S.E.C. Rule 15c2-12
CONTINUING DISCLOSURE REPORT
For Fiscal Year Ended
December 31, 2012
Bond Issues
CUSIPS:
A. Power Supply System Revenue Bonds, Series 2002 A (the “2002 Bonds”). Maturity (January 1) CUSIP 2014 843375 WK8 2015 843375 WL6 2016 843375 WM4 2017 843375 WN2 2018 843375 WQ5
B. Power Supply System Revenue Bonds, Series 2006 A (the “2006 Bonds”). Maturity
(January 1) CUSIP (January 1)Maturity CUSIP
2014 843375 XU5 2019 843375 XZ4
2015 843375 XV3 2020 843375 YA8
2016 843375 XW1 2021 843375 YB6
2017 843375 XX9 2022 843375 YC4
2018 843375 XY7 2023 843375 YD2
C. Power Supply System Revenue Bonds, Series 2009 A (the “2009 Bonds”). Maturity
(January 1) CUSIP (January 1)Maturity CUSIP
2014 843375 YN0 2019 843375 YT7 2014 843375 YZ3 2020 843375 YU4 2015 843375 YP5 2021 843375 ZC3 2015 843375 ZA7 2022 843375 ZD1 2016 843375 YQ3 2024 843375 YV2 2017 843375 YR1 2024 843375 ZB5 2018 843375 YS9 2030 843375 YW0
2019 843375 ZF6 2025 843375 ZP4
2020 843375 ZG4 2030 843375 ZK5
2021 843375 ZH2 2032 843375 ZQ2
2022 843375 ZJ8 2034 843375 ZR0
2023 843375 ZM1 2043 843375 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 (January 1)Maturity CUSIP
2013 843375 ZS8 2016 843375 ZV1
2014 843375 ZT6 2017 843375 ZW9
2015 843375 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.
Annual Report
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.
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, 2012.
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.
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.
2002 Bonds Maturities
Year Ending Total
January 1 Principal Interest Debt Service
2014 $ 42,895,000 $ 9,735,075 $ 52,630,075 2015 45,010,000 7,483,088 52,493,088 2016 47,360,000 5,120,063 52,480,063 2017 50,165,000 2,633,663 52,798,663 2018 55,320,000 – 55,320,000 TOTAL $240,750,000 $24,971,889 $265,721,889 2006 Bonds Maturities
Year Ending Total
January 1 Principal Interest (1) Debt Service
2014 $ 1,980,000 $1,326,850 $ 3,306,850 2015 3,145,000 1,252,205 4,397,205 2016 4,230,000 1,132,065 5,362,065 2017 5,030,000 968,365 5,998,365 2018 3,395,000 770,685 4,165,685 2019 1,635,000 635,565 2,270,565 2020 1,700,000 569,837 2,269,837 2021 1,770,000 499,713 2,269,713 2022 1,845,000 426,700 2,271,700 2023 1,920,000 348,288 2,268,288 2024 2,005,000 266,687 2,271,687 2025 2,090,000 181,475 2,271,475 2026 2,180,000 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
2015 2,250,000 2,585,331 4,835,331 2016 2,350,000 2,483,581 4,833,581 2017 2,470,000 2,366,081 4,836,081 2018 2,565,000 2,267,281 4,832,281 2019 2,670,000 2,161,475 4,831,475 2020 2,790,000 2,044,663 4,834,663 2021 2,915,000 1,919,113 4,834,113 2022 3,060,000 1,773,363 4,833,363 2023 3,215,000 1,620,363 4,835,363 2024 3,380,000 1,453,263 4,833,263 2025 3,555,000 1,277,588 4,832,588 2026 3,740,000 1,090,950 4,830,950 2027 3,940,000 894,600 4,834,600 2028 4,145,000 687,750 4,832,750 2029 4,365,000 470,138 4,835,138 2030 4,590,000 240,975 4,830,975 TOTAL $54,145,000 $28,025,396 $82,170,396
2018 $ 1,705,000 2,427,114 4,132,114 – – – 4,132,114 2019 1,745,000 2,385,288 4,130,288 – – – 4,130,288 2020 1,790,000 2,341,348 4,131,348 – – – 4,131,348 2021 1,835,000 2,295,110 4,130,110 – – – 4,130,110 2022 1,885,000 2,246,517 4,131,517 – – – 4,131,517 2023 1,935,000 2,195,376 4,130,376 – – – 4,130,376 2024 1,990,000 2,140,990 4,130,990 – – – 4,130,990 2025 2,050,000 2,082,472 4,132,472 – – – 4,132,472 2026 2,110,000 2,020,191 4,130,191 – – – 4,130,191 2027 2,190,000 1,941,659 4,131,659 – – – 4,131,659 2028 2,270,000 1,860,150 4,130,150 – – – 4,130,150 2029 2,355,000 1,775,663 4,130,663 – – – 4,130,663 2030 2,445,000 1,688,012 4,133,012 – – – 4,133,012 2031 2,535,000 1,597,011 4,132,011 – – – 4,132,011 2032 2,630,000 1,501,837 4,131,837 – – – 4,131,837 2033 2,730,000 1,403,097 4,133,097 – – – 4,133,097 2034 2,835,000 1,299,714 4,134,714 – – – 4,134,714 2035 2,940,000 1,192,356 4,132,356 – – – 4,132,356 2036 3,055,000 1,079,110 4,134,110 – – – 4,134,110 2037 3,175,000 961,434 4,136,434 – – – 4,136,434 2038 3,295,000 839,136 4,134,136 – – – 4,134,136 2039 3,425,000 712,216 4,137,216 – – – 4,137,216 2040 3,555,000 580,289 4,135,289 – – – 4,135,289 2041 3,690,000 443,354 4,133,354 – – – 4,133,354 2042 3,835,000 301,219 4,136,219 – – – 4,136,219 2043 3,985,000 153,498 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) Net of capitalized interest funded from the proceeds of the 2010 Bonds.
