utility cannot control MMPA's plan includes a diverse set of resources to serve its load. The Agency's portfolio has both owned and contracted renewable and conventional resources. MMPA seeks to maintain flexibility in its power supply plan during a time of technological change. The rapid changes occurring with renewable and storage technologies make flexibility vital to any planning process. Securing additional capacity in the market allows MMPA to later reevaluate the changing market and capture opportunities that do not currently exist. This plan enhances the Agency's ability to respond to change during this transitional period for the energy industry. It also limits 111 the risk of adverse effects. By including renewable resources in its portfolio and promoting energy conservation, the Agency balances socioeconomic and environmental considerations. 112 Appendix A. Load Projection Methodology This appendix describes the methodology used to project MMPA's energy and demand requirements for this Integrated Resource Plan. Members' Energy MMPA member energy usage was projected using linear regression Usage Was Projected analysis. The energy usage for three of MMPA's member cities with A Linear (East Grand Forks, Buffalo, and Elk River)was projected separately Regression Model from that of the other nine members. Those four projections were then combined to obtain the entire Agency's projected energy. The MMPA9 projection includes the member cities of Anoka, Arlington, Brownton, Chaska, Le Sueur,North St. Paul, Olivia, Shakopee and Winthrop. The historical monthly energy data sets for these four projections are as follows: • MMPA9: Monthly energy usage from 1996-2017 • East Grand Forks: Monthly energy usage from 1996-2017 • Buffalo: Monthly energy usage from 2000-2017 • Elk River: Monthly energy usage from 2004-2017 Data constraints for East Grand Forks and Buffalo prompted the separate projections for those cities. Elk River was projected separately because MMPA begins serving its load in October 2018. Total MMPA energy requirements were projected by adding the results of these four regression models. Throughout this appendix, all 12 MMPA member cities are referred to as MMPA12 and all 11 MMPA member cities, excluding Elk River, are referred to as MMPA11. Explanatory The explanatory variables used for the regression models were Variables for Energy weather, income, and population. Projections Were Weather,Income, Weather And Population Cooling degree days (CDD) and heating degree days (HDD)were both used as explanatory variables. All CDD and HDD data is supplied by the National Oceanic and Atmospheric Administration (NOAA). Historical CDD and HDD data for all member communities, except East Grand Forks, comes from the Minneapolis-St. Paul International Airport weather station. Historical CDD and HDD data for the East Grand Forks model comes from the Fargo weather station(the closest available). CDD and HDD projections are historical"normal" data from 1981-2010 (the latest"normal" data set available published by NOAA). 113 Income per Capita Both historical and projected income data come from Woods and Poole Economics' Minnesota State Profile 2017 State and County Projections to 2050. This data is provided at the county level. The MMPA9 model uses a weighted average income variable, created by weighting each of those nine member cities' income per capita by the city's annual energy usage. Population Historical population data from 1988 to 2016 comes from the Minnesota State Demographic Center and the Metropolitan Council Historic Household and Population Estimates. Data was unavailable for the year 1989, so linear smoothing of 1988 and 1990 data was used. Population projections from 2019 to 2033 are based on actual data for 2016, annually increased by long term county population growth rates calculated from Woods and Poole projections. All explanatory variables listed above were used in the MMPA9 model. For the East Grand Forks model, CDD and population were excluded because of low t-stat results. Minimal air conditioning load and a devastating 1997 flood likely explain the low t-stats for CDD and population,respectively. Each model used monthly data to forecast monthly energy, which was then aggregated to provide annual energy projections. Annual Energy Was Annual energy projections were decreased by 1.3% of the Agency's Reduced by three-year rolling average retail energy usage. This reduction Conservation represents MMPA's assumption regarding new conservation measures. Conservation levels of 1.0% and 1.5%were also analyzed, but the 1.3%base case was used for the purposes of this IRP. Conservation reductions lowered the compounded annual growth rate by 1.0%, resulting in a net annual growth rate of 0.8% for the base case energy usage. Agency Energy Following adjustments for conservation,projected energy Requirements Were requirements were reduced by the energy that WAPA supplies to Reduced By WAPA- two MMPA member cities (Olivia and East Grand Forks). These Supplied Energy WAPA allocations were assumed to remain at current levels throughout the projection period. 