PLA-7048, Allegheny Electric Cooperative, Inc. - 2012 Annual Report Table of Contents

Allegheny Electric Cooperative, Inc. - 2012 Annual Report Table of Contents

ML13220A045
Person / Time
Site:	Susquehanna
Issue date:	12/31/2012
From:	Susquehanna
To:	Office of Nuclear Reactor Regulation
References
PLA-7048
Download: ML13220A045 (54)

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A MESSAGE FROM THE 1

BOARD CHAIRMAN AND PRESIDENT & CEO

'M Thanks to a BALANCED APPROACH TO POWER SUPPLY zW MANAGEMENT, Allegheny Electric Cooperative, Inc. has emerged U..)

as a clear leader in terms of affordability and stability in today's co 0.

competitive energy environment.

In 2007, Allegheny Electric Cooperative, Inc. (Allegheny), the power provider for 14 electric distribution cooperatives in Pennsylvania and New Jersey, launched its innovative "Patchwork Quilt" strategy of I

power supply management. In use for the past six years, this approach involves entering into multiple energy and capacity agreements for different amounts and for different lengths of time. The agreements complement Allegheny's self-owned baseload generation assets. By diversifying in this way, Allegheny is I

not dependent on any single source for power supply.

In 2012, the Patchwork Quilt approach continued to deliver benefits, helping Allegheny maintain one of the lowest generation rates in the region. Over the past several years, the strategy has helped Allegheny become an exceptionally dependable source of power supply for its members. In a time of intense market I

volatility, Allegheny's rates have been consistently less volatile than most investor-owned utility (IOU) rates.

This is especially significant given the dramatic changes in the electricity marketplace in recent years.

In 2011, a new era opened in Pennsylvania as the electric generation market in the state entered into full competition. This occurred when the remaining caps on IOU electric generation rates -

initiated under U

the electric restructuring process that began in the mid-1990s -

were lifted at the close of 2010.

This era of "electric choice" has changed the landscape of power generation in the region. With the removal of rate caps, generation suppliers now operate in a fully competitive environment where rates can be influenced by industry and market U

changes. IOUs now compete with alternative electric generation suppliers (EGSs) for customers, who now have the option to CURTIN RAKESTRAW II switch generation providers. As a result, generation rates U

Board Chairman for these entities can fluctuate multiple times a year, often varying significantly from quarter to quarter.

FRANK BETLEY President&CEO In stark contrast, Allegheny has consistently kept its rates among the lowest -

if not the lowest N

in the region, with only minor fluctuations throughout this period.

This record of stability has been achieved in large part due m

to the balance of power resources found in Allegheny's Patchwork Quilt.

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Unlike the IOUs, who sold off or transferred ownership of their generation assets under electric restructuring, Allegheny held onto its power resources. Today, this strong foundation in baseload generation resources, combined with strategic power agreements, leaves Allegheny and its member cooperatives not nearly as affected by market volatility as the IOUs. As a result, Allegheny is able to deliver a competitive rate on a consistent basis.

This diversified approach allows Allegheny to enjoy tremendous flexibility in operational and financial matters. Having this strategy in place has played a key role during events like maintenance outages at the Susquehanna Steam Electric Station nuclear facility in Luzerne County. During such outages, we are able to quickly secure alternative power resources to maintain reliability and mitigate the impact on rates exemplifying the strategy in action.

The strategy also allows us the flexibility to take advantage of special opportunities. In 2012, Allegheny completed the process to become the sole owner of the Raystown Hydroelectric Project in Huntingdon County a facility we have leased since it became operational in 1988. Only through our strong position were we able to respond quickly to this opportunity to acquire the facility, which continues to be a reliable source of renewable energy for our cooperative members.

Also in 2012, Allegheny quickly maneuvered to sell an option on Allegheny Locks & Dams 8 & 9, two run-of-river hydroelectric facilities on the Allegheny River. Allegheny had an option to purchase the facilities in 2030, but chose to take advantage of an opportunity to sell this option. In assessing the future value of this option, it was determined that selling the option now would be of most benefit to Allegheny.

In financial matters, Allegheny recorded another year of solid financial results in 2012. Our strong financial position allowed the retirement of $3.8 million in patronage capital to members in 2012, bringing the total retired since 2006 to nearly $25 million. Since its inception in 1946, Allegheny has returned 31 percent of its total assigned margins to members in the form of capital credit retirements, exceeding the national G&T average of 23.3 percent -

another indication of Allegheny's solid financial position.

For years, Allegheny's balanced approach has been a stabilizing force i a series of c es and U

upheavals, from a severe economic downturn to political ard regulatory uncertainty to the push for competitive electricity markets. In 2012, and throughout these challenging periods, Allegheny has managed to deliver exceptionally co pbers with a reliable f

electricity at an affordable price.

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2QTHE YEAR IN REVIEW U

12I Allegheny in 2012 continued to show the strength of its innovative Patchwork Quilt strategy of power supply management. The strategy involves securing power in different amounts, from different sources, for different periods of time. Developed over the past decade and launched in 2007, the plan helps further diversify Allegheny's power resources -

all the more prudent, given the volatility of the energy market and difficult economic climate of the past few years.

The Patchwork Quilt plan adds complementary pieces to a solid foundation of Allegheny-owned power resources. Combined with a strong financial position, Allegheny enjoys tremendous flexibility in being able to react to market changes and operational issues, including maintenance outages at our facilities. That strength allowed Allegheny in 2012 to continue to successfully achieve our core mission of stable and affordable wholesale power rates for our member cooperatives in Pennsylvania and New Jersey. Here is a look at Allegheny's 2012 power supply portfolio:

SUSQUEHANNA STEAM ELECTRIC STATION Allegheny owns 10 percent of the Susquehanna Steam Electric Station (SSES), a 2,600-megawatt, two-unit nuclear power plant located in Luzerne County, Pa. PPL Susquehanna, a division of Allentown, Pa.-

U based PPL Corporation, owns the remaining 90 percent and operates the boiling water reactor facility.

In 2012, this 10 percent share of SSES provided 1.69 billion kilowatt-hours of electricity to Pennsylvania

• and New Jersey electric cooperatives. Considering dual unit outages, the capacity factor of Unit 1 was 68.9 percent; Unit 2 achieved a calendar year capacity factor of 81.2 percent. This corresponds to an average U

annual composite capacity factor for the facility of 75 percent.

Both units experienced outages in 2012. Unit 1, considered by the Nuclear Regulatory Commission since 2010 to be the largest boiling water reactor in terms of thermal power and generating capacity, was offline for a total of 99 days. During a planned refueling outage, Unit 1 underwent several major inspections and equipment replacements. These included inspecting and refurbishing jet pumps, and replacing drywall

• fans, steam relief valves, and hydraulic control units. Unit 2 was offline for a total of 48 days due to turbine inspections and unexpected mechanical issues.

RAYSTOWN HYDROELECTRIC PROJECT Allegheny's Raystown Hydroelectric Project (Raystown) is a two-unit, 21-megawatt, run-of-river hydropower U

facility located at Raystown Lake and Dam in Huntingdon County, Pa. With near-normal rainfall in 2012, Raystown generated approximately 88 million kilowatt-hours, 3 percent higher than the annual goal of 85.4 million kilowatt-hours. The 2012 generation amount equates to 2.8 percent of Allegheny's requirements for U

the year. The plant maintained a 99.9 percent availability.

In October 2011, Allegheny successfully completed the purchase of the lease agreement that had been in place since 1988 for the Raystown hydropower facility. As a result of the purchase, Allegheny became the lease owner while continuing in the position of the lessee. In 2012, staff continued efforts to eliminate other lease structure components and to reflect Allegheny as the sole Federal Energy Regulatory

• allegheny electric cooperative, inc.

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Commission (FERC) hydro license holder. After all the necessary financial steps were completed,

[] Allegheny filed the appropriate application with FERC in mid-June and was approved as the sole license holder in early December.

Allegheny staff operates the hydroelectric project in close cooperation with the Baltimore District of the U.S.

Army Corps of Engineers, which controls water releases from Raystown Lake, the largest man-made body

[] of water in Pennsylvania.

• NEW YORK POWER AUTHORITY Since 1966, Allegheny has purchased power generated by hydroelectric projects located along the Niagara and St. Lawrence rivers in upstate New York. Both facilities are operated by the New York Power Authority (NYPA). In 2012, Allegheny received an allocation of 33 megawatts from the projects for the I

benefit of the 14 member cooperatives. Since 1966, it is estimated that NYPA generation has saved the electric distribution cooperatives $365 million ($8.4 million in 2012), compared to the cost of purchasing the same amount of electricity from other sources.

LOAD MANAGEMENT I

In 1986, Allegheny and its member electric distribution cooperatives in Pennsylvania and New Jersey

[] launched the Coordinated Load Management System (CLMS) to reduce electricity consumption during peak demand periods.

By shifting use of residential water heaters, electric thermal units, dual fuel home heating systems, and other special equipment in the homes of volunteer cooperative consumer-members to off-peak hours, the CILMS improves system efficiency, cuts costly demand and transmission charges Allegheny and its member cooperatives must pay for purchased power, and reduces the need for new generating capacity.

The system reduces transmission zone peaks and, during summer peaks, reduces Allegheny's capacity obligation under procedures established by the PJM Interconnection.

Over the past year, the CLMVS reduced cooperative purchased power costs by more than $5.7 million, bringing total net power cost savings achieved since December 1986 to more than $111.8 million. Currently, 206 substations are being utilized for load control with approximately 48,500 load control receivers installed on appliances (mostly water heaters) in the homes of electric cooperative consumer-members.