(2) 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.
(3) 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, 2013. 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.
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
power the Agency is obligated to supply, and Austin is obligated to purchase, to a
Contract Rate of Delivery, effective January 1, 2016. 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 2015.
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.
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
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 2013.
In order to meet its power supply obligations, the Agency has also implemented
certain demand side management programs and has entered into certain
medium-term 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 2005. 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 100.5 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, 2012.
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 2020.
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.
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 $0.05413 per kWh, an off-peak energy charge of $0.04046 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
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 $0.05413 per kWh during designated on-peak
hours and $0.04046 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
Year
Average Cost of Power and Energy
(cents/kWh) Annual PercentChange
2003 4.639 0.1 2004 4.573 (1.4) 2005 4.537 (0.8) 2006 5.343 17.8 2007 5.994 12.2 2008 6.129 2.3 2009 6.631 8.2 2010 7.024 5.9 2011 7.039 0.2 2012 7.089 0.7
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,
2010.
market which uses locational marginal pricing. The Agency remains directly
involved in energy marketing activities, working closely with TEA on a
day-to-day 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.
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... 892,210 Power production ... 126,608,034 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 ... 972,236 Total operating expenses... 188,476,990 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
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, 2012. 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, 2012.
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 2012. 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, 2030. Austin has
given notice that it will set its “Contract Rate of Delivery” based on its 2015 peak demand,
effective January 1, 2016.
Owatonna ... 358,118 12.5% Austin ... 349,242 11.7% Fairmont ... 159,342 5.4% Lake City ... 151,461 4.4% Litchfield ... 118,452 4.1% Saint Peter ... 97,283 3.2% Redwood Falls... 72,300 2.6% New Prague 67,888 2.2% Waseca ... 65,039 2.2% Mora ... 58,244 1.9% Princeton... 53,708 1.8% North Branch ... 27,943 1.1% Blooming Prairie ... 25,773 0.9% Grand Marais... 23,348 0.8% Spring Valley... 20,280 0.7% Wells ... 19,055 0.6% Preston... 14,685 0.5% TOTALS... 2,957,151 100.0% _____________________
(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 2012.
Year (MW) Percent Change (MWh) Percent Change 2008 505 (0.6) 2,928,147 (1.2) 2009 491 (2.8) 2,737,119 (6.5) 2010 516 5.1 2,823,926 3.2 2011 529 2.5 2,827,619 0.1 2012 519 (1.9) 2,822,105 (0.2)
Average Annual Compound
Growth Rate: 2008-2012: 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
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 2013.