114 NCP Demand Was MMPA's Non-Coincident Peak (NCP) demand requirements were Projected Using a projected by applying a weather normalized load factor to the Weather Normalized Agency's energy projections. This weather normalized load factor Load Factor of 55.9%was calculated as the average of annual weather normalized load factors from 2011 to 2017. The average load factor was then applied to the conservation-adjusted energy projections to obtain MMPA's projected NCP demand. Demand at MISO's MMPA's demand at the time of MISO's peak(CP demand)was Annual Coincident projected by applying a coincidence factor to the Agency's NCP Peak Was Projected projections. This coincidence factor of 93.9% was calculated as the Using A Coincidence average of monthly summer(June-September)coincidence factors Factor Approach from June 2005 to September 2016. The average coincidence factor was then applied to the NCP demand projections to obtain MMPA's projected CP demand. CP Demand Was Like the energy projections, CP demand projections were reduced Adjusted for WAPA- by the capacity that WAPA supplies to two MMPA member cities. Supplied Capacity These WAPA allocations were assumed to remain at the current contract levels throughout the projection period. Capacity The Agency's total capacity requirements are calculated by adding Requirements transmission system losses (2.3%) and planning reserve margin Include Losses and requirements (8.4%)to the projected CP demand requirements. Reserves MMPA's entire load is in MISO Zone 1 and currently serves load in two Local Balancing Authorities(LBAs). The vast majority of MMPA's load is in the NSP LBA, where transmission losses are 2.4%. The remainder of MMPA's load is in the OTP LBA, with transmission losses of 3.1%. In October 2018, MMPA will begin serving Elk River load in the GRE LBA, which currently has transmission losses of 1.4%. For the purposes of this IRP, the Agency assumes aggregate 2.3%transmission losses. MISO's planning reserve margin requirement is expected to be 8.4% in planning year 2018. For long term planning purposes, a planning reserve margin of 8.4% was used. 115 Appendix B. 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L 3 I- a � o ct a) 2 � N � c) Ce ,,,i I.L U L o C w C O 0 3 .. z E LL 0 L W m o `4oZZQ Y a > , - au ' V ci) L � w ° °-) N o I- p o an E ZO N Y Q 5 — 0 3 w o w , _ < N F. LL O O O C) Lo r- C) V co N O O) , co co ti v w c0 r` E O N v Q f/J Y O O Ln O c.0 t` O �- O O O N N N ,— O 07 N- 0 C Q y Q T a Z W ,- r ,- r ,— N N N N N N N N N N N N N N N �p 24, an an U w onE .o 5 >> a- 4 5 c 'E. 'E 2 c) Ce ct 3 -o -o N F- D °o O O° a) 2 • O I) Z J C3 o a p >- c L L W N 'b ,5 •LO' ,L' F- � 0 2 0 0) 0) co N CO N- CO CO - co LU N- Tt CO O) d' In N 0 to Q Q 1-- O N N Q N- CI) 2 Q O O N N N N N N N N C) M C) C) N N N N N rDiu U) Q cj Q. w g Z Z p 11.1 < 00000000000000000000000 0 w U) Z o .a go _O (NCO L (UNCCOCD0OOOO- LU (UN (UC) C - CNI CO OOO- CL C r- c) r---. LL 000000000 . . . . . . - - - - N N N N N C O � W o U 2 Appendix C. Renewable Energy Standard Rate Impact Report This appendix contains MMPA's rate impact report for complying with the Renewable Energy Standards (RES) in Minnesota Statute §216B.1691. Rate Impact Follows MMPA's RES rate impact calculations in this appendix follow the the PUC Established PUC established methodology. Methodology Minnesota Statute §216B.1691 establishes a Renewable Energy Standard and requires a utility to evaluate the rate impact of the standard and file the report as an appendix in its resource plan. On January 6, 2015,the Minnesota Public Utilities Commission(PUC) issued Order Establishing Uniform Reporting System for Estimating Rate Impact of Minn. Stat. §216B.1691 (`Order") under Docket No. E-999/CI-11-852. Levelized Historic MMPA's historic RES rate impact was evaluated for the years 2005 RES Rate Impact to 2017. On an annualized basis,the RES rate impact ranged from Was 0.25 cents/kWh 0.00 to 0.96 cents per kWh. The levelized RES rate impact for this time period was 0.25 cents per kWh. Full details are provided in the historic table below. The years analyzed satisfies Order point 2A(1) directing an analysis for the period 2005 until the last reported year. Levelized RES Rate The RES rate impact was projected for the years 2018 to 2033. On Impact Projected to an annualized basis,the RES rate impact is projected to range from be 0.03 cents/kWh 0.64 to (0.53)cents per kWh. The levelized RES rate impact for this time period is projected to be 0.03 cents per kWh. Full details are provided in the projection table below. The years analyzed satisfies Order point 2A(2) directing an analysis of the 15 years following the last reported year. Includes All MMPA's rate impact analysis includes all its generation assets that Generation Assets meet the renewable energy standard regardless of when the asset that Comply with the was acquired. Renewable Energy Standard The resources included in the evaluation satisfy the requirement of Order point 2B. 132 Rate Impact Includes The RES rate impact calculations include direct costs incurred to Direct Costs meet the RES. These costs include power purchase agreements (PPAs) from renewable resources and the capital and operating costs of owned assets. There were no transmission costs to include in the rate impact. The direct costs included satisfy Order points 2C and 2E. Rate Impact Includes The RES rate impact calculations include avoided energy, capacity, Avoided Costs and emissions costs. There were no avoided transmission costs included in the rate impact. Historically,the avoided energy costs are those associated with MMPA's PPAs and owned assets. The projected avoided energy costs are based on locational marginal prices for Minnesota Hub, escalated at inflation. The avoided capacity costs are based on the MISO Zone 1 Cost of New Entry(CONE), escalated at inflation. The avoided regulatory cost of emissions is included and based on the June 6, 2018 PUC Order Establishing 2018 and 2019 Estimate of Future CO2 Regulation Costs. These costs are included starting in 2025 and estimated at the midpoint of the regulatory costs, increased at inflation. The avoided costs accounted for in the RES rate impact are in compliance with Order points 2F and 2G(2). Rate Impact Excludes The RES rate impact does not include the indirect costs of ancillary Costs for Ancillary services or base load cycling that are a result of the increase in Services and Base intermittent generation resources on the system. Based on MISO's Load Cycling market construct, MMPA sells all generation output to, and procures all their load from,the MISO market. MISO charges for ancillary services and base load cycling cannot be attributed to the RES resources. This analysis meets the requirements of Order point 2D. RES Rate Impact The tables below detail the historic and projected RES rate impact. Summary Tables They report annualized and levelized cost impacts, satisfying Order point 2H. 133 z w a w ce w w co N O L z O OA E H CC w a m w Q a g � F s z LAw a a 00 z Q - it Appendix D. Regulatory Requirements Cross Reference Index The following table provides a cross reference index for the various regulatory requirements related to Integrated Resource Plan filings. Statute or Rule Description of Requirement Location in IRP 7843.0400 Subp. 1 Include most Advance Forecast filed with Appendix B DOC 7843.0400 Subp. 2 File a proposed plan for meeting the service Sections 7 and 10 needs of its customers 7843.0400 Subp. 3A Describe resource options considered, Section 9 and 11 including information supporting selection of proposed resources 7843.0400 Subp. 3B Include descriptions of the overall process and Section 11 of the analytical techniques used to create resource plan from available options 7843.0400 Subp. 3C Include a five-year action plan Section 10 7843.0400 Subp. 3D Explain why the plan is in the public interest Section 13 7843.0400 Subp. 4 Include a non-technical summary Section 1 216B.1691 Subd.2e Rate impact of compliance with Renewable Section 12 and Energy Standard Appendix C 216B.1691 Subd. 3 Description of efforts towards meeting Section 12 REO/RES 216B.2422 Subd. 2 Include a least cost plan for meeting 50% and Section 12 75% of all energy needs from new and refurbished generating facilities through a combination of conservation and renewable energy resources 216B.2422 Subd. 2c Narrative on utility's progress towards Section 12 achieving the state greenhouse gas emission reduction goals 216B.2422 Subd. 3 Use Commission values and other external Section 11 factors including socioeconomic costs when evaluating and selecting resource options 136 Appendix E. Acronyms Index The following index provides definitions of acronyms used in this IRP. Acronym Definition AC Alternating current BOGF Black Oak Getty Wind Farm BSF Buffalo Solar Facility CAGR compounded annual growth rates CDD Cooling degree day CIP Conservation Improvement Program CP Coincident peak DIR Dispatchable Intermittent Resource DOC Depaitinent of Commerce EFORd Equivalent demand forced outage rate EIA Energy Information Administration EPA Environmental Protection Agency ERMU Elk River Municipal Utilities FEP Faribault Energy Park FERC Federal Energy Regulatory Commission GOR Gross operating revenue GW Gigawatt GWh Gigawatt-hour HDD Heating degree day HTBE Hometown BioEnergy ICAP Installed capacity IRP Integrated resource plan kW Kilowatt kWh Kilowatt-hour LBA Local balancing area LNG Liquified natural gas MATS Mercury and Air Toxics Standards MISO Midcontinent Independent System Operator MMPA Minnesota Municipal Power Agency 137 MRS Minnesota River Station MW Megawatt MWh Megawatt-hour NOAA National Oceanic and Atmospheric Administration NCP Non-coincident peak OGWF Oak Glen Wind Farm PPA Power purchase agreement ppb Parts per billion PRM Planning reserve margin PRMR Planning resource margin requirements PUC Public Utilities Commission PY Planning year(June 1 through May 31) REC Renewable energy credit RES Renewable energy standard SEP Shakopee Energy Park UCAP Unforced capacity WAPA Western Area Power Administration ZRC Zonal resource credits 138 FITCH UPGRADES MINNESOTA MUNICIPAL POWER AGENCY, (MN) ELEC REV BONDS TO 'A+'; OUTLOOK STABLE Fitch Ratings-New York-16 July 2018:Fitch Ratings has upgraded the ratings on the following Minnesota Municipal Power Agency(MMPA, or the agency) revenue bonds: --Approximately $187 million electric revenue bonds series 2013, 2014, 2014A and 2016 to 'A+' from'A'. The Rating Outlook has been revised to Stable from Positive. SECURITY The bonds are secured by the net revenues of MMPA, derived primarily from payments under long-term power sales agreements (PSAs)with 11 participating municipal electric systems. The bonds are further secured by certain personal property and contract rights covering the system. KEY RATING DRIVERS POWER RESOURCE STRATEGY: The rating upgrade reflects MMPA's shifting resource strategy from short-term market purchases to a combination of new locally-owned generation and competitively-priced inteiuiediate-term purchased power agreements (PPAs). As additional new generation is no longer needed to meet load growth, MMPA faces modest capital needs and no additional direct debt going forward. LEVERAGE EXPECTED TO CONTINUE IMPROVING: The upgrade also reflects Fitch's expectation the revamped resource strategy will result in a decline in leverage with approximately $50 million of debt amortizing over the next five years, no new debt and more muted rate increases than previously projected. Financial margins are projected to remain strong. MATURE JOINT ACTION AGENCY: MMPA is a joint action agency that has provided wholesale power supply to its 11 member cities since 1995. A 12th member will begin receiving power in October 2018. Power and energy are principally supplied pursuant to take-and-pay PSAs that were recently extended through 2050 by 10 members representing 94% of system load. The remaining contracts expire in 2040. CONCENTRATION WITH THE LARGEST MEMBERS: The largest members are Shakopee Public Utilities Commission, City of Chaska, and City of Anoka, which account for a sizeable 71% of the agency's revenues. Each member exhibits healthy overall credit characteristics and has been experiencing continued growth in retail electric sales in recent years. The remaining cities add limited geographic and economic diversification to the membership. SOLID FINANCES, STABLE ELECTRIC RATES: The agency maintains average wholesale power rates to members (7.32 cents/KWh in 2017)that are comparable or below neighboring investor-owned,municipal, and cooperative utilities. MANAGEMENT FUNCTIONS OUTSOURCED: MMPA relies on Avant Energy, Inc., a provider of energy management services,to manage virtually all functions of the agency including accounting, operations, and power and fuel market management. MMPA has no direct employees. Despite this unusual arrangement, Avant's track record in managing MMPA has been favorable. 139 RATING SENSITIVITIES STABLE MARGINS,LOWER LEVERAGE: The Minnesota Municipal Power Agency's rating is predicated on Fitch's expectation of continued stable financial performance, maintenance of stable and competitive rates, and a steady improvement in overall leverage. CREDIT PROFILE MMPA provides wholesale power supply to 11 participating cities, all of which own and operate municipal electric systems. A 12th member, Elk River, MN, will begin purchasing power from MMPA on Oct. 1, 2018. MMPA's load center is concentrated in the northern and southwestern suburbs of the Minneapolis-St.Paul metropolitan area. Fitch views the membership as having a diverse economic base,which includes commercial businesses, light and heavy manufacturing, farming,tourism and services. MMPA supplies virtually all power requirements of the participating municipal systems on a take- and-pay basis through separate,but substantially similar long-term PSAs. Each of the contracts expires on Dec. 31, 2050,with the exception of two small participants whose contracts expire on Oct. 31, 2040. Collectively,the participating systems serve approximately 70,000 largely residential and commercial customers and a total population of approximately 150,000. Fitch believes the underlying credit quality of the participating member's utilities, especially the three largest systems, are supportive of the 'A+'rating on the bonds. WELL-POSITIONED POWER SUPPLY PORTFOLIO Power is currently supplied to the members through a mix of agency-owned resources and PPAs. MMPA's primary asset is the Faribault Energy Park, a 300 MW natural gas/oil-fired combined cycle plant. The remaining power and energy requirements of the participants are supplied through agency-owned renewable facilities(wind and bioenergy), member-owned resources and a portfolio of PPAs with third parties. Peak demand from all members was 312 MW in 2017, which is down about 7% in aggregate since 2011. However, energy sales have grown steadily by an average annual rate of 1.3% from 2009 -2017 reflecting the resiliency of the Minneapolis-St. Paul economy and the lack of significant customer concentration at the member level. Demand is expected to continue to increase modestly at the member level as well as with the addition of MMPA's newest member,the city of Elk River, MN,later this year. Demand will increase by roughly 20% from Elk River's approximately 70 MW of load requirements. MMPA has sufficient capacity to meet member load. After adding Shakopee Energy Park, a 46 MW quick-start natural gas-fired plant primarily used for peaking in 2017 and a long-term PPA with Sempra Energy for 78 MW of wind capacity in 2016, MMPA's supply resources total 532 MW of nameplate capacity. MMPA is in the process of adding additional capacity to meet member load requirements and to replace existing short-term contracts,primarily with carbon-free resources via longer-term PPAs. The new capacity will come online over the next few years, and by 2020, MMPA expects that roughly 60% of its energy will come from renewable resources. In addition, capacity will be sufficient to meet member needs (including Elk River)through at least 2030. MMPA previously expected to build additional gas-fired distributed generation similar to the Shakopee plant. However, given the relatively low cost of the power procured through intermediate-term PPAs, management no longer plans to build additional generation. 140 FINANCIAL PERFORMANCE REMAINS STRONG Operating performance at the agency has strengthened over the last seven years with funds available for debt service(FADS)growing to $36.3 million in 2017, a nearly 100% increase since 2009. The improved results are due to a combination of factors, including higher asset depreciation, increased operating revenue and relatively stable operating expenses, including lower purchased power costs.Fitch-calculated debt service coverage, which improved over that span, totaled 1.44x in fiscal 2017 and matches well with the 'A+' category median of 1.21x for wholesale systems. The bond indenture requires a coverage ratio of 1.15x. MMPA's liquidity is sound. MMPA ended 2017 with$37.5 million in cash and equivalents, which while lower than 2016 is a very strong 176 days cash on hand and above the median for similarly rated wholesale systems(133 days). The agency also benefits from an available credit facility, which was recently increased to $20 million and extended to 2019, strengthening liquidity to 270 days. IMPROVED LEVERAGE, MODEST CAPITAL NEEDS MMPA had just over$300 million in total debt outstanding as of fiscal-end 2017. All existing debt is fixed-rate and matures in 2046. Leverage as measured by net adjusted debt to adjusted FADS has been on a steady decline following the wind down of MMPA's earlier construction cycle and ended 2017 at 7.4x.In 2010, leverage totaled 13.3x. Equity capitalization also improved but remains somewhat low at 21.3%in 2017 (equity capitalization was just 8% in 2010). Over the next five years MMPA will amortize approximately $50 million in existing debt. With modest capital needs going forward due primarily to the shift toward contracted purchased power and away from additional new construction, leverage should continue to improve. RATES ARE COMPETITIVE,LIMITED INCREASES PROJECTED Wholesale rates for power charged by MMPA are reviewed monthly by the board and management and are not subject to the approval of any federal or state authority including the Minnesota Public Utilities Commission. MMPA reserves the right to adjust rates at any time pursuant to the terms of the PSA. Management's authority to determine MMPA's forward-looking monthly energy adjustment clause ensures adequate recovery of fuel costs. Members are required under the terms of the PSA to set retail rates sufficient to meet their obligations under the agreement, and are free to do so without regulatory oversight. Payments under each PSA constitute an operating expense of each member and are derived solely from the revenues of each member's electric system. Lower gas prices led to a significant drop in rates from $73.00/MWh in 2008 to $58.77/MWh in 2009. Since then,MMPA's wholesale rates have been on the rise reflecting increasing debt service requirements, higher transmission rates and the transfer of funds to the rate stabilization fund. MMPA rates to members totaled a still competitive$73.19/MWh in 2017. MMPA's updated financial forecast projects wholesale rates will increase by a manageable 1% annually through 2022. Previous forecasts assumed larger rate increases from new debt to fund construction costs related to new generating resources. Contact: Primary Analyst 141 Andrew De Stefano Director +1-212-908-0284 Fitch Ratings,Inc. 33 Whitehall Street New York,NY 10004 Secondary Analyst Dennis M. Pidhemy Managing Director +1-212-908-0723 Committee Chairperson Doug Scott Managing Director +1-512-215-3725 A January 2018 district court ruling that dismissed claims regarding payment of Puerto Rico Highways and Transportation Authority debt has raised questions about the scope of protections provided by Chapter 9 of the U.S. bankruptcy code to bonds secured by pledged special revenues. Fitch's rating criteria treat special revenue obligations as independent from the related municipality's general credit quality. The outcome of the litigation could result in modifications to Fitch's approach. For more information, see "What Investors Want to Know: The Impact of the Puerto Rico Ruling on Special Revenue Debt" available at www.fitchratings.com. Media Relations: Sandro Scenga,New York, Tel: +1 212 908 0278, Email: sandro.scenga@fitchratings.com. Additional information is available on www.fitchratings.com. Applicable Criteria Rating Criteria for Public-Sector,Revenue-Supported Debt(pub. 26 Feb 2018) https://www.fitchratings.com/site/re/10020113 U.S.Public Power Rating Criteria(pub. 18 May 2015) https://www.fitchratings.com/site/re/864007 ALL FITCH CREDIT RATINGS ARE SUBJECT TO CERTAIN LIMITATIONS AND DISCLAIMERS.PLEASE READ THESE LIMITATIONS AND DISCLAIMERS BY FOLLOWING THIS LINK: HTTPS://WWW.FITCHRATINGS.COM/UNDERSTANDINGCREDITRATINGS. 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Copyright©2018 by Fitch Ratings,Inc.,Fitch Ratings Ltd.and its subsidiaries.33 Whitehall Street,NY,NY 10004.Telephone: 1-800-753-4824,(212) 908-0500.Fax:(212)480-4435.Reproduction or retransmission in whole or in part is prohibited except by permission.All rights reserved.In issuing and maintaining its ratings and in making other reports(including forecast information),Fitch relies on factual information it receives from issuers and underwriters and from other sources Fitch believes to be credible.Fitch conducts a reasonable investigation of the factual information relied upon by it in accordance with its ratings methodology,and obtains reasonable verification of that information from independent sources,to the extent such sources are available for a given security or in a given jurisdiction.The manner of Fitch's factual investigation and the scope of the third-party verification it obtains will vary depending on the nature of the rated security and its issuer,the requirements and practices in the jurisdiction in which the rated security is offered and sold and/or the issuer is located,the availability and nature of relevant public information,access to the management of the issuer and its advisers,the availability of pre-existing third-party verifications such as audit reports,agreed-upon procedures letters,appraisals,actuarial reports, engineering reports,legal opinions and other reports provided by third parties,the availability of independent and competent third-party verification sources with respect to the particular security or in the particular jurisdiction of the issuer,and a variety of other factors.Users of Fitch's ratings and reports should understand that neither an enhanced factual investigation nor any third-party verification can ensure that all of the information Fitch relies on in connection with a rating or a report will be accurate and complete.Ultimately,the issuer and its advisers are responsible for the accuracy of the information they provide to Fitch and to the market in offering documents and other reports.In issuing its ratings and its reports,Fitch must rely on the work of experts,including independent auditors with respect to financial statements and attorneys with respect to legal and tax matters.Further,ratings and forecasts of financial and other information are inherently forward-looking and embody assumptions and predictions about future events that by 142 their nature cannot be verified as facts.As a result,despite any verification of current facts,ratings and forecasts can be affected by future events or conditions that were not anticipated at the time a rating or forecast was issued or affirmed. 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For Australia,New Zealand,Taiwan and South Korea only:Fitch Australia Pty Ltd holds an Australian financial services license(AFS license no. 337123)which authorizes it to provide credit ratings to wholesale clients only.Credit ratings information published by Fitch is not intended to be used by persons who are retail clients within the meaning of the Corporations Act 2001 Fitch Ratings,Inc.is registered with the U.S.Securities and Exchange Commission as a Nationally Recognized Statistical Rating Organization(the "NRSRO").While certain of the NRSRO's credit rating subsidiaries are listed on Item 3 of Form NRSRO and as such are authorized to issue credit ratings on behalf of the NRSRO(see https://www.fitchratings.com/site/regulatory),other credit rating subsidiaries are not listed on Form NRSRO(the "non-NRSROs")and therefore credit ratings issued by those subsidiaries are not issued on behalf of the NRSRO.However,non-NRSRO personnel may participate in determining credit ratings issued by or on behalf of the NRSRO. 143 INFRASTRUCTURE AND PROJECT FINANCE =tIy MOODY Sir =t , INVESTORS SERVICE tst } inf .eµ '3.4g ..x CREDIT OPINION Minnesota Municipal Power Agency 1 August 2018 Update following Moody's Upgrade to Al from A2; Outlook efe Rate this Research Stable Summary Minnesota Municipal Power Agency's (MMPA:Al/stable) credit profile reflects the weighted Contacts average credit quality of its municipal members, including that of Elk River Municipal Utilities Scott Solomon +1.212.553.4358 (Aa3/STA)who will enter the membership beginning October 2018. VP-Sr Credit Officer MMPA's profile also benefits from improved financial performance,which has been driven Scott.Solomon@moodys.com by a combination of modest rate increases (about 2.6% in 2016 and 2.4% in 2017) and A.J.Sabatelte +1.212.553.4136 the implementation of cost control measures.As a result, MMPA's fixed obligation charge Associate Managing Director angelosabatelle@moodys.com coverage(FOCC) improved to more than 1.4x in 2016 and 2017 from 1.3x in 2015 and 1.2x in 2014.We anticipate MMPA's FOCC to remain in excess of 1.4x over the next three years CLIENT SERVICES allowing the joint action agency(JAA) to build-up incremental cash reserves that is expected Americas 1-212-553-1653 to be used to retire debt beginning in 2020. Asia Pacific 852-3551-3077 Rating outlook Japan 81-3-5408-4100 The stable outlook assumes MMPA's fixed obligation charge coverage remains in excess of EMEA 44-20-7772-5454 1.4x,that the credit quality of the members do not appreciably change, and that operating performance at the JAA's plants continue to remain strong. Factors that could lead to an upgrade • Significant deleveraging resulting in a debt ratio being less than 60%and an FOCC in excess of 2.0x on a consistent basis Factors that could lead to a downgrade » Underperformance of the JAA's generation assets or the execution of a power procurement process that materially erodes MMPA's cost competitiveness and financial metrics • Deterioration in the weighted average credit quality of its members. 144 MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE Key indicators Exhibit 1 MINNESOTA MUNICIPAL POWER AGENCY 2016 2017 Total Sales (mWh) 1,533,105 1,517,874 Debt Outstanding ($'000) 313,129 281,528 Debt Ratio (%) 79.4 72.3 sourcAd { EyasiL1quidity on Hand (incl. Bank Lines)(days) 203 261 Prdcted Obligation Charge Coverage (x) 1.4 1.4 MMPA is a municipal corporation existing under the laws of the State of Minnesota and founded for the purpose of securing an adequate,economical and reliable supply of electricity for its members.The members are cities located throughout Minnesota and have a diverse economic base. Each municipal member owns and operates an electric system which distributes and sells powers to its customers. Detailed credit considerations Resilient Service Area with Unregulated Rate Setting Ability Key drivers for MMPA's Al rating include the strong credit profile of its membership,who operate largely in the northern and southwestern suburbs of Minneapolis-St. Paul,an economically strong region,and the Agency's unregulated rate setting ability. The Agency's twelve municipal members have a weighted average credit quality that approximates the higher end of the "A" rating category.The weighted average credit assessment incorporates the Aa3 assigned to Elk River Municipal Utilities,who we anticipate will be MMPA's third largest customer when its joins the membership in October and the Al ratings assigned to Shakopee Public Utility Commission and Chaska Electric Enterprise,the two largest members. Each member has entered into individual power sale agreements(PSA)with MMPA that expire December 2050,with the exception of the City of Le Sueur and the City of Olivia that expire October 31, 2040. Under each PSA,the members have agreed to purchase and receive all electric power required to meet the needs of its customers from MMPA. Payments by the members are made monthly and consist of three components:a flat monthly customer charge,a demand charge per kWh and an energy charge.The energy charge is adjusted through an energy adjustment clause. MMPA has the right to alter its rates at any time. Its bond indenture requires MMPA to set rates sufficient to cover debt service by at least 1.15x. Each member has covenanted under its PSA to maintain rates to its customers sufficient to provide revenues adequate to meet its obligations to MMPA under the PSA. Procurement and Financial Strategy Support Improved Credit Profile A challenge confronting MMPA has been the need to match the long-term needs of its members to generation sources while taking into consideration the addition of a new member and increasing transmission costs while maintaining competitive rates. One answer has been to build distributed generation that is directly interconnected to its members electric distribution system,freeing up other generating resources.To that end, MMPA achieved commercial operation in February 2017 of the 46 megawatt Shakopee Energy Park that uses fuel-efficient reciprocating engines to generate local power for the city of Shakopee. MMPA has also entered into a long-term competitively priced capacity contract with a creditworthy third party that meets MMPA's capacity requirements from the Midcontinental Independent System Operator or MISO and replaces its need to construct incremental generating resources.Going forward, MMPA will rely on a combination of spot,contracted power purchases and owned resources This publication does not announce a credit rating action.For any credit ratings referenced in this publicanon,grease see the ratings tab on the issuer/entity page on www.rnoodys.com for the most updated credit rating action information and rating history. 2 1 August 2018 Minnesota Municipal Power Agency:Update following Moody's Upgrade to Al from A2;Outlook Stable 145 MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE to meet increased electric requirements and has the ability to adjust its energy charge through an energy adjustment clause should market derived power prices increase greater than anticipated. MMPA believes that keeping power prices to its members at or near current levels and no need for constructing incremental generating resources will allow it to build-up significant cash reserves that could be used to retire debt beginning 2020. State Regulatory Initiative Minnesota has one of the most aggressive renewable energy standards in the US. By 2025, 25%of all retail energy sold must be from renewable generation.This has ramped up from 17% by 2016, moving to 20% by 2020 and to 25% by 2025. Electricity generated by solar,wind,hydroelectric and biomass are eligible technologies under the standards. Moreover, open market purchases of RECs count toward the requirements. MMPA appears to be well positioned through a combination of owned and contracted resources to meet the renewable energy standard. MMPA's 2017 renewable generation was approximately 450,000 MWh's or 30% of retail energy sold. LIQUIDITY MMPA's available cash is sufficient,totaling approximately$56 million at December 31, 2017 or more than 250 days cash on hand. External liquidity is provided under a $20 million revolver due May 2019 with US Bank National Association (Al,stable).There was no amount borrowed under the revolver as of December 31,2017. DEBT STRUCTURE MMPA has a manageable debt profile.The utility's debt balance as of December 31, 2017 consisted of approximately$263 million of Electric Revenue Bonds.The Electric Revenue Bonds are secured by a pledge of the net revenues of the system and the indenture requires MMPA to set rates sufficient to produce at least 1.15x coverage of annual debt service. Scheduled debt maturities approximate $10 million in each of 2018 and 2019. PENSIONS AND OPEB Management and operations of MMPA is outsourced to Avant and as such has no employees and no pension obligation. Management and Governance MMPA's rating considers that it does not have any employees, making it somewhat unique amongst its peers. Rather,the JAA outsources all management and operational functions to various third-party vendors,a strategy that alters the entity's risk profile relative to its peers.That said,we have gained a degree of comfort with the Agency's long-term relationship with Avant Energy, Inc. (Avant),an unaffiliated energy management company that has provided management services for MMPA under contractual arrangements since 1992.The current contract between Avant and MMPA extends to 2026. 3 1 August 2018 Minnesota Municipal Power Agency:Update following Moody's Upgrade to Al from A2;Outlook Stable 146 MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE MethodologyThe principal methodology used in this rating was US Municipal Joint Action Agencies published in October 2012/As depicted below,the grid indicated rating of A2 is one notch lower then the assigned rating.The grid indicated rating,however,reflects historical financial performance that is expected to improve going forward. Factor Subfactori Descri pti on Score Metric 1.Participant Credit Quality and Cost Recovery Framework a)Weighted Average A2 participant credit quality. Unregulated rate setting including participants.Cost recovery structure and governance. 2.Resource Risk Management a)Resource Diversity.Asset A quality and complexity. Resource supply contract terms and counterparty credit quality.Wholesale market purchase exposure 3.Competitiveness a)Cost competitiveness A relative to regional peers 4.Financial Strength and Liquidity a)Adjusted days liquidity on Aa 200 hand (3-year avg)(days) b)Debt ratio(3-year avg)(%) A 74% c)Fixed obligation charge A 1.38x coverage ratio (3-year avg)(x) 5.Willingness to Recover Costs with Sound Financial Metrics a)Rate Setting Record. A Timeliness of rate recovery. Stability and strength of financial metrics Notching Conventions Notch 1 -Contractual Structure and 0 Legal Environment 2-Participant Diversity and 0 Concentration 3-Construction Risk 0 4-Debt Service Reserve,Debt 0 Structure and Financial Engineering_ 5-Unmitigated Exposure to 0 Wholesale Power Markets Scorecard Indicated Rating: A2 Source:Moody's Investors Service 4 1 August 2018 Minnesota Municipal Power Agency:Update following Moody's Upgrade to Al from A2;Outlook Stable 147 MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE ©2018 Moody's Corporation,Moody's Investors Service,Inc.,Moody's Analytics,Inc.andiar their licensors and affiliates(collectively,-' EW'S") Ail rightsreserved. 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REPORT NUMBER 1136132 5 1 August 2018 Minnesota Municipal Power Agency:Update following Moody's Upgrade to Al from A2;Outlook Stable 148 MOODY'S INVESTORS SERVICE INFRASTRUCTURE AND PROJECT FINANCE CLIENT SERVICES Americas 1-212-553-1653 Asia Pacific 852-3551-3077 Japan 81-3-5408-4100 EMEA 44-20-7772-5454 MOODY'S INVESTORS SERVICE 6 1 August 2018 Minnesota Municipal Power Agency.Update following Moody's Upgrade to Al from A2;Outlook Stable 149 Cap Anoka M M PA 9 Minnesota Municipal Power Agency 2017 Annual Report 0 C:0 C 0 0 c,17 0 42) )11 3 1 s \ g a ) f /„ e 0 t O e 3 5 ° / •® 00 \ ( / { a / •. « _2 s o \ E u z 2 \ f / \ \ / . \ / O ° ° ° ° \ � a / ) $ & / % 0 / . . . E - : s g -, o u E ) E •) \ \ \ } 0 \ \ 1, 0 E 3 = E a § _ & 0 a « .\ E w ° \ \ \ / � \ 3 ( 0 \ \ k \ — 3 6 % >s 4 �_ \ b E \ \ / = > / e e M f ) E \ \ } 8_ 0 ® \ \ M / E 6 & 6 » 2 ^ / a / } \ < ƒ \ ® \ \ \ \ 4 � c o s . . . . . : < \ M \ 11111 4 .. . . .\ ` ~ ^ % CD . = ;, . . = - . y� . . = / \\x\.ate. e . . . . . 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