BAleghny iledheny took steps to update the system. New CaLMS-related equipment was placed on-lde n i

e ng in 2008, and by the end of 2009, Alegheny's member cooperatives were in the process of installing new field equipment in their respective substations. At the end of 2012, field equipment installations were completed at 81 percent of the substations. Approximately 57 percent of the new vendor Naload control switches have been deployed at the participating member cooperatives. These new switches are currently controlled by Allegheny.

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balance of power 2012 ANNUAL REPORT

rI CLEAN POWER COMMITMENT Allegheny and its 14 member cooperatives continue to be very active in meeting consumer-members' desire to support energy efficiency, clean and renewable energy generation, and a secure energy future for electric cooperatives. In addition to Allegheny's investments in clean and carbon-free nuclear and hydropower resources, and our demand-side efficiency measures, here are some of our other initiatives for a better environment:

INTERCONNECTED PROJECTS Allegheny and its member distribution cooperatives actively worked with cooperative consumer-members who were considering the addition of renewable energy projects to their homes or businesses. By the end of 2012, there were 285 consumer-member-owned renewable energy projects that had been interconnected, including six digesters, 53 wind turbines, 225 solar photovoltaic arrays, U

and one small hydroelectric facility. We expect to interconnect additional projects on a regular basis.

See map on foldout, next page.

RENEWABLE ENERGY ASSISTANCE PROGRAM As a positive partner in the Commonwealth's alternative energy initiatives, Allegheny provides a program to assist cooperative consumer-members who want to install a clean energy generation U

system at their home, farm or business. The Renewable Energy Assistance Program (REAP) provides grants to electric distribution cooperatives to help cover various interconnection costs, such as metering equipment and distribution transformers. The program also pays for certain U

transitional costs to help ensure that other electric cooperative consumer-members do not subsidize the operation or installation of small renewable energy generation systems -

such as anaerobic digesters, wind turbines, or solar units. Since 2006, REAP has provided nearly $489,000 in U

interconnection grants among 11 member cooperatives. In many ways, REAP reflects the electric cooperative tradition of members helping members, and continues to strengthen Allegheny's history of addressing environmental and energy challenges in a cost-effective and fair way.

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w 51-S Uof interconnected powerU produced was from SOLAR PHOTOVOLTAIC ARRAYS H LL

Commission (FERC) hydro license holder. After all the necessary financial steps were completed, Allegheny filed the appropriate application with FERC in mid-June and was approved as the sole license holder in early December.

I Allegheny staff operates the hydroelectric project in close cooperation with the Baltimore District of the U.S.

Army Corps of Engineers, which controls water releases from Raystown Lake, the largest man-made body of water in Pennsylvania.

NEW YORK POWER AUTHORITY I

Since 1966, Allegheny has purchased power generated by hydroelectric projects located along the Niagara and St. Lawrence rivers in upstate New York. Both facilities are operated by the New York Power Authority (NYPA). In 2012, Allegheny received an allocation of 33 megawatts from the projects for the U

benefit of the 14 member cooperatives. Since 1966, it is estimated that NYPA generation has saved the electric distribution cooperatives $365 million ($8.4 million in 2012), compared to the cost of purchasing the same amount of electricity from other sources.

LOAD MANAGEMENT U

In 1986, Allegheny and its member electric distribution cooperatives in Pennsylvania and New Jersey launched the Coordinated Load Management System (CLMS) to reduce electricity consumption during peak demand periods.

By shifting use of residential water heaters, electric thermal units, dual fuel home heating systems, and other special equipment in the homes of volunteer cooperative consumer-members to off-peak hours, I

the CLMS improves system efficiency, cuts costly demand and transmission charges Allegheny and its member cooperatives must pay for purchased power, and reduces the need for new generating capacity.

The system reduces transmission zone peaks and, during summer peaks, reduces Allegheny's capacity U

obligation under procedures established by the PJM Interconnection.

U Over the past year, the CLMS reduced cooperative purchased power costs by more than $5.7 million, bringing total net power cost savings achieved since December 1986 to more than $111.8 million. Currently, 206 substations are being utilized for load control with approximately 48,500 load control receivers installed U

on appliances (mostly water heaters) in the homes of electric cooperative consumer-members.

I Beginning in 2007, Allegheny took steps to update the system. New CLMS-related equipment was placed on-line beginning in 2008, and by the end of 2009, Allegheny's member cooperatives were in the process of installing new field equipment in their respective substations. At the end of 2012, field equipment installations were completed at 81 percent of the substations. Approximately 57 percent of the new vendor load control switches have been deployed at the participating member cooperatives. These new switches are currently controlled by Allegheny.

balance of power 2012 ANNUAL REPORT

CLEAN POWER COMMITMENT U

1 1

Allegheny and its 14 member cooperatives continue to be very active in meeting consumer-members' desire to support energy efficiency, clean and renewable energy generation, and a secure energy future for electric cooperatives. In addition to Allegheny's investments in clean and carbon-free nuclear and hydropower resources, and our demand-side efficiency measures, here are some of our other initiatives for a better environment:

INTERCONNECTED PROJECTS K

Allegheny and its member distribution cooperatives actively worked with cooperative consumer-members who were considering the addition of renewable energy projects to their homes or businesses. By the end of 2012, there were 285 consumer-member-owned renewable energy projects that had been interconnected, including six digesters, 53 wind turbines, 225 solar photovoltaic arrays, I

and one small hydroelectric facility. We expect to interconnect additional projects on a regular basis.

See map on foldout, next page.

RENEWABLE ENERGY ASSISTANCE PROGRAM l

As a positive partner in the Commonwealth's alternative energy initiatives, Allegheny provides a program to assist cooperative consumer-members who want to install a clean energy generation U

system at their home, farm or business. The Renewable Energy Assistance Program (REAP) provides grants to electric distribution cooperatives to help cover various interconnection costs, such as metering equipment and distribution transformers. The program also pays for certain n

transitional costs to help ensure that other electric cooperative consumer-members do not subsidize the operation or installation of small renewable energy generation systems -

such as anaerobic digesters, wind turbines, or solar units. Since 2006, REAP has provided nearly $489,000 in U interconnection grants among 11 member cooperatives. In many ways, REAP reflects the electric cooperative tradition of members helping members, and continues to strengthen Allegheny's history of addressing environmental and energy challenges in a cost-effective and fair way.

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SOLAR PHOTOVOLTAIC ARRAYS lL.

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$4,211,000 SYSTEM RATE 6 42 f" *cents per kWh ENERGY SALES TO MEMBERS 3,082,288 MWh 2012 PEAK DEMAND TOTAL ASSETS

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225 N Water Street, Suite 400 P0 Box 1580 U.O-P Decatur, 1L 62525 1580 CPAs & Advisors 2174292411 Fax 217 429,6109 www.bkd.com Independent Auditor's Report Board of Directors Allegheny Electric Cooperative, Inc.

Harrisburg, Pennsylvania We have audited the accompanying consolidated financial statements of Allegheny Electric Cooperative, Inc., which U

comprise the consolidated balance sheets as of December 31, 2012 and 2011, and the related consolidated statements of margin, comprehensive margin, members' equities 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 consolidated financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, U

implementation and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditor's Responsibility Our responsibility is to express an opinion on these consolidated 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 consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the consolidated 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 U

consolidated 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 U

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 consolidated financial statements.

U We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Allegheny Electric Cooperative, Inc. as of December 31, 2012 and 2011, and the results of its operations and its cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

Decatur, Illinois April 18, 2013 Praxiti' MEMBER ex erence i GLOBAL AL ANE ex einem"1INDEPENOF NJ T

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CONSOLIDATED BALANCE SHEETS DECEMBER 31,2012 AND 2011 (IN THOUSANDS)

ASSETS 2012 2011 Electric Utility Plant, at cost In service (see Note 2)

Less accumulated depreciation Construction work in progress Nuclear fuel in process (see Notes 1 and 3)

Net electric utility plant (see Notes 1, 2 and 3)

Investments and Other Assets Investments in associated organizations (see Note 4)

Nuclear Decommissioning Trust (NDT) (see Notes 1 and 5)

Non-utility property, at cost (net of accumulated depreciation of

$6,876 in 2012 and $6,563 in 2011)

Assets of consolidated variable interest entity Non-utility property, at cost (net of accumulated depreciation of $1,060 in 2012 and $1,058 in 2011)

Deferred tax assets, net (see Note 10)

Derivative investments (see Note 6)

Other noncurrent assets 935,977 (738,486) 197,491 10,014 32,582 240,087 26,972 90,120 6,633 12 7,304 934 2,699 134,674 918,250 (723,994) 194,256 6,737 32,110 233,103 27,490 79,497 5,824 15 9,357 4,665 435 127,283 15,207 45,264 10,843 17,062 1,738 8,669 1,541 860 14 9

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U Current Assets Cash and cash equivalents Investments (see Notes 1 and 4)

Derivative investments (see Note 6)

Accounts receivable, members (see Note 1)

Other receivables Inventories (see Note 1)

Other current assets Assets of consolidated variable interest entities Cash and cash equivalents Accounts receivable, affiliated organization Other receivables Other current assets Total current assets Deferred Charges (see Note 7)

Deferred asset plan - NDT investments Deferred decommissioning regulatory asset Deferred asset plan - forward swaps Other 30,419 36,377 2,008 20,301 2,241 9,357 1,425 735 103 9

686 103,661 3,530 1,159 3,869 3,832 13 1

4,690 483,112 7,714 470,446 Total assets allegheny electric cooperative, inc.

MEMBERS' EQUITIES AND LIABILITIES 2012 2011 U

Members' Equities (see Note 1)

Membership fees 3

3 Patronage capital 71,395 59,939 Donated capital 38 38 Unrestricted net assets 100 100 Retained earnings 4,211 15,323 Members' equities 75,747 75,403 Accumulated other comprehensive income 20,000 15,352 Total equities 95,747 90,755 Asset Retirement Obligation (see Note 8) 153,973 148,050 Long-Term Debt (see Note 9) 167,398 165,119 Current Liabilities Notes payable (see Note 9) 20,500 Current installments of long-term debt 7,721 7,164 Financial transmission rights (see Note 6) 2,008 4,665 Derivative liability - forward swaps (see Note 6) 9,097 Accounts payable and accrued expenses 16,348 18,029 Accounts payable, affiliated organization 14 10 Liabilities of consolidated variable interest entities Accounts payable and accrued expenses 1,667 1,488 Accrued postretirement benefit cost (see Note 13) 231 311 Accounts payable, affiliated organization 88 88 Total current liabilities 48,577 40,852 Other Liabilities and Deferred Revenue Deferred income tax obligation from safe harbor lease (see Note 15) 31 308 Financial transmission rights (see Note 6) 934 5,577 Deferred credits (see Note 16) 16,452 19,785 U

17,417 25,670 Total liabilities and members' equities 483,112 470,446 See Notes to Consolidated Financial Statements balance of power 2012 ANNUAL REPORT

CONSOLIDATED STATEMENTS OF MARGIN YEARS ENDED DECEMBER 31, 2012 AND 2011 (IN THOUSANDS) 2012 2011 Operating Revenues 213,951 227,937 Operating Expenses Operations Purchased capacity and energy costs Transmission Operation Maintenance Production Operation Maintenance Fuel Depreciation Accretion of asset retirement obligation Amortization of capital retirement asset Administrative and general Property and other taxes Total Operating Expenses Before Interest Operating Margin Before Interest Expense Interest Expense 100,511 27,321 425 27,099 16,365 12,175 8,063 2,961 12,286 553 207,759 109,453 28,307 310 26,816 15,018 10,847 6,631 5,695 957 12,234 547 216,815 11,122 (10,445)

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6,192 (10,744)

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Operating Margin (Loss)

Non-operating Margins Non-operating rental income Non-operating rental expense Interest income Settlement proceeds Proceeds from option Capital credits and other income 677 1,486 (1,546) 4,024 1,005 2,000 1,794 8,763 1,489 (1,442) 5,504 6,818 2,277 14,646 Net Margin 4,211 15,323 1161 UI II allegheny electric cooperative, inc.

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U CONSOLIDATED STATEMENTS OF COMPREHENSIVE MARGIN YEARS ENDED DECEMBER 31, 2012 AND 2011 (IN THOUSANDS) 2012 4,211 Net Margin Other Comprehensive Margin Change in postretirement benefit plan Unrealized appreciation in investments 87 4,561 4,648 2011 15,323 (77) 1,271 1,194 16,517 Comprehensive Margin 8,859 See Notes to Consolidated Financial Statements

CONSOLIDATED STATEMENTS OF MEMBERS' EQUITIES YEARS ENDED DECEMBER 31, 2012 AND 2011 (IN THOUSANDS)

U MEMBERSHIP DONATED PATRONAGE FEES CAPITAL CAPITAL Balance, January 1, 2011 3

38 54,369 U

Patronage capital retirement (3,553)

I Patronage capital assignment 6,262 Patronage capital - NDT (earnings) losses 2,861 Net margin Other comprehensive margin Balance, December 31, 2011 3

38 59,939 Patronage capital retirement (3,867)

Patronage capital assignment 12,292 Patronage capital-NDT (earnings) losses 3,031 U

Net margin Other comprehensive margin Balance, December 31, 2012 38 71,395 1

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UNRESTRICTED NET ASSETS RETAINED EARNINGS TOTAL MEMBERS' EQUITIES 63,633 ACCUMULATED OTHER COMPREHENSIVE MARGIN 14,158 TOTAL EQUITIES 77,791 m

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(2,861) 15,323 15,323 (12,292)

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U 4,211 4,648 100 4,211 75,747 20,000 95,747 See Notes to Consolidated Financial Statements

CONSOLIDATED STATEMENTS OF CASH FLOWS DECEMBER 31, 2012 AND 2011 2012 2011 Operating Activities Net margin Items not requiring cash Depreciation and fuel amortization Amortization of capital retirement asset Accretion of asset retirement obligation Deferred income taxes Loss on disposal of equipment Other than temporary losses Change in Investments in associated organizations Accounts receivable, members Other receivables Inventories 4,211 18,832 5,923 2,053 73 99 518 (3,239)

(503)

(309) 12,566 (1,695)

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(7,300) 7 (586) 15,323 16,294 957 5,695 3,570 393 909 66 (502)

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(153) 25,256 11,657 (1,559) 171 (25,524)

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2012 Investing Activities Additions to electric utility plant and non-utility property, net Proceeds from investments Purchase of investments Net cash used in investing activities Financing Activities Net borrowings under line-of-credit agreement Principal payments on long-term debt Proceeds from issuance of long-term debt Patronage capital retirement Net cash provided by financing activities Net Increase (Decrease) in Cash and Cash Equivalents Cash and Cash Equivalents, Beginning of Year Cash and Cash Equivalents, End of Year Supplemental Cash Flows Information Interest paid Income tax received Plant purchased with long-term debt (27,074) 9,366 (6,640)

(24,348) 20,500 (7,164) 10,000 (3,867) 19,469 15,087 16,067 31,154 10,670 2011 (43,742) 11,640 (5,792)

(37,894)

(5,942) 10,000 (3,553) 505 (15,821) 31,888 16,067 10,438 200 9,966 1l2 balance of power 2012 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 2012 AND 2011 NATURE OF OPERATIONS AND

SUMMARY

OF SIGNIFICANT ACCOUNTING POLICIES NOTE 1 NATURE OF OPERATIONS AND

SUMMARY

OF SIGNIFICANT ACCOUNTING POLICIES NATURE OF OPERATIONS Allegheny Electric Cooperative, Inc. (Cooperative) is a rural electric cooperative corporation established under the laws of the Commonwealth of Pennsylvania. The Cooperative has entered into wholesale power contracts with each of its member cooperatives which extend through 2025. The Cooperative extends unsecured credit to its members, with credit extended to two members of 17% and 12% and 18% and 13% at December 31, 2012 and 2011, respectively. The Cooperative either finances or obtains approval for 100 percent of its outstanding debt with the National Rural Utilities Cooperative Finance Corporation (CFC). The Cooperative is a generation and transmission cooperative. The member cooperatives' primary service areas are rural areas throughout much of Pennsylvania and a portion of New Jersey.

The Cooperative's primary operating asset is its 10 percent undivided interest in the Susquehanna Steam Electric Station (SSES), a 2,600-megawatt, two-unit nuclear power plant, co-owned by a subsidiary of PPL Corporation (PPL). The Board of Directors of the Cooperative, elected by its members, has full authority to establish electric rates to its member cooperatives. Rates are established on a cost of service basis. The Cooperative's Board of Directors has established a deferred revenue account to offset future increases in power supply costs.

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PRINCIPLES OF CONSOLIDATION The financial statements include the accounts of the Cooperative and a variable interest entity, Continental Electric Cooperative Services, Inc. (CCS), of which the Cooperative has determined it is the primary beneficiary. All significant intercompany accounts and transactions have been eliminated in consolidation.

VARIABLE INTEREST ENTITY AND CHANGE IN ACCOUNTING PRINCIPLE A legal entity is referred to as a variable interest entity (VIE) if any of the following conditions exist: (1) the total equity investment at risk is insufficient to permit the legal entity to finance its activities without additional subordinated financial support from other parties, or (2) the entity has equity investors who cannot make significant decisions about the entity's operations or who do not absorb their proportionate share of the expected losses or receive the expected returns of the entity. A VIE's primary beneficiary is the entity that has the power to direct the VIE's significant activities and has an obligation to absorb losses or the right to receive benefits that could be potentially significant to the VIE. A VIE must be consolidated by the Cooperative if it is deemed to be the primary beneficiary of the VIE.

All facts and circumstances are taken into consideration when determining whether the Cooperative has variable interests that would deem it the primary beneficiary and, therefore, require consolidation of the related VIE or otherwise rise to the level where disclosure would provide useful information to the users of the Cooperative's financial statements. In many cases, it is qualitatively clear whether the Cooperative has e

allegheny electric cooperative, inc.

the power to direct the activities significant to the VIE. In other cases, a more detailed qualitative analysis and possibly a quantitative analysis are required to make such a determination.

The Cooperative monitors the consolidated VIE to determine if any reconsideration events have occurred U

that could cause it to no longer be a VIE. The Cooperative reconsiders whether it is the primary beneficiary of a VIE on an ongoing basis. A previously consolidated VIE is deconsolidated when the Cooperative ceases to be the primary beneficiary or the entity is no longer a VIE.

CCS is considered to be a variable interest entity and the Cooperative is determined to be the primary beneficiary of CCS. As such, the assets, liabilities, and results of operations have been consolidated into these financial statements.

BASIS OF ACCOUNTING The Cooperative substantially maintains its accounting records in accordance with the Federal Energy Regulatory Commission's (FERC) uniform system of accounts as modified and adopted by the U.S.

Department of Agriculture, Rural Utilities Service (RUS).

In accordance with FERC guidelines, the Cooperative also maintains its accounts in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 980, Regulated Operations.

U DEREGULATION Pennsylvania retail electric customers have the choice of selecting the power supplier, or generator, from which they buy electricity. The ability to choose alternative energy suppliers has not significantly affected the Cooperative's operations or ability to recover its costs through future rates charged to its members.

On a regular basis, the Cooperative reevaluates its application of FASB ASC Topic 980, Regulated Operations, and Topic 980-20, Discontinuation of Rate Regulated Accounting. The Cooperative has determined that regulatory assets and liabilities should continue to be accounted for under the provisions of Topic 980 because it is reasonable to assume that the Cooperative will continue to be able to charge and collect its cost of service-based rates.

USE OF ESTIMATES The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the U

reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial report, and the reported amounts of revenues and expenses during the years then ended.

Actual results could differ from those estimates.

ELECTRIC UTILITY PLANT Electric utility plant is carried at cost. Depreciation of electric utility plant is provided over the estimated useful lives of the respective assets on a straight-line basis, except for nuclear fuel, as follows:

balance of power 2012 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31,2012 AND 2011 U

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U Nuclear Utility Plant Production Transmission General plant Nuclear fuel Non-Nuclear Utility Plant Hydroelectric Production Plant Unit #1 and Unit #2 Remaining License Life Extended to 2042 and 2044, respectively 2.75%

3% - 12.5%

Units of heat production 3%-33%

5%

Maintenance and repairs of property, and replacements and renewals of items determined to be less than units of property, are charged to expense. Replacements and renewals of items considered to be units of property are charged to the property accounts. At the time properties are disposed of, the original cost, plus cost of removal less salvage of such property, is charged to accumulated depreciation.

NON-UTILITY PROPERTY Non-utility property acquisitions are stated at cost less accumulated depreciation and amortization.

Depreciation and amortization is charged to expense on a straight-line basis over the estimated useful life of each asset.

The estimated useful lives of non-utility property range from 3 to 50 years.

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NUCLEAR FUEL 0

Nuclear fuel is charged to fuel expense based on the quantity of heat produced for electric generation.

Under the Nuclear Waste Policy Act of 1982, the U.S. Department of Energy (DOE) is responsible for the permanent storage and disposal of spent nuclear fuel removed from nuclear reactors. The Cooperative currently pays PPL for its portion of DOE fees for such future disposal services. During 2012 and 2011, the Cooperative recorded settlements related to the permanent storage and disposal of spent nuclear fuel as reported in non-operating margins in the consolidated statements of margins.

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VESTMENTS I

Ivestments are classified as "available for sale" and recorded at fair value, with unrealized gains and losses excluded from earnings and reported in other comprehensive income. Purchase premiums and discounts are recognized in interest income using the interest method over the terms of the securities.

Gains and losses on the sale of securities are recorded on the trade date and are determined using the specific identification method.

• For debt securities with fair value below amortized cost when the Cooperative does not intend to sell a debt security, and it is more likely than not that the Cooperative will not have to sell the security before recovery of its cost basis, it recognizes the credit component of an other-than-temporary impairment of a b security in earnings and the remaining portion in other comprehensive income.

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U For available-for-sale debt securities that management has no intent to sell and believes that it more likely than not will not be required to sell prior to recovery, only the credit loss component of the impairment is U

recognized in earnings, while the noncredit loss is recognized in other comprehensive income. The credit loss component recognized in earnings is identified as the amount of principal cash flows not expected to be received over the remaining term of the security as projected based on cash flow projections.

For equity securities, when the Cooperative has decided to sell an impaired available-for-sale security and does not expect the fair value of the security to fully recover before the expected time of the sale, the security is deemed other-than-temporarily impaired in the period in which the decision to sell is made.

The Cooperative recognizes an impairment loss when the impairment is deemed other than temporary even if a decision to sell has not been made.

m CASH AND CASH EQUIVALENTS Cash and cash equivalents consist of bank deposits in federally insured accounts, temporary investments and money market funds.

The Cooperative places its cash and temporary investments with high quality financial institutions. For purposes of the statements of cash flows, the Cooperative considers all highly liquid investments with an original maturity of three months or less when purchased to be cash equivalents. Cash equivalents are carried at cost.

Pursuant to legislation enacted in 2010, the FDIC fully insured all noninterest-bearing transaction accounts beginning December 31, 2010, through December 31, 2012, at all FDIC-insured institutions.

The legislation expired on December 31, 2012. Beginning January 1, 2013, noninterest-bearing transaction accounts are subject to the $250,000 limit on FDIC insurance per covered institution.

At December 31, 2012, the Cooperative's cash accounts exceeded federally insured limits by approximately $29,267,000.

The Cooperative's cash and investments are in a variety of financial instruments. The related values as presented in the financial statements are subject to various market fluctuations, which include changes in the equity markets, interest rate environment and the general economic conditions. The Cooperative's U

credit losses have historically been minimal and within management's expectations.

m ACCOUNTS RECEIVABLE Accounts receivable are stated at the amount billed to members. Accounts receivable are due in accordance with approved policies. An allowance for doubtful accounts has not been recorded because all accounts receivable are considered fully collectible.

m DERIVATIVES Derivatives are recognized as assets and liabilities on the consolidated balance sheet and measured at fair value. For exchange-traded contracts, fair value is based on quoted market prices. For nonexchange-traded balance of power [ 2012 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31,2012 AND 2011 contracts, fair value is based on dealer quotes, pricing models, discounted cash flow methodologies, or similar techniques for which the determination of fair value may require significant management judgment or estimation.

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The Cooperative accounts for certain power plant spare parts using a deferred inventory method. Under this method, purchases of spare parts under inventory control are included in an inventory account and then charged to the appropriate capital or expense accounts when the parts are used or consumed.

Inventories are carried at cost, with cost determined on the average cost method.

PATRONAGE CAPITAL Current and future margins (excluding earnings from the Nuclear Decommissioning Trust) will be assigned as patronage capital.

INCOME TAXES The Cooperative accounts for income taxes in accordance with income tax accounting guidance (ASC t

740, Income Taxes). The income tax accounting guidance results in two components of income tax expense: current and deferred. Current income tax expense reflects taxes to be paid or refunded for the current period by applying the provisions of the enacted tax law to the taxable income or excess U

of deductions over revenues. The Cooperative determines deferred income taxes using the liability (or balance sheet) method. Under this method, the net deferred tax asset or liability is based on the tax effects of the differences between the book and tax bases of assets and liabilities, and enacted changes U in tax rates and laws are recognized in the period in which they occur. Deferred income tax expense results from changes in deferred tax assets and liabilities between periods. Deferred tax assets are reduced by a valuation allowance if, based on the weight of evidence available, it is more likely than not U that some portion or all of a deferred tax asset will not be realized.

Tax positions are recognized if it is more likely than not, based on the technical merits, that the tax position will be realized or sustained upon examination. The term more-likely-than-not means a likelihood of more than 50 percent; the terms examined and upon examination also include resolution of the related appeals U

or litigation processes, if any. A tax position that meets the more-likely-than-not recognition threshold is initially and subsequently measured as the largest amount of tax benefit that has a greater than 50 percent likelihood of being realized upon settlement with a taxing authority that has full knowledge of U all relevant information. The determination of whether or not a tax position has met the more-likely-than-not recognition threshold considers the facts, circumstances and information available at the reporting date and is subject to management's judgment. At December 31, 2012 and 2011, no uncertain tax U positions have been identified.

The Cooperative would recognize interest and penalties on income taxes, if any, as a component of income tax expense.

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REVENUE RECOGNITION Revenue from the sale of electricity to members is recorded based on contrac under the Cooperative's current rate schedule.

m COMPREHENSIVE MARGIN U

Comprehensive margin consists of net margin and other comprehensive margin. Other comprehensive margin includes unrealized appreciation (depreciation) on available-for-sale securities and changes in the funded status of the postretirement plan.

IMPAIRMENT OF LONG-LIVED ASSETS The Cooperative evaluates the recoverability of the carrying value of long-lived assets whenever events or circumstances indicate that carrying amount may not be recoverable. If a long-lived asset is tested for recoverability and the undiscounted estimated future cash flows expected to result from the use and eventual disposition of the asset is less than the carrying amount of the asset, the asset cost is adjusted to fair value and an impairment loss is recognized as the amount by which the carrying amount of a long-lived asset exceeds its fair value. No asset impairment was recognized during the years ended December 31, 2012 and 2011.

NOTE 2 ELECTRIC UTILITY PLANT IN SERVICE 2012 2011 ELECTRIC UTILITY PLANT IN SERVICE m

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m Production Transmission General plant Nuclear fuel Other Total (In thousands) 637,649 637,913 42,024 41,998 5,025 4,525 225,963 211,445 25,316 22,369 935,977 918,250 m

NOTE 3 SUSQUEHANNA STEAM ELECTRIC STATION The Cooperative owns a 10 percent undivided interest in SSES. PPL owns the remaining 90 percent.

Both participants provide their own financing. The Cooperative's portion of SSES's gross assets, which includes electric utility plant in service, construction and nuclear fuel in progress, totaled $654 million and

$650 million as of December 31, 2012 and 2011, respectively. The Cooperative's share of anticipated costs for ongoing construction and nuclear fuel for SSES is estimated to be approximately $129 million over the next five years. The Cooperative receives a portion of the total SSES output equal to its SUSQUEHANNA STEAM ELECTRIC STATION balance of power 2012 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 2012 AND 2011 percentage ownership. SSES accounted for approximately 54% and 55% of the total kilowatt hours sold by the Cooperative during the years ended December 31, 2012 and 2011, respectively. The balance sheets and statements of margins reflect the Cooperative's respective undivided share of assets, liabilities and operations associated with SSES.

NOTE 4 INVESTMENTS

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National Rural Utilities Cooperative Finance Corporation (CFC) Subordinated Term Certificates, bearing interest at 5.8%, maturing January 1, 2026(1)

National Rural Utilities Cooperative Finance Corporation (CFC) Subordinated Term Certificates, bearing interest at 3%, maturing January 1, 2014111 National Rural Utilities Cooperative Finance Corporation (CFC) Member Capital Securities, bearing interest at 7.5%, maturing March 24, 2044'1)

Other Total 14,390 15,005 42 10,000 2,540 26,972 86 10,000 2,399 27,490 raThe Cooperative is required to maintain these investments pursuant to certain loan and guarantee agreements.

Such investments are carried at cost.

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U Gross Unrealized Gains Cost Investments U.S. Government agency securities Corporate bonds Auction rate security Mutual funds Total 3,145 22,922 2,831 4,800 33,698 2,690 2012 Gross Unrealized Losses (In thousands)

(2)

(9)

(11) 2011 Gross Unrealized Losses (In thousands)

Realized Losses 3,145 25,610 2,831 4,791 36,377 Fair Value Cost MI Investments U.S. Government U

agency securities Corporate bonds Auction rate security Mutual funds Total 2,690 Gross Unrealized Gains 1

2,476 2,477 Realized Losses Fair Value 5,382 30,745 3,081 4,042 43,250 (2)

(212)

(62)

(276) 5,381 (187) 32,822 3,081 3,980 (187) 45,264 0

Maturities of investments at December 31, 2012:

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One year or less After one through five years Mutual funds Amortized Approximate Cost Fair Value (In thousands) 6,678 6,692 22,220 24,894 4,800 4,791 33,698 36,377 Corporate bonds in CFC comprise approximately $15 million and $19 million of the debt securities in 2012 and 2011, respectively.

Gross gains of $118,000 and $676,000 and gross losses of $58,000 and $267,000 resulting from sales of securities were realized for 2012 and 2011, respectively. These gains and losses are included in capital credits and other income on the consolidated statements of margin.

balance of power 1 2012 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31,2012 AND 2011 Certain investments in debt and equity securities are reported in the financial statements at an amount less than their historical cost. Total fair value of these investments at December 31, 2012 and 2011, was

$9.6 million and $18.4 million, respectively. These declines primarily resulted from increases in market interest rates prior to the balance sheet date and the failure of certain investments to meet projected earnings targets. The gross unrealized losses at December 31, 2012 and 2011 for a period of less than 12 months were $1,000 and $5,000, respectively, and for a period of greater than 12 months were

$10,000 and $271,000, respectively.

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NUCLEAR DECOMMISSIONING TRUST No other-than-temporary impairment was recorded for 2012. In 2011, the Cooperative recorded other-than-temporary impairment on a corporate bond. The cost-basis of this investment has been adjusted to reflect recognition of this impairment. Total other-than-temporary impairment reflected in the statement of margins for 2011 was $187,000 for this temporary investment.

NOTE 5 NUCLEAR DECOMMISSIONING TRUST The Nuclear Decommissioning Trust consists of the following as of December 31, 2012 and 2011:

Gross Unrealized Gains 2012 Gross Unrealized Realized Losses Losses (In thousands)

Fair Value Cost Decommissioning Trust Fund Money market funds U.S. Government securities Corporate bonds Other obligations Common stocks Total 415 25,377 16,295 624 30,087 72,798 518 926 41 16,274 17,759 Gross Unrealized Gains (82)

(45) 415 25,813 17,176 U 665

9) 46,051

9) 90,120 (211)

(338)

(9.

(9(

2011 Gross Unrealized Realized Losses Losses (In thousands)

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Cost Decommissioning Trust Fund Money market funds U.S. Government securities Corporate bonds Other obligations Common stocks Total 460 460 N

23,584 13,172 1,864 27,798 66,878 1,398 713 120 11,577 13,808 (9)

(120)

(2)

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(467) 24,973 13,765 1,982 (722) 38,317 (722) 79,497 0

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Certain investments in debt and equity securities are reported in the financial statements at an amount less than their historical cost. Total fair value of these investments at December 31, 2012 and 2011 was i

$14.0 million. These declines primarily resulted from increases in market interest rates prior to the balance sheet date and the failure of certain investments to meet projected earnings targets. The gross unrealized losses at December 31, 2012 and 2011 for a period of less than 12 months were $273,000 and $378,000, i

respectively, and for a period of greater than 12 months were $65,000 and $89,000, respectively.

m For 2012 and 2011, the Cooperative recorded other-than-temporary impairments on equity securities in the amount of $99,000 and $722,000, respectively. The cost-basis of these investments has been adjusted to reflect the recognition of these impairments.

l Under ASC Topic 980, Regulated Operations, the Cooperative has elected to defer these losses and i

pass them on to members through the future rate structure. As of December 31, 2012 and 2011, total deferred charges for the Nuclear Decommissioning Trust other-than-temporary impairment were

$3,530,000 and $3,869,000.

• NOTE 6 m

DERIVATIVES AND HEDGING t4 The Cooperative does not engage in speculative derivative transactions; however, the Cooperative DERIVATIVES m

engages in hedging activities that are a natural part of power supply and transmission activities.

AND HEDGING The Cooperative uses hedging instruments, including forwards, futures, financial transmission rights, and options, to manage power market price risks. In addition, substantial reliance on the purchase of energy from other power suppliers exposes the Cooperative to the risk that counterparties will default. Therefore, an assessment is performed on the creditworthiness of counterparties and other credit issues related to these purchases, which may require the counterparties to post collateral. Defaults, however, may still occur, If a default occurs, the Cooperative may be forced to enter into alternative contractual arrangements or purchase energy in the forward, short-term or spot markets at then-current market prices that could vary from the prices previously agreed upon with the defaulting counterparty. The Cooperative has never had a counterparty default or fail to perform, but past performance is no guarantee of future results.

m FINANCIAL TRANSMISSION RIGHTS The Cooperative is issued Financial Transmission Rights (FTRs) by the PJM Interconnection LLC, (PJM).

These FTRs have been found to meet the FASB ASC Topic 815, Derivatives and Hedging, definition of a derivative, and therefore must have special derivative accounting procedures applied to them.'

The Cooperative receives an entitlement of FTRs. FTRs are defined from a "source" node to a "sink" node (path) for a specific amount of megawatts of electric power. The holder of an FTR is entitled to U

m balance of power 2012 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31,2012 AND 2011

=

receive whole or partial offsets of transmission congestion charges that arise when that specific path is congested. The purpose of the FTR mechanism is to act as a hedge against volatile congestion charges.

Market values of FTRs are only observable based on the clearing prices of the FTRs in multi-year, annual, seasonal and monthly auctions. The expected value of FTRs fluctuates based on seasonal expectations of the supply and demand of energy for each specific path. Significant assumptions and modeling projections are necessary to value FTRs. The expected FTR values are considered in the rate-making process and therefore the fair value of FTRs are recognized on the balance sheet and recorded as deferred income under ASC Topic 980, Regulated Operations. The fair value of FTRs was $2,942 000 and $10,242,000 as of December 31, 2012 and 2011 for the remainder of the current PJM planning periods that end May 31, 2012 and 2011 and beyond.

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Fair value of FTRs 2,942 10,242

• Balance sheet locations Current assets Current assets Current liabilities Current liabilities Noncurrent assets Noncurrent assets Noncurrent liabilities Noncurrent liabilities FORWARD SWAPSi The Cooperative is exposed to market purchases of power to meet the power supply needs of the member U

distribution cooperatives that are not met by Cooperative-owned generation. While the Cooperative does not engage in speculative practices, the Cooperative utilizes derivative contracts to manage this exposure. Power is purchased under both long-term and short-term physically-delivered and financially-settled forward contracts to supply power to member cooperatives. These forward purchase contracts meet the accounting definition of a derivative; however, a majority of the forward purchase derivative contracts qualify for the normal purchases/normal sales exception under previously issued guidance. As U

a result, these contracts are not recorded at fair value and are not subject to the disclosure requirements.

Purchased power is expensed when the power under the forward contract is delivered.

IN The Cooperative purchased capacity swap forward contracts in order to lock in capacity pricing prior to the completion of capacity auctions. These derivatives do not qualify for the normal purchases/normal U

sales exception; however, the Cooperative opted out of the cash flow hedge accounting as allowed under previously issued guidance. For these derivative contracts that did not qualify for the normal purchases/

normal sales exception, the Cooperative deferred all gains and losses on a net basis as a regulatory asset or liability in accordance with ASC Topic 980, Regulated Operations. These amounts were subsequently UI allegheny electric cooperative, inc.

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m reclassified as purchased power in the consolidated statements of margin as the power was delivered and/or the contract settled.

Generally, derivatives are reported on the consolidated balance sheet at fair value. The measurement of fair value is based on actively quoted market prices, if available. Otherwise, indicative price information is sought from external sources, including broker quotes and industry publications. For individual contracts, the use of differing assumptions could have a material effect on the contract's estimated fair value.

Changes in the fair value of the derivative instruments are recorded as a regulatory asset or regulatory liability. The change in these accounts is included in the operating section of the statement of cash flows.

As of December 31, 2012, the Cooperative had no outstanding derivative futures contracts. As of December 31, 2011, the Cooperative had the following outstanding derivative futures contracts:

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Unit of Measure Commodity Quantity Capacity swap MW 47,565 As of December 31, 2011, the fair value of the derivative instruments, excluding contracts accounted for as a normal purchase/normal sale, were as follows:

2011 Remaining Cost (in thousands) 9,097 Current liabilities Capacity swap forward contracts Balance sheet locations Fair Value (in thousands) 5,266 Current assets As of December 31, 2011, the Cooperative deferred the following losses on a net basis as a regulatory asset in accordance with ASC Topic 980, Regulated Operations:

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Location of Loss in the Statement of Margin at Settlement Purchased Power Amount of Deferred Loss at December 31, 2011 (in thousands)

(3,832)

Capacity swap forward contracts balance of power ' 2012 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31,2012 AND 2011 II il.

w DEFERRED CHARGES NOTE 7 DEFERRED CHARGES Deferred charges consist of the following regulatory assets as of December 31, 2012 and 2011.

2012 2011 (In thousands)

Deferred asset plan - NDT investments (see Note 5)

Deferred decommissioning regulatory asset Deferred asset plan - forward swaps (see Note 6)

Safe harbor lease closing costs 3,530 1,159 3,869 3,832 1

13 4,690 7,714 Effective July 1, 2012, the Cooperative established a decommissioning regulatory account under ASC Topic 980, Regulated Operations. This account includes the excess (deficiency) of the annual accretion of the asset retirement obligation over (under) the annual cash contribution and realized earnings of the NDT. The Cooperative monitors this account periodically and will recognize amounts in the statements of margin and pass amounts through to its members as necessary to meet the funding requirements of the NDT. No such amounts were recognized during July 1, 2012 through December 31, 2012.

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m NOTE 8 ASSET RETIREMENT OBLIGATION Amounts collected from the Cooperative's members for decommissioning, less applicable taxes, are deposited in external trust funds for investment and can only be used for future decommissioning costs.

The fair value of the nuclear decommissioning trust was $90.1 million and $79.5 million for the years ended December 31, 2012 and 2011, respectively.

The changes in the carrying amounts of asset retirement obligations were as follows:

2012 2011 (In thousands)

Be_ ginning balance Accretion expense 148,050 5,923 142,355 5,695 Ending balance 153,973 148,050 The amount of actual obligation could differ materially from the estimates reflected in these financial statements.

I NOTELO GTR DET9~w*

LONG-TERM DEBTI S2012 2011 LONG-TERM DEBT (In thousands)

Note payable CFC, payable in varying quarterly installments beginning April 2008, plus interest at 6.8%, final payment January 2014 5,175 9,050 Note payable CFC, payable in varying quarterly installments beginning I

April 2014, plus interest at 6.9%, final payment January 2021 38,600 38,600 Note payable CFC, payable in varying quarterly installments beginning April 2021, plus interest at 7.0%, final payment April 2025 39,700 39,700 Note payable CFC, payable in varying quarterly installments beginning I

July 2006, plus interest at 6.8%, final payment January 2014 750 1,350 Note payable CFC, payable in varying quarterly installments beginning April 2014, plus interest at 6.9%, final payment January 2021 5,800 5,800 I

Note payable CFC, payable in varying quarterly installments beginning April 2021, plus interest at 7.0%, final payment April 2025 6,200 6,200 Note payable CFC, payable in varying quarterly installments beginning I

July 2006, plus interest at 7.25%, final payment October 2025 11,510 12,026 Note payable CFC, payable in varying quarterly installments beginning I

July 2006, plus interest at 7.25%, final payment October 2025 1,841 1,924 I

Note payable CFC, payable in varying quarterly installments beginning October 2009, plus interest ranging from 4.05% to 6.65%,

I final payment October 2025 36,750 37,667 Note payable CFC, payable in varying quarterly installments beginning January 2012, plus interest ranging from 2.60% to 5.25%,

I final payment October 2025 19,775 10,000 I

Note payable Co-Bank, payable in varying annual installments beginning January 2012, plus interest ranging from 1.78% to 4.89%, final payment January 2018 9,018 9,966 I

Total long-term debt 175,119 172,283 Less current installments 7,721 7,164 U

Long-term debt, net of current installments

$ 167,398

$ 165,119 U

The Cooperative has an additional available borrowing balance with CFC through December 2025 beyond the operating line of credit below totaling $86,338,000 at December 31, 2012.

balance of power 2012 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 2012 AND 2011 The Cooperative had a $35,000,000 operating line of credit with CFC that expired on March 31, 2011.

The Cooperative renewed the operating line of credit through March 31, 2016 at $50,000,000 under the same basic terms. There were borrowings of $20,500,000 against this line as of December 31, 2012, and there were no outstanding borrowings against this line as of December 31, 2011. The interest rate on the line of credit fluctuates as established by CFC and was 2.90% as of December 31, 2012.

Additionally, the Cooperative has a commitment from CFC to provide unsecured letters of credit of up to

$25,000,000. Under this commitment, the Cooperative has unsecured letter of credit facilities totaling

$18,700,000 which expire at various dates throughout 2013. As of December 31, 2012 and 2011, no funds have been drawn against this facility.

Future maturities of all long-term debt are as follows (in thousands):

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U 2013 2014 2015 2016 2017 Thereafter 7,721 8,577 9,384 11,531 13,803 124,103 175,119 A'W INCOME TAXES Substantially all assets of the Cooperative are pledged to secure the notes payable. The Cooperative is required to maintain certain covenants including an annual debt service coverage ratio. The Cooperative was in compliance with the applicable covenant as of December 31, 2012 and 2011, respectively.

During 2012 and 2011, the Cooperative incurred interest costs of $10,744,000 and $10,445,000, respectively.

NOTE 10 INCOME TAXES As of December 31, 2012 and 2011, the Cooperative had available nonmember net operating loss carryforwards of approximately $10 and $13 million, respectively for tax reporting purposes expiring in 2013 through 2019, and alternative minimum tax credit carryforwards of approximately $1,252,000 and

$1,297,000 respectively, which carry forward indefinitely.

There was no provision for federal income taxes at December 31, 2012 and 2011. The Cooperative is not subject to state income taxes. The Cooperative is no longer subject to federal income tax examinations by tax authorities for years before 2009.

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U Temporary differences that give rise to deferred tax balances are principally attributable to fixed asset basis, safe harbor lease treatment, and financial statement accruals. Deferred tax assets also include the effect of net operating loss carryforwards. The temporary differences and the carryforward items produce a deferred tax asset at December 31, 2012 and 2011, of approximately $7.3 and $10.4 million, respectively. Realization of the net deferred tax asset is contingent upon the Cooperative's future earnings. A valuation allowance of approximately $1 million in 2011 had been established against this asset because it had been determined that this portion of the deferred tax asset more likely than not would be unrealized. This valuation allowance was removed in 2012. The Cooperative will include the utilization of the net deferred tax asset of approximately $7.3 million and $9.4 million at December 31, 2012 and 2011, respectively, in future rates charged to members. Therefore, a deferred credit has been recorded equal to the net deferred tax asset under FASB ASC Topic 980, Regulated Operations.

NOTE 11 RELATED PARTY TRANSACTION A related organization, the Pennsylvania Rural Electric Association (PREA), has provided the Cooperative with certain management, general, and administrative services on a cost reimbursement basis. The costs for services provided by PREA were $906,000 and $946,000 for the years ended December 31, 2012 and 2011, respectively.

NOTE 12 CONSOLIDATED VARIABLE INTEREST ENTITY As the primary beneficiary, the Cooperative consolidates CCS. The general creditors of CCS have no recourse against the general credit of the Cooperative.

The following table summarizes the carrying amount of the assets and liabilities of CCS included in the Cooperative's consolidated balance sheets at December 31, 2012 and 2011:

RELATED PARTY TRANSACTION CONSOLIDATED VARIABLE INTEREST ENTITY 2012 2011 (In thousands)

Current assets Cash and cash equivalents Accounts receivable, affiliated organization Other receivables Other current assets Non-utility property

$ 735 103 9

686 12

$ 860 14 9

1,139 15 m

m Total assets 1,545 2,037 balance of power 1 2012 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 2012 AND 2011 Current liabilities Accounts payable and accrued expenses Accrued postretirement benefit cost Accounts payable, affiliated organization

$1,667 231 88

$1,488 311 88 Total liabilities 1,986 1,887 POSTRETIIREMENT BENEFITS NOTE 13 POSTRETIREMENT BENEFITS As of November 1,1995 (the effective date), postretirement medical benefits are only offered to grandfathered employees. There are two different levels of benefits for those grandfathered retirees. For each retiree over the age of 62 on the effective date, CCS pays the full premium for the appropriate medical insurance for the covered participant. For those that were over the age of 55 but younger than 62 on the effective date, CCS pays a maximum premium for medical insurance equal to the policy premium on November 1, 1995. In this second group, the participant is responsible for any increases above this amount. On December 31, 2012 and 2011, there were nine and eleven individuals covered under this plan, respectively. CCS expects to contribute $22,000 to the plan in 2013. This amount will be allocated to the Cooperative and PREA based on historical payroll allocations of the retirees covered under the plan.

CCS uses a December 31 measurement date for the plan. Information about the plan's funded status follows:

UI UI UI UI UI UI UI II UI UI UI UI UI UI UI UI UI U!

UI UI UI UI UI UI UI II UI II UI UI UI UI 2012 2011 (In thousands)

$ 231 Benefit obligation, projected Fair value of plan assets

$311 Funded status (231)

(311)

Amounts recognized in the statements of financial position:

2012 2011 (In thousands) 231 311 Accrued postretirement benefit cost liability allegheny electric cooperative, inc.

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U Amounts recognized in accumulated other comprehensive income not yet recognized as components of net periodic benefit cost consist of:

2012 2011 (In thousands)

Net Loss Transition obligation

$ 75 27 102

$124 65 189 The accumulated benefit obligation for the plan was $129,000 and $122,000 at December 31, 2012 and 2011, respectively.

Other significant balances and costs are:

2012 2011 Employer contributions Benefits paid Benefit cost (In thousands)

$ 24

$ 24

$ 85

$22

$22

$ 54 The following amounts have been recognized in the consolidated statement of margins for the year ended December 31, 2012:

2012 2011 (In thousands)

Amounts arising during the period:

Net (gain) loss Net transition obligation

$ (49) 38 The estimated net loss and transition obligation for the plan that will be amortized from accumulated other comprehensive income into net periodic benefit cost over the next fiscal year are $4,000 and

$17,000, respectively.

The discount rate used to determine the benefit obligation was 3.65% and 4.70% for 2012 and 2011, respectively.

For measurement purposes, a 6% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2012 and should remain at that level.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 2012 AND 2011 m

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As of December31, 2012, the expected future payments, which reflect expected future service, are as follows:

2013 22 2014 22 2015 22 U

2016 21 2017 21 2018 and thereafter 123 NOTE 14 EMPLOYEE BENEFIT PLANS EMPLOYEE All employment relationships are through CCS, the consolidated variable interest entity of the Cooperative.

BENEFIT PLANS CCS's leave policies provide for payment of unused leave after the end of each calendar year for 2012 and 2011. A provision has been recorded for this liability.

MULTI-EMPLOYER PENSION PLAN Substantially all of the employees of CCS participate in the National Rural Electric Cooperative Association U

(NRECA) Retirement Security Plan (RS Plan). The RS Plan is a defined benefit pension plan qualified under Section 401 and tax exempt under Section 501(a) of the Internal Revenue Code. It is a multi-employer plan under the accounting standards. The plan sponsor's Employer Identification Number is 53-0116145 and the Plan Number is 333.

A unique characteristic of a multi-employer plan compared to a single employer plan is that all plan assets are available to pay benefits of any plan participant. Separate asset accounts are not maintained for participating employers. This means that assets contributed by one employer may be used to provide U

benefits to employees of other participating employers.

The Cooperative's contributions, through CCS, to the RS Plan in 2012 and in 2011 represented less than 5 percent of the total contributions made to the plan by all participating employers. The Cooperative, through CCS, made contributions to the plan of $1,837,000 in 2012 and $1,814,000 in 2011. There have been no significant changes that affect the comparability of 2012 and 2011 contributions.

In the RS Plan, a "zone status" determination is not required, and therefore not determined, under the Pension Protection Act (PPA) of 2006. In addition, the accumulated benefit obligations and plan assets are not determined or allocated separately by individual employer. In total, the RS Plan was between 65 percent and 80 percent funded at January 1, 2012 and January 1, 2011 based on the PPA funding target and PPA actuarial value of assets on those dates.

Because the provisions of PPA do not apply to the RS Plan, funding improvement plans and surcharges are not applicable. Future contribution requirements are determined each year as part of the actuarial valuation U

of the plan and may change as a result of plan experience.

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DEFINED CONTRIBUTION PLAN The Cooperative, through CCS, has a 401(k) defined-contribution plan covering substantially all employees, which allows for both employee and Cooperative contributions. Contributions to the plan were approximately mm

$418,000 and $469,000 for 2012 and 2011, respectively.

m DEFERRED COMPENSATION AGREEMENTS m

The Cooperative, through CCS, has an employment agreement with its President & CEO and retention arrangements with deferred compensation provisions.

NOTE 15

'vi1 A Tij COMMITMENTS AND CONTINGENCIES POWER SUPPLY AND TRANSMISSION AGREEMENTS COMMITMENTS AND The Cooperative has entered into power supply and transmission agreements with various service providers.

CONTINGENCIES A significant number of these agreements are umbrella type agreements and do not bind the Cooperative to enter into any type of transaction.

Since June 2007, the Cooperative has issued periodic Requests for Proposal (RFP) for energy and/or capacity products for varying quantities and terms between one and five years with delivery beginning in 2009 or later.

As of December 31, 2012, there were several significant capacity and energy transactions under these umbrella agreements with some energy deliveries beginning as early as 2009 and extending through 2014.

The Cooperative also purchased capacity for 2009 through May 2016, in a series of transactions. These transactions contained specific quantities of capacity, all of which were or will be needed to serve the Cooperative's load.

A summary of the power supply agreements are as follows:

NEW YORK POWER AUTHORITY This contract meets a portion of the Cooperative's base load and peaking requirements and its delivered cost to the Cooperative's members is below market. The current contract terminates in 2025 for the Niagara Project. The current contract for the St. Lawrence Project expires in 2017.

2012 ENERGY PROVIDER As the result of a competitive request for proposals, the Cooperative entered into an agreement in April 2011 to provide the Cooperative's remaining unmet load requirements beginning in January 2012.

The agreement provides for the Cooperative to purchase energy at a fixed price within a monthly quantity bandwidth. Quantities outside of the bandwidth are priced using a market-based risk sharing mechanism.

The Cooperative also has the obligation to provide a specified amount of generation from its owned or balance of power 2012 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31,2012 AND 2011 U

controlled resources or to provide any shortfall energy from market sources. The agreement expired on December 31, 2012.

FUTURE POWER SUPPLY Using the RFP process, the Cooperative entered into power purchase agreements in 2009 with various counterparties for a combination of around-the-clock, on-peak and off-peak energy and call option products that would meet approximately 90 percent of its projected energy requirements in 2013.

The Cooperative entered into an agreement in May 2012 to provide the Cooperative's remaining current U

load requirements beginning in January 2013. The agreement expires in December 2013.

Various purchased power agreements require the Cooperative to post collateral deposits for exposure exceeding specified thresholds. As of December 31, 2012, collateral deposits totaled $2,671,000. Other agreements allow the Cooperative to provide additional credit support in the form of irrevocable standby U

letters of credit. The Cooperative had such letters issued as of December 31, 2012 in the amount of

$7,700,000. These letters of credit were provided by CFC and are valid through dates ranging from July 31, 2013 through December 31, 2013.

U SSES REPLACEMENT POWER INSURANCE POLICY U

The Cooperative mitigated a portion of the economic risk of an outage at SSES by purchasing a Replacement Power Insurance Policy from Ariel Syndicate 1910. Under the terms of the policy, if SSES had a forced outage event, the Cooperative would have been reimbursed for the cost of replacement power for the insured quantity of up to 250 MW. The policy stipulates that the outage limit for each such

• forced outage is 90 consecutive days, and the aggregate coverage limit is $10 million. For this coverage, the Cooperative purchased a two-year policy terminating December 31, 2014.

TRANSMISSION SERVICE Transmission service for the Cooperative's load is provided through a hybrid arrangement consisting U of the PJM Open Access Transmission Tariff (OATT) and the pre-existing Wheeling and Supplemental Power Agreement with Pennsylvania Electric Company. A separate irrevocable standby letter of credit is related to obligations existing under the OATT. This letter of credit was issued during 2011 in the amount U

of $11,000,000 to the benefit of PJM Settlement, Inc. The letter of credit was provided by CFC and is valid through August 14, 2013.

INSURANCE PPL, as the 90 percent owner and sole operator of SSES, and the Cooperative, as owner of a 10 percent undivided interest in SSES, are members of certain insurance programs which provide coverage for n

property damage to the SSES nuclear generation plant. Under these programs, the plant, as a whole, has property damage coverage for up to $2.75 billion. Additionally, there is coverage for the cost of replacement power during prolonged outages of nuclear units caused by certain specified conditions.

Under the property and replacement power insurance programs, PPL and the Cooperative could allegheny electric cooperative, inc.

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be assessed retrospective premiums in the event the insurers' losses exceed their reserves. As of December 31, 2012, the maximum amount PPL and the Cooperative jointly could be assessed under I

these programs was $44 million annually.

I PPL and the Cooperative's public liability for claims resulting from a nuclear incident is currently limited to

$12.6 billion under provisions of the Price-Anderson Act Amendments of 2005. In the event of a nuclear incident at any of the reactors covered by the Act, PPL and the Cooperative could be assessed up to

$235 million per incident, payable at $35 million per year.

SAFE HARBOR LEASE The Cooperative previously sold certain investment and energy tax credits and depreciation deductions pursuant to a safe harbor lease. The proceeds from the sale, including interest earned thereon, have U

been deferred and are being recognized on the statements of operations over the 30-year term lease.

The deferred gain was $0.03 million and $0.3 million as of December 31, 2012 and 2011, respectively.

Under the terms of the safe harbor lease, the Cooperative is contingently liable in varying amounts in the U

event the lessor's tax benefits are disallowed and in the event of certain other occurrences. The maximum amount for which the Cooperative was contingently liable as of December 31, 2012 was approximately

$0.8 million. Payment of this contingent liability has been guaranteed by CFC. As of February 2013, the lease and any contingent liability has ended.

LITIGATION The Cooperative may be subject to claims and lawsuits that arise primarily in the ordinary course of business. At December 31, 2012, no such claims or lawsuits existed.

4 NOTE 16 q,

DEFERRED CREDITS SALE/LEASEBACK ARRANGEMENT DEFERRED CREDITS The Cooperative previously completed a sale and leaseback of its hydroelectric generation facility at the Raystown Dam (the Facility). The Facility was sold to a trustee bank representing Ford Motor Credit Company I

(Ford) for $32 million in cash. During 1996, Ford transferred its interest in the Facility to a third party. Under terms of the arrangement, the Cooperative leased the Facility for an initial term of 30 years beginning June 1988. Payments under the lease were due in semi-annual installments which commenced January 10, 1989. At the end of the 30-year term, the Cooperative had the option to purchase the Facility for an amount equal to the Facility's fair market value or for a certain amount fixed by the transaction documents.

The Cooperative also had the option to renew the lease for a five-year fixed rate renewal and three fair market renewal periods, each of which may not be for a term of less than two years. Payments during the fixed rate renewal period were 30 percent of the average semi-annual installments during the initial lease term.

balance of power 2012 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31,2012 AND 2011 The lease payments were based on an assumed interest rate of 8.8 percent and may fluctuate based on differences between the future interest rate and the assumed interest rate. Rental expense for this lease totaled $1.6 million in year ended December 31, 2011. The Cooperative retained co-licensee status n

for the Facility throughout the term of the lease. The gain of $1.9 million related to the sale was being recognized over the lease term. The unrecognized gain was recorded in other deferred revenue.

Effective October 27, 2011, the Cooperative executed an agreement to acquire the Facility. The remaining unrecognized gain of $566,000 was used to reduce the cost of the asset recorded.

The unwind of the sale/leaseback arrangement was concluded by all parties in May 2012. The Cooperative i

applied for and received from the FERC the status of sole licensee for the facility.

DEFERRED REVENUE PLAN The Board has established a Deferred Revenue Plan, which seeks to stabilize members' rates for 2013 and as long as possible thereafter to mitigate the effects of expected increases in rates. The deferral U

of revenue for 2012 was determined as any amount above $2,510,000 assignable margins. Deferred revenue additions and deletions are recorded in operating revenues in the consolidated statements of margin. At December 31, 2012 and 2011, deferred revenues associated with the Deferred Revenue Plan U

were $9,148,000 and $10,428,000, respectively. The changes in deferred revenues in 2012 and 2011 were as follows:

2012 2011 (In thousands)

Beginning balance 10,428 35,732 Additions 9,148 Deletions (10,428)

(25,304)

U Ending balance 9,148 10,428 DEFERRED CREDIT U

With the establishment of a deferred tax asset to record the effect of the temporary differences related to i

net operating loss carryforwards, fixed asset basis, safe harbor lease treatment, and financial statement accruals, the Cooperative established a deferred credit of $7.3 and $9.4 million for 2012 and 2011, respectively, under FASB ASC Topic 980, Regulated Operations. The value of the deferred tax asset is U

considered in the rate making process as required by Topic 980.

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NOTE 17 DISCLOSURES ABOUT FAIR VALUE OF ASSETS AND LIABILITIES Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements must maximize the use of observable inputs and minimize the use of unobservable inputs. There is a hierarchy of three levels of inputs that may be used to measure fair value:

DISCLOSURES ABOUT FAIR VALUE OF ASSETS AND LIABILITIES Level 1 Quoted prices in active markets for identical assets or liabilities Level 2 Observable inputs other than Level 1 prices, such as quoted prices for similar assets or liabilities; quoted prices in active markets that are not active; or other inputs that are U

observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities UI Level 3 Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities RECURRING MEASUREMENTS mI The following table presents the fair value measurements of assets and liabilities recognized in the accompanying consolidated balance sheet measured at fair value on a recurring basis and the level within the fair value hierarchy in which the fair value measurements fall at December 31, 2012 and 2011:

2012 Fair Value Measurements Using I

U7 Quoted Prices in Active Markets for Identical Assets (Level 1)

Significant Other Observable Inputs (Level 2)

Fair Value (In thousands)

Available-for-sale securities Nuclear Decommissioning Trust

$ 90,120 Investments 36,377 Derivative investments 2,942 Financial transmission rights (2,942)

[]

[]

[]

71,239 4,791 18,881 28,755 2,942 (2,942)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 2012 AND 2011 m

2011 Fair Value Measurements Usingm Quoted Prices in Significant Active Markets Other Significant for Identical Observable Unobservable Fair Assets Inputs Inputs Value (Level 1)

(Level 2)

(Level 3)

(In thousands)

Available-for-sale securities Nuclear Decommissioning Trust

$ 79,497 62,420 17,077 Investments 45,264 3,980 38,203 3,081 Derivative investments 15,508 15,508 Financial transmission rights (10,242)

(10,242)

Forward swaps (5,266)

(5,266)

Following is a description of the valuation methodologies and inputs used for instruments measured at fair value on a recurring basis and recognized in the accompanying balance sheets, as well as the general classification of such instruments pursuant to the valuation hierarchy. There have been no significant changes in the valuation techniques during the year ended December 31, 2012. For assets classified within Level 3 of the fair value hierarchy, the process used to develop the reported fair value is reported below.

NUCLEAR DECOMMISSIONING TRUST AND INVESTMENTS (AVAILABLE-FOR-SALE SECURITIES)

Where quoted market prices are available in an active market, securities are classified within Level I of the valuation hierarchy. Level 1 securities include highly liquid government bonds and exchange-traded equities. If quoted market prices are not available, then fair values are estimated by using pricing models, quoted prices of securities with similar characteristics or discounted cash flows. For these investments, the inputs used by the pricing service to determine fair value may include one, or a combination of: observable inputs such as benchmark yields, reported trades, broker/dealer quotes, benchmark securities, bids, offers, and reference data market research publications and are classified within Level 2 of the valuation hierarchy. Level 2 securities include certain collateralized mortgage and debt obligations and certain municipal securities. In certain cases where Level 1 or Level 2 inputs are not available, securities are classified within Level 3 of the hierarchy and include an auction rate security.

Inputs include quoted market prices, benchmark securities, bids, offers and broker/dealer quotes.

DERIVATIVES The fair value is estimated using inputs that are observable or that can be corroborated by observable market data and, therefore, are classified within Level 2 of the valuation hierarchy. For financial transmission rights, inputs include clearing prices of the FTRs at multi-year, annual, seasonal and monthly auctions allegheny electric cooperative, inc.

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adjusted for seasonal expectations of the supply and demand of energy. For forward swaps, inputs include actively quoted market prices, broker quotes and industry publications.

• I LEVEL 3 RECONCILIATION U

The following is a reconciliation of the beginning and ending balances of recurring fair value measureme recognized in the accompanying consolidated balance sheet using significant unobservable (Level 3) i1 Auction Rate Security (In thousands)

Balance, January 1, 2011 3,278 Total realized and unrealized gains and losses Included in net margin 103 Included in other comprehensive margin Settlements (300)

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Balance, December 31, 2011 3,081 Total realized and unrealized gains and losses Included in net margin Included in other comprehensive margin Settlements (250)

Ui Balance, December 31, 2012 2,831 During 2012, there were no realized gains and losses for the item reflected in the table above included in net margin in the accompanying consolidated statements of margin. During 2011, realized gains of $103,000 for the item reflected in the table above is included in net margin in the accompanying consolidated statements of margin.

UNOBSERVABLE (LEVEL 3) INPUTS U

The following table presents quantitative information about unobservable inputs used in recurring Level 3 fair value measurements:

-=

2012 Auction rate security UI Valuation Unobservable Fair Value Technique Inputs

$ 2,831 Discounted cash flow Discount Rate 4.50%

Estimated maturity 2021 Estimated cash flow Historical retirements balance of power 2012 ANNUAL REPORT

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 2012 AND 2011 FAIR VALUE OF OTHER FINANCIAL INSTRUMENTS The estimated fair values of the Cooperative's other financial instruments at December 31, 2012 and 2011 are as follows (in thousands):

U 2012 2011 Carrying Estimated Carrying Estimated Amount Fair Value Amount Fair Value Cash and cash equivalents

$ 31,154 Investment in associated organizations 26,972 Long-term debt 175,119

$ 31,154 26,972 175,119

$16,067 27,490 172,283

$16,067 27,490 172,283 U

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The following methods were used to estimate the fair value of all other financial instruments not recognized in the accompanying balance sheet.

CASH AND CASH EQUIVALENTS The carrying amount approximates fair value.

INVESTMENTS IN ASSOCIATED ORGANIZATIONS Management was not able to estimate the fair value of investments that represent the Cooperative's-investment in memberships and other associated organizations and they remain at their carrying value.

LONG-TERM DEBT REALTY TAXES Due to the current market interest rates and/or short-term maturities of the Co amounts approximate fair value.

NOTE 18 REALTY TAXES The Cooperative's portion of local real estate taxes related to SSES are bill The Cooperative is billed and pays directly to various local tax jurisdictions local property that is exclusively owned by the Cooperative.

NOTE 19 SUBSEQUENT EVENTS SUBSEQUENT EVENTS Subsequent events have been evaluated through the date of the Independent Auditor's Report, which the date the financial statements were available to be issued.

allegheny electric cooperative, inc.

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