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 2014. 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 63.12 percent with a net capacity factor of
52.83 percent. The national five-year averages for similar-sized coal plants for
the period of 2007 through 2011 were 85.77 percent and 76.61 percent,
respectively. The national five-year averages for all coal-fired plants for the
period of 2007 through 2011 were 83.45 percent and 67.32 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
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 100.5 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 2009.
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 2011. 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 2020. The Agency continues to evaluate additional renewable energy
options.
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
2015.
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 30-40 miles of 161 kV lines in
Minnesota. The aggregate estimated cost of these facilities is $1.9 billion.
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 2015.
The Agency’s share of the project is approximately $70 million.
THE LARGEST MEMBERS
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Independent Auditors’ Report 1
Management’s Discussion and Analysis 3
Statements of Net Position 13
Statements of Revenues, Expenses, and Changes in Net Position 14
Statements of Cash Flows 15
Independent Auditors’ Report
The Board of Directors
Southern Minnesota Municipal Power Agency:
We have audited the accompanying financial statements of Southern Minnesota Municipal Power Agency (the Agency), which comprise the statements of net position as of December 31, 2012 and 2011, and the related statements of revenues, expenses, and net position and cash flows for the years then ended, and the related notes to the financial statements.
Management’s Responsibility for the Financial Statements
Management is responsible for the preparation and fair presentation of these financial statements in accordance with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.
Auditors’ Responsibility
Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our report dated April 9, 2012, we expressed an opinion on the Agency’s 2011 financial statements qualified for the effects of such adjustments, if any, as might have been determined to be necessary had we been able to examine evidence regarding the Agency’s estimates of the insurance claim receivable, reduction of plant equipment, and deferred gain on involuntary conversion of plant assets. Since that date, the Agency has provided us with such evidence. Accordingly, our present opinion on the 2011 financial statements, as presented herein, is different from that expressed in our previous report.
U.S. generally accepted accounting principles require that the management’s discussion and analysis on pages 3 through 12 be presented to supplement the basic financial statements. Such information, although not a part of the basic financial statements, is required by the Governmental Accounting Standards Board who considers it to be an essential part of financial reporting for placing the basic financial statements in an appropriate operational, economic, or historical context. We have applied certain limited procedures to the required supplementary information in accordance with auditing standards generally accepted in the United States of America, which consisted of inquiries of management about the methods of preparing the information and comparing the information for consistency with managements’ responses to our inquiries, the basic financial statements, and other knowledge we obtained during our audit of the basic financial statements. We do not express an opinion or provide any assurance on the information because the limited procedures do not provide us with sufficient evidence to express an opinion or provide any assurance.
Minneapolis, Minnesota March 15, 2013
Financial Statements Overview
This discussion and analysis of Southern Minnesota Municipal Power Agency’s (the Agency) financial performance provides an overview of the Agency’s activities for the fiscal years ended December 31, 2012 and 2011. The information presented should be read in conjunction with the basic financial statements and the accompanying notes to the financial statements.
The Agency follows the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission. The basic financial statements are prepared on the accrual basis of accounting in accordance with U.S. generally accepted accounting principles. The Agency’s basic financial statements include the statement of net position, the statement of revenues, expenses, and changes in net position, and the statement of cash flows.
The statement of net position provides information about the nature and amount of assets and obligations (liabilities) of the Agency as of the end of the year. The statement of revenues, expenses, and changes in net position reports revenues and expenses for the current year. The statement of cash flows reports cash receipts, cash payments, and net changes in cash resulting from operating activities, capital and related financing activities, and investing activities.
Financial Highlights
The following table summarizes the financial position of the Agency as of December 31, 2012 and 2011:
Condensed statements of net position highlights are as follows:
" The assets of the Agency exceeded its liabilities at the close of 2012 by approximately $75.4 million (net position). The assets of the Agency exceeded its liabilities at the close of 2011 by approximately $67.0 million (net position). Current assets decreased by approximately $0.9 million with a decrease of $26.3 million in noncurrent investments. Current assets consist of cash, current investments, accounts receivable, inventories, prepayments, and other current assets. Current assets include deposits and
held in restricted funds of approximately $54.5 million in accordance with the bond resolution for debt service requirements. Noncurrent investments include investments held in restricted funds of approximately $17.7 million in accordance with the bond resolution for capital construction projects. " Capital assets, net, increased by approximately $46.2 million during 2012. Capital assets, net, include the
Agency’s 41% undivided ownership interest in the Sherburne County Generating Unit No. 3 (Sherco 3) plant with a historical cost of approximately $449.3 million as of December 31, 2012. The Agency also has approximately $172.5 million on a historical cost basis of substation facilities, transmission lines, land, wind turbines, buildings, members’ generating units under contract upgrades, and general office equipment.
" The increase in capital assets, net, is the result of an increase in electric plant and equipment, net, of approximately $3.5 million and an increase in construction in progress of approximately $42.8 million. The increase in electric plant and equipment, net is a result of a decrease of $22.5 million due to the impairment of a portion of the Agency’s capital assets resulting from the damage to Sherco 3’s turbine and generator as a result of the failure that occurred in November 2011, an increase of approximately $21.7 million in Sherco 3 due to repairs made, an increase of approximately $2.6 million in the Mora Landfill gas station, and $1.6 million in transmission assets.
" Deferred costs decreased by approximately $5.0 million in 2012. The decrease is the result of a net decrease in long-term debt issuance costs due to amortization and costs incurred in 2012 of approximately $21.2 million and a decrease in the amount of deferred costs to be recovered in future periods of approximately $3.8 million during the year. Deferred costs to be recovered in future periods are costs in excess of the amounts currently billable to the members that are to be recovered from future revenues by setting rates sufficient to provide funds for the related debt service requirements.
" Escrow deposit was set up for the Fairmont Energy Station for approximately $10.5 million for the installation of a new generating plant in Fairmount, MN. The new facility consists of four 6 MW gas-fired reciprocating engines manufactured by Caterpillar. The efficient engine design will provide increased fuel diversity and operational flexibility for the Agency’s generation fleet. The plan will be operational in late 2013.
" Deferred outflows of resources decreased by approximately $0.2 million in 2012. Deferred outflows of resources result from hedging of cash flows associated with the Agency’s variable interest rate debt through the use of pay-fixed, receive-variable interest rate swaps. This amount offsets the fair value of the Agency’s interest rate swaps at December 31.
" Insurance claim receivable decrease of approximately $6.2 million and represents the Agency’s estimate of its proportionate share of the insurance claim receivable at December 31, 2012. The decrease is a result of repairs that were made to Sherco 3’s turbine and generator.
" The current portion of long-term debt included in current liabilities was approximately $44.3 million. Current liabilities also include $21.0 million of commercial paper notes. The increase in total current liabilities of approximately $2.2 million is primarily attributable to a $0.4 million increase in accounts payable – power production, a $3.4 million decrease in accrued liabilities and other payables, an increase in deferred credits of $3.1 million, a decrease in deferred gain on involuntary conversion of plant assets of $0.5 million, an increase of $3.7 million in current maturities of long-term debt, and a decrease of approximately $1.0 million in accrued interest payable.
" The carrying value of long-term debt at the end of 2012 was approximately $642.2 million. Scheduled principal payments of approximately $40.6 million were made in 2012. The carrying value of the long-term debt was also impacted by the effect of bond discount/premium amortization.
" Deferred credits, current and long-term, which represent rate stabilization, increased by approximately $0.2 million. The increase was a result of net contributions to the fund during 2012.
" In November 2011, during restart activities following a planned overhaul, the Agency’s coal fired generating plant, Sherco 3, experienced a mechanical failure in the turbine and generator. A fire resulted which was extinguished within a few hours. Equipment damage was significant. However, all of the equipment damaged has been determined to be repairable. The recovery team estimates that all of the components will be repaired and back on site by early 2013. Sherco 3 is expected to be back on line in 2013, although several uncertainties remain which could impact the schedule. In 2011, the Agency established a regulatory liability of approximately $40.0 million representing the deferred gain on the involuntary conversion of certain of the Agency’s capital assets at Sherco 3 due to the damage sustained. Due to a change in estimate in 2012, the deferred gain was increased to $66.6 million. The deferred gain, which represents the difference between the amount of the estimated insurance recovery and the carrying value of the capital assets impaired, will be amortized by the Agency into income over the estimated remaining useful life of Sherco 3 at the time of the incident, or approximately 20 years. The Agency has purchased replacement power for Sherco 3 through the summer months of 2013.
The following table summarizes the financial position of the Agency as of December 31, 2011 and 2010:
Condensed statements of net position highlights are as follows:
" The assets of the Agency exceeded its liabilities at the close of 2011 by approximately $67.0 million (net position). The assets of the Agency exceeded its liabilities at the close of 2010 by approximately $58.5 million (net position). This increase is due to improvements in member community economic activity, favorable energy prices in the Midwest Independent Transmission System Operator (MISO) market, and continued focus on cost containment in Agency operations.
" Current assets decreased by approximately $3.7 million with a decrease of $11.8 million in noncurrent investments. Current assets consist of cash, current investments, accounts receivable, inventories, prepayments, and other current assets. Current assets include deposits and investments held in revenue and operating funds of approximately $37.7 million to be used for operating, maintenance, and working capital needs of the Agency. Current assets also include deposit and investments held in restricted funds of approximately $51.9 million in accordance with the bond resolution for debt service requirements. Noncurrent investments include investments held in restricted funds of approximately $44.2 million in accordance with the bond resolution for capital construction projects.
" Capital assets, net, decreased by approximately $5.7 million during 2011. Capital assets, net, include the Agency’s 41% undivided ownership interest in the Sherburne County Generating Unit No. 3 (Sherco 3) plant with a historical cost of approximately $450.1 million as of December 31, 2011. The Agency also has approximately $168.2 million on a historical cost basis of substation facilities, transmission lines, land, wind turbines, buildings, members’ generating units under contract upgrades, and general office equipment.
" The decrease in capital assets, net, is the result of a decrease in electric plant and equipment, net, of approximately $28.5 million and an increase in construction in progress of approximately $22.8 million. The decrease in electric plant and equipment, net is a result of a decrease of $14.7 million due to the impairment of a portion of the Agency’s capital assets resulting from the damage to Sherco 3’s turbine and generator as a result of the postoverhaul failure that occurred in November 2011, $4.2 million due to the retirement of the Austin Utilities’ plant, along with the effect of depreciation expense.
" Deferred costs increased by approximately $2.0 million in 2011. The increase is the result of a net decrease in long-term debt issuance costs due to amortization and costs incurred in 2011 of approximately $1.2 million offset by an increase in the amount of deferred costs to be recovered in future periods of approximately $3.2 million during the year. Deferred costs to be recovered in future periods are costs in excess of the amounts currently billable to the members that are to be recovered from future revenues by setting rates sufficient to provide funds for the related debt service requirements.
" Deferred outflows of resources decreased by approximately $0.5 million in 2011. Deferred outflows of resources result from hedging of cash flows associated with the Agency’s variable interest rate debt through the use of pay-fixed, receive-variable interest rate swaps. This amount offsets the fair value of the Agency’s interest rate swaps at December 31.
" Insurance claim receivable increase of approximately $54.7 million relates to damage resulting from a failure that occurred with Sherco 3’s turbine and generator in November 2011 during postoverhaul testing. The insurance claim receivable represents the Agency’s estimate of its proportionate share of the insurance claim receivable at December 31, 2011.
" The current portion of long-term debt included in current liabilities was approximately $40.6 million. Current liabilities also include $21.0 million of commercial paper notes. The decrease in total current liabilities of approximately $4.1 million is primarily attributable to a $6.6 million increase in accounts payable – power production, a $17.1 million decrease in accrued liabilities and other payables, an increase in deferred credits of $2.9 million, an increase in deferred gain on involuntary conversion of plant assets of $1.9 million and an increase of $2.8 million in current maturities of long-term debt.
" The carrying value of long-term debt at the end of 2011 was approximately $661.5 million. Scheduled principal payments of approximately $37.8 million were made in 2011. The carrying value of the long-term debt was also impacted by the effect of bond discount/premium amortization.
" Deferred credits, which represent rate stabilization, increased by approximately $8.0 million. The increase was a result of net contributions to the fund during 2011.
" In November 2011, during restart activities following a planned overhaul, the Agency’s coal fired generating plant, Sherco 3, experienced a mechanical failure in the turbine and generator. A fire resulted which was extinguished within a few hours. Equipment damage was significant. However, all of the equipment damaged has been determined to be repairable. The recovery team estimates that all of the components will be repaired and back on site in early 2013. Sherco 3 is expected to be back on line in 2013, although several uncertainties remain that could impact the schedule. The Agency established a regulatory liability of approximately $40.0 million representing the deferred gain on the involuntary conversion of certain of the Agency’s capital assets at Sherco 3 due to the damage sustained. The deferred gain, which represents the difference between the amount of the estimated insurance recovery and the carrying value of the capital assets impaired, will be amortized by the Agency into income over the estimated remaining useful life of Sherco 3 at the time of the incident, or approximately 21 years. The Agency has purchased replacement power for Sherco 3 through the summer months of 2013.
The following table summarizes the changes in financial position of the Agency for the years ended December 31, 2012 and 2011:
Condensed statements of revenues, expenses, and changes in net position highlights are as follows:
" Operating revenues, power sales, increased by approximately $14.6 million between 2012 and 2011. Operating revenues, power sales, consist principally of member power sales revenue, power sales to
nonmembers, other transmission revenue, and contributions to, or distributions from, the rate stabilization account. Sales to nonmembers include the Agency’s participation in the MISO Day 2 market.
" Before the effects of distributions made from the rate stabilization account, operating revenues, power sales, increased by approximately $4.0 million, primarily due to a decrease in the MISO Day 2 market by approximately $0.9 million, by an increase of approximately $3.9 million in transmission revenue, and by an increase in power sales to members and nonmembers of approximately $1.0 million. The decrease for MISO market revenues was due to a decrease in day-ahead asset energy revenue in 2012. There was relatively no net contribution to the rate stabilization account in 2012 compared with a net contribution of $10.8 million in 2011. Contributions to the rate stabilization account decrease the amount of operating revenues, power sales, whereas distributions from the rate stabilization account increase the amount of operating revenues, power sales.
" Operating expenses increased by approximately $14.0 million between 2012 and 2011. Operating expenses consist of production fuel, power production, other operating expenses, depreciation and amortization, and expenses to be recovered in future periods. The increase observed in 2012 compared with 2011 was the net result of a decrease in production fuel expense of approximately $36.9 million, an increase in power production expenses of approximately $57.7 million due to the failure at Sherco 3 that occurred in November 2011 and is expected to become operational in 2013, a decrease in other operating expenses of approximately $8.6 million (due to an increase of approximately $4.3 million in transmission expenses, a decrease of approximately $13.1 million in Sherco 3 operating and maintenance expenses, an increase in administrative and member services of approximately $0.9 million and a decrease of approximately $0.7 million in in-lieu of property taxes) and a combined increase of approximately $1.8 million in depreciation and expenses to be recovered in future periods.
The following table summarizes the changes in financial position of the Agency for the years ended December 31, 2011 and 2010:
Condensed statements of revenues, expenses, and changes in net position highlights are as follows:
" Operating revenues, power sales, increased by approximately $2.4 million between 2011 and 2010. Operating revenues, power sales, consist principally of member power sales revenue, power sales to nonmembers, other transmission revenue, and contributions to, or distributions from, the rate stabilization account. Sales to nonmembers include the Agency’s participation in the MISO Day 2 market.
" Before the effects of distributions made from the rate stabilization account, operating revenues, power sales, decreased by approximately $0.9 million, primarily due to a decrease in the MISO Day 2 market by approximately $3.2 million, by an increase of approximately $1.7 million in transmission revenue, with relatively no change in power sales to members and nonmembers. The decrease for MISO market revenues was due to a decrease in transmission rights revenue in 2011. The net contribution to the rate stabilization account in 2011 was approximately $10.8 million compared with a net contribution of $14.1 million in 2010. Contributions to the rate stabilization account decrease the amount of operating revenues, power sales, whereas distributions from the rate stabilization account increase the amount of operating revenues, power sales.
