CONTINUING DISCLOSURE REPORT

Transcription

1 Southern Minnesota Municipal Power Agency S.E.C. Rule 15c2-12 CONTINUING DISCLOSURE REPORT For Fiscal Year Ended December 31, 2012 OHSUSA:

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3 S.E.C. Rule 15c2-12 CONTINUING DISCLOSURE REPORT Southern Minnesota Municipal Power Agency, (the Agency ) hereby provides its Continuing Disclosure Report for the fiscal year ended December 31, 2012 in connection with the following Bonds: Bond Issues CUSIPS: A. Power Supply System Revenue Bonds, Series 2002 A (the 2002 Bonds ). Maturity (January 1) CUSIP WK WL WM WN WQ5 B. Power Supply System Revenue Bonds, Series 2006 A (the 2006 Bonds ). Maturity (January 1) CUSIP Maturity (January 1) CUSIP XU XZ XV YA XW YB XX YC XY YD2 C. Power Supply System Revenue Bonds, Series 2009 A (the 2009 Bonds ). Maturity (January 1) CUSIP Maturity (January 1) CUSIP YN YT YZ YU YP ZC ZA ZD YQ YV YR ZB YS YW0 OHSUSA: i

4 D. Power Supply System Revenue Bonds, Taxable Series 2010 A (Issuer Subsidy Build America Bonds) (the 2010 A Bonds ). Maturity (January 1) CUSIP Maturity (January 1) CUSIP ZE ZN ZF ZP ZG ZK ZH ZQ ZJ ZR ZM ZL3 E. Power Supply System Revenue Bonds, Series 2010 B (Tax-Exempt) (the 2010 B Bonds ; the 2010 A Bonds and the 2010 B Bonds are collectively referred to herein as the 2010 Bonds ). Maturity (January 1) CUSIP Maturity (January 1) CUSIP Annual Report ZS ZV ZT ZW ZU3 Note: The CUSIP numbers above are provided for the convenience of Bondholders. The Agency is not responsible for the accuracy or completeness of such numbers. The Agency s Annual Report as defined in the Continuing Disclosure Certificate dated September 6, 2002 with respect to the 2002 Bonds, the Continuing Disclosure Certificate dated September 6, 2006 with respect to the 2006 Bonds, the Continuing Disclosure Certificate dated July 21, 2009 with respect to the 2009 Bonds and the Continuing Disclosure Certificate dated October 21, 2010 with respect to the 2010 Bonds (such Continuing Disclosure Certificates are hereinafter referred to as the Disclosure Certificates ) for the fiscal year ended December 31, 2012 is attached hereto. Other Matters This Report is provided solely for the purposes of the Disclosure Certificates. The filing of this Report does not constitute or imply any representation (i) that all of the information provided is material to investors, (ii) regarding any other financial, operating or other information about the Agency or the Bonds, or (iii) that no changes, circumstances or events have occurred since the end of the fiscal year to which this Report relates (other than as referred to in this Report), or that no other information exists, which may have a bearing on the Agency s financial condition, the security for the Bonds, or an investor s decision to buy, sell, or hold the Bonds. The information contained in this Report has been obtained from sources that are believed to be reliable, but such information is not guaranteed as to accuracy or completeness. No statement in this Continuing Disclosure Report should be construed as a prediction or representation about future financial performance of the Agency. The information provided herein may relate to bonds and indebtedness of the Agency in addition to the ones listed above. Dated: September 27, 2013 OHSUSA: ii

5 SOUTHERN MINNESOTA MUNICIPAL POWER AGENCY Power Supply System Revenue Bonds, Series 2002 A, Series 2006 A, Series 2009 A, Taxable Series 2010 A (Issuer Subsidy Build America Bonds) and Series 2010 B (Tax-Exempt) CONTINUING DISCLOSURE REPORT FOR FISCAL YEAR ENDED DECEMBER 31, 2012 In accordance with the requirements of the Disclosure Certificates, the following information is provided with respect to the Agency s power supply system (the System ) for the fiscal year ended December 31, A. Audited Financial Statements: The financial statements of the Agency with respect to the System for the fiscal years ended December 31, 2012 and 2011, together with the report thereon of KPMG LLP, independent certified public accountants, are attached hereto as APPENDIX A. The financial statements of the Cities of Austin, Owatonna and Rochester (collectively, the Largest Members ), for the fiscal years ended December 31, 2012 and 2011, together with reports thereon of each of the independent certified public accountants of each of the Largest Members, are attached hereto as APPENDIX B. B. Updated Financial Information and Operating Data: The following information updates the financial information and operating data contained in the Official Statement of the Agency, dated September 6, 2002, relating to the 2002 Bonds, the Official Statement of the Agency, dated August 24, 2006, relating to the 2006 Bonds and certain of the information and operating data contained in the Official Statement, dated July 9, 2009, relating to the 2009 Bonds (the 2009 Bonds Official Statement ) and the Official Statement, dated October 14, 2010, relating to the 2010 Bonds (the 2010 Bonds Official Statement ; collectively, the Official Statements ) under the indicated captions. The 2009 Bonds Official Statement and the 2010 Bonds Official Statement are together referred to herein as the 2009/2010 Bonds Official Statements ). All capitalized terms used herein without definition have the respective meanings ascribed thereto in the Official Statements. OHSUSA:

6 CAPITAL EXPENDITURES/FINANCING PROGRAM The Agency s capital expenditures for the year ended December 31, 2012 were as follows: 2012 Generation $66,131,722 Transmission Lines and Substations 4,399,305 General Plant 103,114 Total $70,634,141 The Agency paid for its capital expenditures for the year ended December 31, 2012 from the proceeds of bonds and internally generated funds. The Generation amount includes Sherco 3 restoration expenditures of $42,640,000, which were paid from insurance proceeds. As of December 31, 2012, the Agency had outstanding commercial paper in the aggregate principal amount of $21,000,000 and currently has outstanding commercial paper in the aggregate principal amount of $21,000,000. On September 6, 2006 the Agency issued the 2006 Bonds in the principal amount of $40,000,000 in order to provide funds for the payment on November 30, 2006 of the principal and interest on $38,926,000 in principal amount of the Agency s Power Supply System Commercial Paper Notes, Series B (the CP ). The 2006 Bonds were issued on a parity with all of the Agency s Outstanding Bonds and the 2006 Bonds maturing on January 1, 2014 through January 1, 2019, inclusive, bear interest at a CPI Rate (the CPI Bonds ). In connection with the issuance of the CPI Bonds, the Agency entered into an interest rate swap agreement with Morgan Stanley Capital Services Inc., pursuant to the terms of which the Agency is required to pay a fixed interest rate and is entitled to receive a floating interest rate, each based on a notional amount equal to the principal amount of the CPI Bonds. [Remainder of page intentionally left blank] OHSUSA:

7 DEBT SERVICE REQUIREMENTS ON THE BONDS The following table shows the annual debt service requirements (calculated on a cash flow basis) for the 2002 Bonds, the 2006 Bonds, the 2009 Bonds and the 2010 Bonds Bonds Maturities Year Ending Total January 1 Principal Interest Debt Service 2014 $ 42,895,000 $ 9,735,075 $ 52,630, ,010,000 7,483,088 52,493, ,360,000 5,120,063 52,480, ,165,000 2,633,663 52,798, ,320,000 55,320,000 TOTAL $240,750,000 $24,971,889 $265,721, Bonds Maturities Year Ending Total January 1 Principal Interest (1) Debt Service 2014 $ 1,980,000 $1,326,850 $ 3,306, ,145,000 1,252,205 4,397, ,230,000 1,132,065 5,362, ,030, ,365 5,998, ,395, ,685 4,165, ,635, ,565 2,270, ,700, ,837 2,269, ,770, ,713 2,269, ,845, ,700 2,271, ,920, ,288 2,268, ,005, ,687 2,271, ,090, ,475 2,271, ,180,000 92,650 2,272,650 TOTAL $32,925,000 $8,471,085 $41,396,085 (1) For purposes of the foregoing table, interest on the CPI Bonds was calculated based on the fixed rates that the Agency is required to pay pursuant to a swap agreement entered into in connection with the CPI Bonds. OHSUSA:

8 2009 Bonds Maturities Year Ending Total January 1 Principal Interest Debt Service 2014 $ 2,145,000 $ 2,688,881 $ 4,833, ,250,000 2,585,331 4,835, ,350,000 2,483,581 4,833, ,470,000 2,366,081 4,836, ,565,000 2,267,281 4,832, ,670,000 2,161,475 4,831, ,790,000 2,044,663 4,834, ,915,000 1,919,113 4,834, ,060,000 1,773,363 4,833, ,215,000 1,620,363 4,835, ,380,000 1,453,263 4,833, ,555,000 1,277,588 4,832, ,740,000 1,090,950 4,830, ,940, ,600 4,834, ,145, ,750 4,832, ,365, ,138 4,835, ,590, ,975 4,830,975 TOTAL $54,145,000 $28,025,396 $82,170,396 OHSUSA:

9 2010 A Bonds 2010 B Bonds Maturities Year Ending January 1 Principal Interest (1)(2)(3) Total Principal Interest (1) Total Total Debt Service on 2010 Bonds (1)(2)(3) 2014 $ 2,427,114 $ 2,427,114 $1,500,000 $204,500 $1,704,500 $ 4,131, ,427,114 2,427,114 1,530, ,500 1,704,500 4,131, ,427,114 2,427,114 1,590, ,300 1,703,300 4,130, ,427,114 2,427,114 1,640,000 65,600 1,705,600 4,132, $ 1,705,000 2,427,114 4,132,114 4,132, ,745,000 2,385,288 4,130,288 4,130, ,790,000 2,341,348 4,131,348 4,131, ,835,000 2,295,110 4,130,110 4,130, ,885,000 2,246,517 4,131,517 4,131, ,935,000 2,195,376 4,130,376 4,130, ,990,000 2,140,990 4,130,990 4,130, ,050,000 2,082,472 4,132,472 4,132, ,110,000 2,020,191 4,130,191 4,130, ,190,000 1,941,659 4,131,659 4,131, ,270,000 1,860,150 4,130,150 4,130, ,355,000 1,775,663 4,130,663 4,130, ,445,000 1,688,012 4,133,012 4,133, ,535,000 1,597,011 4,132,011 4,132, ,630,000 1,501,837 4,131,837 4,131, ,730,000 1,403,097 4,133,097 4,133, ,835,000 1,299,714 4,134,714 4,134, ,940,000 1,192,356 4,132,356 4,132, ,055,000 1,079,110 4,134,110 4,134, ,175, ,434 4,136,434 4,136, ,295, ,136 4,134,136 4,134, ,425, ,216 4,137,216 4,137, ,555, ,289 4,135,289 4,135, ,690, ,354 4,133,354 4,133, ,835, ,219 4,136,219 4,136, ,985, ,498 4,138,498 4,138,498 TOTAL $67,990,000 $49,172,617 $117,162,617 $6,260,000 $557,900 $6,817,900 $123,980,517 (1) (2) (3) Net of capitalized interest funded from the proceeds of the 2010 Bonds. Net of cash subsidy payments from the United States Treasury in respect of interest on the 2010 A Bonds. See THE 2010 A&B BONDS Designation of the 2010 A Bonds as Build America Bonds in the 2010 Bonds Official Statement. Pursuant to the requirements of the Balanced Budget and Emergency Deficit Control Act of 1985, as amended, automatic reductions to the net of cash subsidy payments from the United States Treasury in respect of interest on the 2010 A Bonds commenced on March 1, The sequestration reduction rate of 8.7% is scheduled to be applied until the end of the current fiscal year (September 30, 2013) or intervening Congressional action, at which time the sequestration rate is subject to change. OHSUSA:

10 CROD MEMBERS AND OTHER EXCEPTIONS TO THE ALL REQUIREMENTS OBLIGATION OF THE POWER SALES CONTRACTS The following information updates the information relating to the CROD Members and other exceptions to the all requirements obligation of the Power Sales Contracts contained in the Official Statements (other than the 2009/2010 Bonds Official Statements) under the caption THE AGENCY Present and Future Power Supply Operations Present Power Supply Operations and in the 2009/2010 Bonds Official Statement under the caption THE AGENCY Power Supply Operations Obligations Under Power Supply Contracts, to read as follows: The Agency has power sales contracts (the Power Sales Contracts ) with each of the eighteen Members. Term of the Power Sales Contracts. The term of the Power Sales Contracts with Austin, Rochester and Waseca extends to April 1, 2030, and thereafter until terminated upon one year s prior notice by either party. The remaining 15 Members have extended their Power Sales Contracts to expire in 2050, and thereafter until terminated upon one year s prior notice by either party. Subject to the exceptions and limitations noted below, each Power Sales Contract requires the Agency to sell to the Member, and the Member to purchase from the Agency, all electric power and energy required by such Member for the operation of its municipal electric system for the term of the applicable Power Sales Contract. Exceptions to Total Requirements Provision. Two exceptions to this total requirements obligation of the Agency and the Members are provided in the Power Sales Contracts. First, each Member may acquire or construct hydro-electric facilities and utilize the capacity thereof, in an amount not exceeding 5 MW at any time, in the operation of its system. Second, three Members, Redwood Falls, Litchfield, and Fairmont, each of which has an allotment of power from Western Area Power Administration ( WAPA ), to purchase power and energy from WAPA, up to 8.9 MW for Redwood Falls, up to 12.7 MW for Litchfield, and up to 0.9 MW for Fairmont. As of December 31, 2012, WAPA supplied approximately 59 percent of Litchfield s power and energy, approximately 62 percent of Redwood Falls power and energy and approximately two percent of Fairmont s power and energy. In the event that Redwood Falls, Litchfield s, and Fairmont s allocation from WAPA is reduced or terminated, the Agency will be required to supply the power and energy requirements no longer supplied by WAPA. Limitation on Total Requirements Provisions of certain Members. Two Members have limitations on the amount of power and energy the Agency is required to sell and the Member is required to purchase. Rochester is still operating under its original Power Sales Contract which provides that, after 1999, the maximum amount of electric power the Agency is required to sell and OHSUSA:

11 Rochester is required to purchase is limited to the Contract Rate of Delivery, as defined therein. The Agency and Rochester have agreed that Rochester s Contract Rate of Delivery is 216 MW. Austin had extended its total requirements provisions to 2030, but subsequently gave the Agency notice under its Power Sales Contract, exercising its right to limit the amount of power the Agency is obligated to supply, and Austin is obligated to purchase, to a Contract Rate of Delivery, effective January 1, Consequently, commencing January 1, 2016, the amount of power the Agency is obligated to supply to Austin, and the amount Austin is obligated to purchase from the Agency, will be limited to the peak demand of Austin, as determined by the Agency, for calendar year Rights of Other Members to Set Contract Rates of Delivery. All Members other than Rochester and Austin have amended their Power Sales Contracts to extend the total requirements provisions through the terms of their respective Power Sales Contracts. Thus Waseca s total requirements provision extends into 2030 and the total requirements provision for each of the remaining fifteen Members extends into 2050, in each case subject to the right to establish a Contract Rate of Delivery as described below. These amendments to the Power Sales Contracts provide that at any time, unless the Agency is developing a resource for the production or transmission of electric power and energy to be used to supply power and energy under the Power Sales Contracts (a Power Supply Resource ), the Agency or the Member may, by seven years notice to the other party, limit the amount of power the Agency is obligated to supply, and the Member is obligated to purchase, to the Member s Contract Rate of Delivery. Under the amended Power Sales Contracts, Contract Rate of Delivery is defined to mean the peak demand of the Member, as determined by the Agency, for the calendar year immediately preceding the calendar year in which the Contract Rate of Delivery limitation is to take effect. Neither the Member nor the Agency may give to the other a notice electing to initiate such Contract Rate of Delivery limitation during any period of time when the Agency is developing a Power Supply Resource. Such period shall commence no earlier than the date on which the Agency first enters into a contract to sell Bonds to finance any costs associated with such Power Supply Resource and shall end no later than the earlier of the actual date on which the Agency first receives power and energy or transmission services, as the case may be, from such Power Supply Resource or the date on which the Agency determines not to proceed with the development of such Power Supply Resource. CAPACITY PURCHASES FROM THE AGENCY S MEMBERS The following information updates the information contained in the Official Statements (other than the 2009/2010 Bonds Official Statements) under the caption THE AGENCY Present and Future Power Supply Operations Capacity Purchase from Members and in the 2009/2010 Bonds Official Statements under the caption THE AGENCY Power Supply Operations Present Power Supply and Transmission Operations, to read as follows: The Agency currently has Capacity Purchase Agreements with thirteen Members that own electric generating resources. OHSUSA:

12 Most of the Agency s Member-owned capacity is covered by Capacity Purchase Agreements that provide for the pass-through of certain costs from the particular Member to the Agency ( Pass-through Capacity Purchase Agreements ). Under the Pass-through Capacity Purchase Agreements, the applicable Member has the responsibility for maintaining the facilities in readily operable condition and to provide the necessary personnel to operate the facilities, while the Agency will (i) have sole authority for hourly scheduling and dispatching of generation; (ii) be responsible for operation and maintenance costs as well as certain renewal and replacement costs as specified under the Pass-through Capacity Purchase Agreements; and (iii) be responsible for procuring all fuel necessary for the facility and for the cost of the fuel and the cost of delivering the fuel to the facility. Under these Pass-through Capacity Purchase Agreements, the Member retains 100 percent ownership of the applicable facility; however, in most cases, all items of equipment, additions to the facility, improvements thereto and other property added to or replacing part of the facility after the date ( Turnover Date ) such unit was dedicated to the Agency under such Capacity Purchase Agreement or a previous similar contract (the Turnover Dates vary from 1991 through 1995, depending on the applicable unit) pursuant to the renewal and replacement budget and paid for by the Agency are the sole property of the Agency (subject to certain repurchase obligations of such Member). Under the Pass-through Capacity Purchase Agreements, the Member agrees to indemnify the Agency for certain costs, expenses and/or liabilities incurred by the Agency as a result of any contamination and/or clean-up, imposition of liens and/or third party claims, arising out of the existence or claimed existence of hazardous substance in the plant or on the plant site occurring before the Turnover Date with certain exceptions, all according to the terms of the Pass-through Capacity Purchase Agreements. The Pass-through Capacity Purchase Agreements extend through the earlier of the retirement date of the applicable resource or five years after written notice of termination given by either party. The Agency may shorten the notice requirement to one year if the renewal and replacement budget required to keep the plant operational is determined by the Agency to be uneconomical. The Agency currently has Pass-through Capacity Purchase Agreements with (i) Owatonna for its gas-fired combustion turbine unit and (ii) Blooming Prairie, Litchfield, Mora, New Prague, Preston, Princeton, Redwood Falls, Spring Valley, and Wells for their respective diesel units. In addition, the Agency has entered into quick start capacity purchase agreements with Blooming Prairie, Grand Marais, Litchfield, North Branch, Princeton, Redwood Falls, Saint Peter and Spring Valley for new diesel units with ten minute start capability (collectively, the Quick-Start Capacity Purchase Agreements ). Under these agreements, each such Member finances, builds and operates its unit(s) at its sole expense and provides the output of the unit(s) exclusively to the Agency in exchange for a fixed dollar-per-kilowatt monthly payment to the applicable Member and payment of fuel costs. The Quick-Start Capacity Purchase Agreements are otherwise similar to the Pass-through Capacity Purchase Agreements but have a minimum term of twenty years and can be OHSUSA:

13 renewed by the Agency for successive five-year periods thereafter. A total of approximately 57 MW of diesel generation was installed and put into operation during 2003 through mid 2012 as part of the Quick Start Capacity Purchase Agreements. Approximately 141 MW of Dedicated Capacity is available to the Agency, including 53 diesel units with an aggregate rating of approximately 124 MW and one combustion turbine unit with an aggregate rating of approximately 17 MW. In 2011, the Agency acquired from Fairmont the site and generation facilities formerly under contract with the Agency. While two existing diesel powered generators (12 MW total capacity) will remain in service, substantial portions of this facility were demolished in preparation for construction of new generating resources. A new building was constructed to house the additional resources. The new generating facilities include four Caterpillar Inc. ( Caterpillar ) high efficiency natural gas powered reciprocating engines with a combined total output of 25 MW, along with all ancillary fuel, cooling and emissions control systems. Construction of the new facilities is nearing completion and commercial operation is anticipated in the fourth quarter of In order to meet its power supply obligations, the Agency has also implemented certain demand side management programs and has entered into certain mediumterm power purchases from other utilities. The Minnesota Legislature s establishment of the Renewable Energy Standard ( RES ) in 2007 requires that the Agency purchase or produce increasing percentages of its energy from renewable resources. The Agency owns six wind turbines (8.5 MW of capacity) installed between 2003 and To meet the RES, the Agency uses energy from: the wind turbines it owns, bio-diesel fueled generation contracted to the Agency, a purchased power agreement from a waste-to-energy facility located in a Member s community, a twenty-year agreement with EDF Renewable Energy, Inc. (formerly known as enxco, Inc.) ( EDF ) to purchase the output from a MW wind farm located near Dexter, Minnesota, renewable energy certificates ( RECs ) purchased from a Member hydroelectric facility and purchases from the REC market. In addition, the Agency recently completed construction of a 1.6 MW landfill gas generation project near Mora, Minnesota that began commercial operation on April 2, The combination of production and allowed banking of associated certificates from this portfolio of resources, along with the market purchase of RECs, is projected to meet the Agency s RES requirement through The Agency offers its Members the opportunity to purchase RECs for customers interested in supporting renewable energy in addition to that supplied as a part of Agency base energy delivery. OHSUSA:

14 In 2013, the Minnesota Legislature made some changes to Minnesota s net metering rules and established a Solar Electric Standard ( SES ). Net metering rules for cooperative and municipal utilities remain unchanged and the SES only applies to Minnesota s investor owned utilities. RATES The following information updates the information contained in the Official Statements (other than the 2009/2010 Bonds Official Statements) under the caption THE AGENCY Competitive Position and Rates and in the 2009/2010 Bonds Official Statements under the caption THE AGENCY Rates and Trends, to read as follows: Each Member is required to pay for power and energy furnished by the Agency at rates established by the Agency. Such rates are required to be established at a level which will provide for the recovery of the Agency s total Revenue Requirements, including debt service on the Bonds and other amounts required to be deposited in funds established under the Resolution. For additional information concerning payments by the Members under the Power Sales Contracts, see Payments by the Members in the Appendix to the Official Statements entitled Summary of Certain Provisions of the Power Sales Contracts. The Agency s Revenue Requirements include amounts required to comply with any rate covenant of the Agency. Under the Resolution, the Agency has covenanted to establish and collect rates, fees and charges for the output of the System which, together with other available Revenues, are reasonably expected to yield Net Revenues for the twelve-month period commencing with the effective date of such rates, fees and charges equal to at least 1.10 times Aggregate Debt Service on Bonds for such period and, in any event, as required, together with other available funds, to pay or discharge all other indebtedness, charges and liens payable out of Revenues. For purposes of this covenant, amounts required to pay Refundable Principal Installments may be excluded from Aggregate Debt Service to the extent that the Agency intends to make such payments from sources other than Revenues. The Agency is required to review and, if necessary, revise its rates, fees and charges upon the occurrence of a material change in circumstances, but in any case at least once every twelve months. See the Appendix to the Official Statements entitled Summary of Certain Provisions of the Resolution for definitions of the terms System, Net Revenues, Aggregate Debt Service and Refundable Principal Installment. Members are billed for power and energy furnished by the Agency primarily under the Base Rate established under Schedule B of the Power Sales Contracts (the Base Rate ). The 2012 Base Rate (effective January 1, 2012) consists of a power supply demand charge of $10.66 per kw/month, an on-peak power supply energy charge of $ per kwh, an off-peak energy charge of $ per kwh, and a transmission charge of $2.66 per kw/month. Under the 2012 Base Rate schedule, the power supply billing demand for any monthly billing period is the greater of the metered demand coincident to the Agency s highest demand measured for the period or 74 percent of the metered demand coincident to the OHSUSA:

15 Agency s highest metered demand measured during the most recent full summer season (June through September). The transmission billing demand for any monthly billing period is 100 percent of the metered demand coincident to the Agency s highest metered demand measured during the most recent full summer season (June through September). Designated on-peak hours are those hours between 10:00 a.m. and 10:00 p.m. Monday through Friday, excluding certain designated holidays. The current Base Rate schedule also includes a cost adjustment clause under which the power supply on- and off-peak energy charges are adjusted if the Agency s costs of energy production (including purchased power costs) are greater or less than $ per kwh during designated on-peak hours and $ per kwh during designated off-peak hours. The Agency may implement changes in its rates after 90 days notice to the Members. The average cost of power and energy provided by the Agency to the Members through 2012 has increased by 52.8 percent since 2003, an average of slightly over 5.0 percent per year. The following table sets forth the annual average cost of power and energy provided by the Agency to the Members along with the annual percentage change for the 2003 through 2012 time period. Members Historical Average Cost of Power and Energy from the Agency Average Cost of Power and Energy (cents/kwh) Annual Percent Change Year (1.4) (0.8) The Average Cost of Power increases between 2006 and 2010, shown in the above table, were the result of factors impacting the electric industry as a whole on both a regional and national basis. Factors included increases in natural gas, coal and rail prices, the development and implementation of Midwest (now Mid- Continent ) Independent System Operator, Inc. ( MISO ) day 2 energy markets, and major storms such as Hurricane Katrina, which imposed significant upward pressure on natural gas, oil, and electric market prices. Changes in the Average Cost of Power in 2011 and 2012 were due to kwh sales volume differences between those years and the relative amount of sales on and off peak. The Agency s Member rates, consisting of its demand charge, on and off peak energy charges, and transmission charge have remained unchanged since January 1, OHSUSA:

16 At the end of 2005, the Agency entered into a wholesale marketing agreement with The Energy Authority, Inc. ( TEA ), a Georgia nonprofit corporation founded by public power utilities in Under that agreement, TEA assists the Agency with wholesale marketing activities. Specifically, TEA is exclusively responsible for the Agency s real-time and medium-term energy transactions. TEA brings to the Agency significant expertise in markets such as the MISO market which uses locational marginal pricing. The Agency remains directly involved in energy marketing activities, working closely with TEA on a day-today basis. The TEA risk management services are coordinated with the periodic review of the Agency s financial reserves as performed by the Agency s financial advisor, Public Financial Management, Inc. TEA also provides the Agency with risk management services related to the Agency s power supply portfolio. These services are focused on identifying ways in which the Agency can reduce its cash flow at risk from areas primarily outside of the Agency s control such as, among others, unplanned generating unit outages, market price fluctuations and fuel price fluctuations. [Remainder of page intentionally left blank] OHSUSA:

17 FINANCIAL RESULTS OF THE AGENCY S OPERATIONS The following Summary of Operations is qualified in its entirety by reference to the Financial Statements of the Agency (including the related Notes) set forth in APPENDIX A. In the 2009/2010 Bonds Official Statements the following is referred to as the Statements of Revenues, Expenses and Changes in Net Position. SUMMARY OF OPERATIONS AND NET POSITION Year Ended December 31, 2012 Operating revenues Power sales... $ 241,436,566 Rate stabilization (contributions)/distributions... (184,994) Total operating revenues... $241,251,572 Operating expenses Production fuel ,210 Power production ,608,034 Other operating expenses... 44,275,363 Depreciation and amortization... 15,729,147 Expenses to be recovered in future periods... Deferred costs expensed in current period ,236 Total operating expenses ,476,990 Operating income... 52,774,582 Nonoperating income Investment earnings... 1,569,104 Miscellaneous income... 1,306,908 Total other revenues... 2,876,012 Nonoperating other expenses Interest expense... 19,670,487 Deferred costs expensed in current period... 1,347,137 Amortization of long-term debt issuance costs... 1,202,645 Amortization of discount/premium on long-term debt... 25,033,835 Total nonoperating expenses... 47,254,104 Change in net position... $8,396,490 Net Position Beginning of period... 67,048,313 End of period... $75,444,803 OHSUSA:

18 Operating revenues take into account amounts transferred to or from the Rate Stabilization Account as permitted by the Resolution. The amount transferred to the Rate Stabilization Account for the year ended December 31, 2012 was $184,994 and the balance in the Rate Stabilization Account at December 31, 2012 was $100,615,307, of which $94,609,883 was classified as Long-term liabilities Deferred Credits and $6,005,424 was classified as Current liabilities Deferred Credits. THE MEMBERS The economy of the region is largely dependent upon agriculture. In addition, there is significant industrial and other commercial activity. As reflected by the large IBM facility and the Mayo Clinic in Rochester and the Hormel food processing plant in Austin, the region s economy has developed a high technology and service-based element which complements the traditional agricultural segment. Manufacturing activity involves the manufacture of electronic components, chemicals and plastics. The IBM facility and the Mayo Clinic together accounted for approximately 17.4 percent of Rochester s operating revenues for the year ended December 31, Hormel accounted for approximately 27.3 percent of Austin s operating revenues for the year ended December 31, 2012 and Viracon accounted for approximately 19.2 percent of Owatonna s revenues for the year ended December 31, As is not uncommon in the electric utility industry, large industrial customers of certain Members have conducted studies relating to additional generation to supply all or a portion of their own electric generation and may conduct such studies in the future. Other than the Mayo Clinic and Hormel, each of which currently supplies some of its own power, the Agency is not aware that any of the other industrial customers of any of the Members have adopted plans either to begin supplying all or a portion of their own electric generation, or to increase their present capability to supply themselves with additional generation. Hormel currently has seven, 2 MW diesel-fired units which it uses for its back-up and peaking needs. The Agency has entered into an agreement with Hormel which allows the Agency, if Hormel is not using the generation from these units, to make up to twelve calls annually for a maximum nine hour run (within permitting guidelines). The Agency would be responsible for the cost of any fuel used during such periods. According to the Minnesota State Demographic Center and Metropolitan Council, the eighteen Members had a combined population of approximately 242,705 in As of December 31, 2012, the Members provided electric service to approximately 112,100 residential, commercial, industrial and other customers. As reflected in the following table, in 2012 one city, Rochester, accounted for approximately 43.4 percent of the Members energy requirements and three Members together accounted for approximately 67.6 percent of the Members energy requirements. Austin, Rochester and Waseca have notified the Agency that they do not wish to extend the terms of their Power Sales Contracts beyond the current expiration date of April 1, Austin has given notice that it will set its Contract Rate of Delivery based on its 2015 peak demand, effective January 1, OHSUSA:

19 2012 Energy Requirements of the Members Energy Member MWh Percentage Rochester... 1,274, % Owatonna , % Austin , % Fairmont , % Lake City , % Litchfield , % Saint Peter... 97, % Redwood Falls... 72, % New Prague 67, % Waseca... 65, % Mora... 58, % Princeton... 53, % North Branch... 27, % Blooming Prairie... 25, % Grand Marais... 23, % Spring Valley... 20, % Wells... 19, % Preston... 14, % TOTALS... 2,957, % (a) The percentages shown are based upon the total energy requirements of each City in 2012, including energy supplied through purchases from WAPA. MEMBERS HISTORICAL POWER AND ENERGY REQUIREMENTS The table below summarizes the growth in the aggregate power and energy requirements of the Members electric systems during the period 2008 through [Remainder of page intentionally left blank] OHSUSA:

20 Members Historical Power and Energy Requirements from the Agency Inlet to Member Systems Peak Demand (1) Energy Year (MW) Percent Change (MWh) Percent Change (0.6) 2,928,147 (1.2) (2.8) 2,737,119 (6.5) ,823, ,827, (1.9) 2,822,105 (0.2) Average Annual Compound Growth Rate: : 0.6 (0.7) (1) The peak demand is the sum of the coincident peak demands for each of the Members during the month when the Agency s demand is higher than any other month of the year. THE POWER SUPPLY SYSTEM The following information updates the information in the Official Statements under the caption THE POWER SUPPLY SYSTEM Power Supply Resources Sherco 3 as follows: Sherco 3 operates based on an overhaul cycle of one major planned overhaul every three years. The last planned overhaul occurred in the fall of 2011 and included a retrofit of the intermediate and high pressure turbine sections intended to increase net power output, without an increase in fuel consumption. In addition, a detailed inspection of the boiler was conducted in order to help identify the remaining useful life of various boiler sections. This information will be used to perform a life cycle analysis of the boiler and plan for future section replacements. A new step-up transformer was also installed to allow for the increased power output due to the new turbine sections. On November 19, 2011, Sherco 3 experienced a catastrophic failure as the unit was being returned to service following the planned overhaul. The event caused extensive damage to the turbine, generator, exciter and some associated plant systems. No injuries occurred, however, two workers were treated for smoke inhalation from a fire associated with the incident. Since November 19, 2011, more than one million man-hours have been worked by numerous contractors and plant staff to repair and reassemble the damaged steam turbine, generator and associated equipment. This effort included disassembling and shipping off-site for repair all of the steam turbine components. The generator stator core was removed and re-stacked on site and the generator rotor was shipped off-site to be rewound. The generator exciter was not OHSUSA:

21 repairable; however, a compatible used exciter was acquired and rebuilt. The condenser section of the steam system was heavily damaged and was removed and replaced with all new components. The balance of the plant, including the boiler and fuel handling systems, was undamaged and secured for safe, long-term shut down while the turbine/generator was being repaired. The restoration project has been completed and it is currently in the start-up process. This will involve an extensive period of commissioning and testing the many systems that were repaired, replaced or have been sitting idle for several months. The plant is expected to return to commercial operation in the early part of the fourth quarter of Insurance has covered the vast majority of the costs for repairs. While the unit has been out of service, the Agency and NSP elected to advance other maintenance and replacement projects that were planned to be done during planned outages in future years. This work included rebuilding boiler feed pumps and replacing the cooling towers. The cooling towers were planned to be replaced in sections over several years beginning in This work has been completed and will improve the overall efficiency of the unit. While Sherco 3 was out of service, the Agency, working with its power marketing partner, TEA, was able to purchase replacement capacity and energy in the forward market and effectively hedge the potential market price exposure. Due to the level of prices in the region, the replacement capacity and energy costs did not have a material effect on the Agency s budget or rates. While Sherco 3 s equivalent availability and capacity factors have historically been at or above the national average for similar facilities, these factors have been significantly impacted by this extended outage. For the five-year period of 2008 through 2012, Sherco 3 s equivalent availability factor, including unscheduled outages and the planned overhauls, was percent with a net capacity factor of percent. The national five-year averages for similar-sized coal plants for the period of 2007 through 2011 were percent and percent, respectively. The national five-year averages for all coal-fired plants for the period of 2007 through 2011 were percent and percent, respectively. National five-year averages for the period of 2008 through 2012 are not available at this time. Once Sherco 3 returns to commercial operation, we anticipate that the equivalent availability and capacity factors will return to their historical levels. On June 14, 2011, the EPA issued a Notice of Violation (a NOV ) to Xcel and NSP, alleging violations of the Clean Air Act at the Sherburne County Generating Station (at which Sherco 3 is located) and at another generating station owned by Xcel. NSP reported that the NOV specifically alleges that various maintenance, repair and replacement projects undertaken at the plants in the mid-2000s should have required a permit under the New Source Review ( NSR ) process. NSP OHSUSA:

22 reported that it believes it has acted in full compliance with the Clean Air Act and NSR process. NSP also reported that it believes that the projects identified in the NOV fit within the routine maintenance, repair and replacement exemption contained within the NSR regulations or are otherwise not subject to the NSR requirements. NSP further reported that it disagrees with the assertions contained in the NOV and will vigorously defend its position. The Agency attended a meeting between NSP and the EPA in August 2011, at which NSP stated and defended its position. The Agency is not aware of additional contact with or communication from the EPA on this matter since that meeting. The current status of this matter is unclear and the potential impact on Sherco 3 has not yet been determined. The following information updates the information contained in the second and third paragraphs in the Official Statement, dated August 24, 2006, relating to the 2006 Bonds, the second and third paragraphs under the 2009 Bonds Official Statement and the second, third and fourth paragraphs under the 2010 Bonds Official Statement, each under the caption THE POWER SUPPLY SYSTEM Power Supply Resources Wind Turbine Program to read as follows: In 2003, the Agency installed two 950 kw wind turbines which were interconnected to the City of Fairmont s distribution system. In late 2004 and early 2005 the Agency installed four 1,650 kw wind turbines, two interconnected to the City of Fairmont s distribution system and two more interconnected to the City of Redwood Falls distribution system. On April 3, 2008, the Agency entered into a twenty-year power purchase agreement with EDF, headquartered in Escondido, California, to supply the Agency all the capacity from a MW wind farm located near Dexter, Minnesota. The Agency estimates that the annual output from the wind farm will exceed 300,000 megawatt hours. The wind farm consists of 67 General Electric 1.5 MW turbines. An identical wind farm developed by EDF is located in the same vicinity and is owned by Xcel. The long-term purchase of this wind energy represents the Agency s commitment to minimize future GHG emissions and meet Minnesota RES requirements. The wind project was completed in late 2008 and went into commercial operation in February The Agency s portfolio approach to meet its Minnesota RES compliance also includes a 1.6 MW landfill gas generator, which began commercial operation on April 2, 2012, and a purchase of 520,000 RECs in late The Agency expects that, with the REC banking provisions of the Minnesota RES, the output from the EDF wind farm, combined with the energy from the Agency's other renewable resources, will allow the Agency to comply with the Minnesota RES through the end of The Agency continues to evaluate additional renewable energy options. OHSUSA:

23 The following information updates the information contained in the third paragraph in the 2010 Bonds Official Statement, under the caption THE POWER SUPPLY SYSTEM Transmission General to read as follows: The Agency had an integrated transmission agreement ( ITA Agreement ) with GRE. That agreement generally included provisions for (i) certain initial payments to compensate the owner of existing transmission facilities for the use of capacity in the existing system; (ii) providing sufficient transmission capacity to deliver the firm power and energy requirements of the utility s customers and the Agency s Members; (iii) formation of the coordinating committee to jointly plan facilities in the geographic areas where the Agency and the utility s service areas overlap; (iv) each utility to construct and own transmission facilities required to be added to the system in proportion to the respective load growth of each system; (v) certain requirements and remedies for maintaining balance of ownership of the transmission facilities included in the shared transmission system; (vi) annual adjustments to be applied to the investment responsibility of a party which is under-invested to recognize escalation in the costs of construction and transmission carrying charges for the use of the over-invested party s system by the under-invested party; (vii) a term of 35 years with automatic five year extensions; and (viii) operating the shared transmission system and metering of the electricity delivered by the shared transmission system. In April 2010, the Agency entered into an agreement with GRE to form a joint pricing zone under MISO and terminate the ITA Agreement between the Agency and GRE when certain conditions were met. Those conditions have been met and the ITA Agreement has been terminated. The Agency now uses MISO network service to serve its loads in the GRE MISO joint pricing zone. The Agency has a shared transmission agreement ( STS Agreement ) with Dairyland generally including the provisions listed in the preceding paragraph. The Agency and Dairyland are both participants in a CapX 2020 transmission project described below, and have agreed that, upon the successful completion and energization of these specific transmission facilities, both parties obligations under the STS Agreement will be equalized. The Agency and Dairyland agree that, at that time, the STS Agreement and any future associated investment obligations will be frozen. The completion of the CapX 2020 transmission facilities and freezing of the STS Agreement are planned to occur by the end of The following information updates the information contained in the second, third and fourth paragraphs in the 2010 Bonds Official Statement, under the caption THE POWER SUPPLY SYSTEM Transmission CapX 2020 to read as follows: CapX 2020 has received regulatory approval for three projects, totaling approximately 640 miles of 345 kv line in Minnesota, with short segments in North Dakota, South Dakota and Wisconsin, plus miles of 161 kv lines in Minnesota. The aggregate estimated cost of these facilities is $1.9 billion. OHSUSA:

24 These approved projects include the Hampton Rochester La Crosse Transmission Project (previously referred to as the SE-TC Rochester La Crosse Transmission Project ). In March 2007, the Agency executed a Project Development Agreement with CapX 2020 and other participating utilities (the Project Development Agreement ) for this project and executed the Project Agreements in December The Agency is participating with a 13% ownership share in this project. Other project participants include NSP, Dairyland, Rochester Public Utilities and WPPI. This approximately $500 million project includes 120 miles of 345 kv line that will run between a new substation in Hampton, Minnesota and a new substation north of Pine Island, Minnesota, and continue on to cross the Mississippi River near Alma, Wisconsin. A single circuit 345 kv line will be built in Wisconsin to a new substation in the area of La Crosse, Wisconsin. A new 161 kv line is being constructed between the Pine Island area substation and the existing Northern Hills substation in northwest Rochester, Minnesota. Also a new 161 kv line is being constructed between the Pine Island area substation and the existing Chester substation in northeast Rochester, Minnesota. Pursuant to the Project Agreements, NSP is identified as the development manager for this project, responsible for managing the permitting process, engineering, procurement and construction of the project facilities. This project is currently under construction and is scheduled to be completed by the end of The Agency s share of the project is approximately $70 million. THE LARGEST MEMBERS Financial information for the Largest Members is included in APPENDIX C hereto. OHSUSA: