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Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-K

 

 

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2014

OR

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

Commission file number 000-50039

 

 

OLD DOMINION ELECTRIC COOPERATIVE

(Exact name of Registrant as specified in its charter)

 

 

 

VIRGINIA   23-7048405

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. employer

identification no.)

 

4201 Dominion Boulevard, Glen Allen, Virginia

 

 

23060

(Address of principal executive offices)   (Zip code)

(804) 747-0592

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act: NONE

Securities registered pursuant to Section 12(g) of the Act: NONE

 

 

Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act?    Yes  ¨    No  x

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act (the “Exchange Act”).    Yes  x    No  ¨

Indicate by check mark whether the Registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ¨    No  x

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405) is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this form 10-K.  x

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer   ¨    Accelerated filer   ¨
Non-accelerated filer   x    Smaller reporting company   ¨

Indicate by check mark whether the Registrant is a shell company (as defined in Exchange Act Rule 12b-2).    Yes  ¨    No  x

State the aggregate market value of the voting and non-voting common equity held by non-affiliates of the Registrant. NONE

Indicate the number of shares outstanding of each of the Registrant’s classes of common stock. The Registrant is a membership corporation and has no authorized or outstanding equity securities.

Documents incorporated by reference: NONE

 

 

 


Table of Contents

OLD DOMINION ELECTRIC COOPERATIVE

2014 ANNUAL REPORT ON FORM 10-K

 

Item

Number

       Page
Number
 
 

Glossary of Terms

     1   
PART I   

1.

 

Business

     3   

1A.

 

Risk Factors

     18   

1B.

 

Unresolved Staff Comments

     22   

2.

 

Properties

     23   

3.

 

Legal Proceedings

     25   

4.

 

Mine Safety Disclosures

     26   
PART II   

5.

 

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

     27   

6.

 

Selected Financial Data

     27   

7.

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

     29   

7A.

 

Quantitative and Qualitative Disclosures About Market Risk

     49   

8.

 

Financial Statements and Supplementary Data

     51   

9.

 

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

     81   

9A.

 

Controls and Procedures

     81   

9B.

 

Other Information

     82   
PART III   

10.

 

Directors, Executive Officers and Corporate Governance

     83   

11.

 

Executive Compensation

     86   

12.

 

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

     93   

13.

 

Certain Relationships and Related Transactions, and Director Independence

     93   

14.

 

Principal Accounting Fees and Services

     94   
PART IV   

15.

 

Exhibits, Financial Statement Schedules

     95   
SIGNATURES   


Table of Contents

GLOSSARY OF TERMS

The following abbreviations or acronyms used in this Form 10-K are defined below:

 

Abbreviation or Acronym

  

Definition

ACES    Alliance for Cooperative Energy Services Power Marketing, LLC
Alstom    Alstom Power, Inc.
Bear Island    Bear Island Paper WB LLC
CAA    Clean Air Act
CAIR    Clean Air Interstate Rule
CCRs    Coal combustion residuals
CEC    Choptank Electric Cooperative, Inc.
CEO    Chief Executive Officer
CFO    Chief Financial Officer
Clover    Clover Power Station
CPCN    Certificate of Public Convenience and Necessity
CO2    Carbon dioxide
CPP    Clean Power Plan
CSAPR    Cross-State Air Pollution Rule
D.C. Circuit    U.S. Court of Appeals for the District of Columbia Circuit
DEC    Delaware Electric Cooperative, Inc.
DPSC    Delaware Public Service Commission
DOE    U.S. Department of Energy
EGU    Electric generating unit
EP    Essential Power, LLC, formerly known as North American Energy Alliance, LLC
EPA    Environmental Protection Agency
EPACT    Energy Policy Act of 2005, as amended
EPC    Engineering, procurement, and construction
FERC    Federal Energy Regulatory Commission
GAAP    Accounting principles generally accepted in the United States
GHG    Greenhouse gases
Hg    Mercury
Indenture    Second Amended and Restated Indenture of Mortgage and Deed of Trust, dated January 1, 2011, of ODEC with Branch Banking and Trust Company, as trustee, as amended and supplemented
IRC    Internal Revenue Code of 1986, as amended
kV    Kilovolt
LIBOR    London Interbank Offered Rate
MATS    Mercury and Air Toxics Standards
Mitsubishi    Mitsubishi Hitachi Power Systems Americas, Inc.
Moody’s    Moody’s Investors Service
MPSC    Maryland Public Service Commission
MW    Megawatt(s)
MWh    Megawatt hour(s)
NAAQS    National Ambient Air Quality Standards
NERC    North American Electric Reliability Corporation
Norfolk Southern    Norfolk Southern Railway Company
North Anna    North Anna Nuclear Power Station
North Anna Unit 3    A potential additional nuclear-powered generating unit at North Anna
NOVEC    Northern Virginia Electric Cooperative
NOx    Nitrogen oxide
NRC    U.S. Nuclear Regulatory Commission
NRECA    National Rural Electric Cooperative Association
NYMEX    New York Mercantile Exchange
  

 

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ODEC, We, Our Old Dominion Electric Cooperative
Outside Directors Members of our board of directors who are not employed by our member distribution cooperatives
Potomac Edison Potomac Edison Company of Virginia
PJM PJM Interconnection, LLC
PM Particulate matter
PPA Pension Protection Act
Rabobank Cooperative Centrale Raiffeisen Boerenleenbank B.A., “Rabobank Nederland”
RCRA Resource Conservation and Recovery Act, as amended
REC Rappahannock Electric Cooperative
RICE Reciprocating Internal Combustion Engine National Emissions Standards for Hazardous Air Pollutants
RFP Request for proposal
RGGI Regional Greenhouse Gas Initiative
RPM Reliability Pricing Model
RPS Renewable portfolio standards
RTO Regional transmission organization
RUS U.S. Department of Agriculture Rural Utilities Service
S&P Standard & Poor’s Ratings Services
SEPA Southeastern Power Administration
SO2 Sulfur dioxide
SVEC Shenandoah Valley Electric Cooperative
TEC TEC Trading, Inc.
VDEQ Virginia Department of Environmental Quality
Virginia Power Virginia Electric and Power Company
VMDAEC Virginia, Maryland, and Delaware Association of Electric Cooperatives
VSCC Virginia State Corporation Commission
Wildcat Point Wildcat Point Generation Facility
XBRL Extensible Business Reporting Language

 

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Table of Contents

PART I

ITEM 1. BUSINESS

OVERVIEW

Old Dominion Electric Cooperative was incorporated under the laws of the Commonwealth of Virginia in 1948 as a not-for-profit power supply cooperative. We are organized for the purpose of supplying the power our member distribution cooperatives require to serve their customers on a cost-effective basis. We serve their power requirements pursuant to long-term, all-requirements wholesale power contracts. Through our member distribution cooperatives, we served more than 560,000 retail electric customers (meters), representing a total population of approximately 1.4 million people in 2014.

We supply our member distribution cooperatives’ power requirements, consisting of demand requirements and energy requirements, through a portfolio of resources including generating facilities, power purchase contracts, and forward, short-term and spot market energy purchases. Our generating facilities are fueled by a mix of coal, nuclear, natural gas, and fuel oil. See “Power Supply Resources” below and “Properties” in Item 2 for a description of these resources.

We are owned entirely by our members, which are the primary purchasers of the power we sell. We have two classes of members. Our Class A members are customer-owned electric distribution cooperatives that are engaged in the retail sale of power to their customers. Our sole Class B member is TEC, a taxable corporation owned by our member distribution cooperatives. Our member distribution cooperatives primarily serve rural, suburban, and recreational areas. These areas predominantly reflect stable growth in residential capacity and energy requirements both in terms of power sales and number of customers. See “Members—Service Territories and Customers” below.

We are a not-for-profit electric cooperative and are currently exempt from federal income taxation under IRC Section 501(c)(12).

We are not a party to any collective bargaining agreement. We had 111 employees as of March 2, 2015.

Our principal executive offices are located in the Innsbrook Corporate Center, at 4201 Dominion Boulevard, Glen Allen, Virginia 23060-6721. Our telephone number is (804) 747-0592.

We are a power supply cooperative. In general, a cooperative is a business organization owned by its members, which are also either the cooperative’s wholesale or retail customers. Cooperatives are designed to give their members the opportunity to satisfy their collective needs in a particular area of business more effectively than if the members acted independently. As not-for-profit organizations, cooperatives are intended to provide services to their members on a cost-effective basis, in part by eliminating the need to produce profits or a return on equity in excess of required margins. Margins not distributed to members constitute patronage capital, a cooperative’s principal source of equity. Patronage capital is held for the account of the members without interest and returned when the board of directors of the cooperative deems it appropriate to do so.

Electric distribution cooperatives form power supply cooperatives to acquire power supply resources, typically through the construction of generating facilities or the development of other power purchase arrangements, at a lower cost than if they were acquiring those resources alone.

 

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Our Class A members are electric distribution cooperatives. Electric distribution cooperatives own and operate electric distribution systems to supply the power requirements of their retail customers. Electric distribution cooperatives own and maintain nearly half of the distribution lines in the United States and serve three-quarters of the United States’ land mass.

MEMBERS

Member Distribution Cooperatives

General

Our member distribution cooperatives provide electric services, consisting of power supply, transmission services, and distribution services (including metering and billing) to residential, commercial, and industrial customers. We have eleven member distribution cooperatives that serve customers in 70 counties in Virginia, Delaware, and Maryland. The member distribution cooperatives’ distribution business involves the operation of substations, transformers, and electric lines that deliver power to customers.

Eight of our member distribution cooperatives provide electric services on the Virginia mainland:

BARC Electric Cooperative

Community Electric Cooperative

Mecklenburg Electric Cooperative

Northern Neck Electric Cooperative

Prince George Electric Cooperative

Rappahannock Electric Cooperative

Shenandoah Valley Electric Cooperative

Southside Electric Cooperative

Three of our member distribution cooperatives provide electric services on the Delmarva Peninsula:

A&N Electric Cooperative in Virginia

Choptank Electric Cooperative, Inc. in Maryland

Delaware Electric Cooperative, Inc. in Delaware

The member distribution cooperatives are not our subsidiaries, but rather our owners. We have no interest in their properties, liabilities, equity, revenues, or margins.

 

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Revenues from our member distribution cooperatives and the percentage each contributed to total revenues from sales to our member distribution cooperatives in 2014 are as follows:

 

Member Distribution Cooperatives

   Revenues  
     (in millions)         

Rappahannock Electric Cooperative

   $ 311.7         34.3

Shenandoah Valley Electric Cooperative

     172.1         19.0   

Delaware Electric Cooperative, Inc.

     106.8         11.8   

Choptank Electric Cooperative, Inc.

     80.2         8.8   

Southside Electric Cooperative

     70.2         7.7   

A&N Electric Cooperative

     53.0         5.8   

Mecklenburg Electric Cooperative

     43.8         4.8   

Prince George Electric Cooperative

     23.5         2.6   

Northern Neck Electric Cooperative

     21.3         2.4   

Community Electric Cooperative

     15.3         1.7   

BARC Electric Cooperative

     10.1         1.1   
  

 

 

    

 

 

 

Total

$ 908.0      100.0
  

 

 

    

 

 

 

No individual customer of our member distribution cooperatives constituted more than 3.5% of our revenues from our member distribution cooperatives.

Service Territories and Customers

The territories served by our member distribution cooperatives cover large portions of Virginia, Delaware, and Maryland. These service territories range from the extended suburbs of Washington, D.C. to the North Carolina border and from the Atlantic shores of Virginia, Delaware, and Maryland to the Appalachian Mountains.

Our member distribution cooperatives’ service territories are diverse and encompass primarily rural, suburban, and recreational areas. The unemployment rate in their service territories is generally below that of the national average. Our member distribution cooperatives’ customers’ requirements for capacity and energy generally are seasonal and increase in winter and summer as home heating and cooling needs increase and then decline in the spring and fall as the weather becomes milder. Our member distribution cooperatives also serve major industries which include manufacturing, poultry, telecommunications, agriculture, forestry and wood products, paper, and travel.

Our member distribution cooperatives’ sales of energy in 2014 totaled approximately 12,300,000 MWh. These sales were divided by customer class as follows:

 

Customer Class

   Percentage of
MWh Sales
    Percentage of
Customers
 

Residential

     59.6     89.2

Commercial and industrial

     39.1        9.9   

Other

     1.3        0.9   

From 2009 through 2014, our eleven member distribution cooperatives experienced a compound annual growth rate of approximately 4.8% in the number of customers and a compound annual growth rate of 8.0% in energy sales measured in MWh. Our member distribution cooperatives’ service territories continue to experience modest growth due to the expansion of suburban communities into neighboring rural areas and the continuing development of resort and vacation communities within their service territories. These annual growth rates have been impacted by acquisitions of service territories by our member distribution cooperatives. Excluding acquisition of the Virginia service territory of Potomac Edison by two of our member distribution cooperatives and the

 

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disposition by SVEC of service territory in West Virginia, both which occurred in 2010, we estimate that our eleven member distribution cooperatives experienced a compound annual growth rate from 2009 to 2014 of approximately 0.4% in the number of customers and a compound annual growth rate of approximately 2.0% in energy sales measured in MWh.

Our eleven member distribution cooperatives’ average number of customers per mile of energized line has increased approximately 11.2 % since 2009 to approximately 9.4 customers per mile in 2014. System densities of our member distribution cooperatives in 2014 ranged from 6.3 customers per mile in the service territory of BARC Electric Cooperative to 14.4 customers per mile in the service territory of A&N Electric Cooperative. Excluding the Potomac Edison acquisitions and the SVEC disposition, we estimate the average number of customers per mile of energized line increased approximately 3.0% since 2009 to approximately 8.7 customers per mile in 2014. In 2014, the average service density for all distribution electric cooperatives in the United States was approximately 7.4 customers per mile.

Delaware and Maryland each currently grant all retail customers the right to choose their power supplier. Virginia currently grants a limited number of large retail customers the right to choose their power suppliers and only in very limited circumstances. The laws of each state grant utilities, including our member distribution cooperatives, the exclusive right to provide transmission and distribution (including metering and billing) services and to be the default providers of power to their customers in service territories certified by their respective state public service commissions. See “Regulation” and “Competition” below.

Wholesale Power Contracts

Our financial relationships with our member distribution cooperatives are based primarily on our contractual arrangements for the supply of power and related transmission and ancillary services. These arrangements are set forth in our wholesale power contracts with our member distribution cooperatives which are effective until January 1, 2054 and beyond this date unless either party gives the other at least three years notice of termination. The wholesale power contracts are “all-requirements” contracts. Each contract obligates us to sell and deliver to the member distribution cooperative, and obligates the member distribution cooperative to purchase and receive from us, all power that it requires for the operation of its system, with limited exceptions, to the extent that we have the power and facilities available to do so.

The principal exception to the all-requirements obligations of the member distribution cooperatives relates to the ability of our eight mainland Virginia member distribution cooperatives to purchase hydroelectric power allocated to them from SEPA. Purchases under this exception constituted approximately 1.4% of our member distribution cooperatives’ total energy requirements in 2014.

Two additional limited exceptions to the all-requirements nature of the contract permit the member distribution cooperatives to receive up to the greater of 5.0% of their power requirements or 5 MW from owned generation or other suppliers, and to purchase additional power from other suppliers in limited circumstances following approval by our board of directors. In 2014, our member distribution cooperatives collectively received 8.7 MW, under these exceptions. We do not anticipate that this will have a material impact on our financial condition, results of operations, or cash flows.

Each member distribution cooperative is required to pay us monthly for power furnished under its wholesale power contract in accordance with our formula rate. We review our formula rate at least every three years. The formula rate, which has been filed with and accepted by FERC, is designed to recover our total cost of service and create a firm equity base. See “Regulation—Rate Regulation” below and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting Results—Formula Rate” in Item 7. More specifically, the formula rate is intended to meet all of our costs, expenses, and financial obligations associated with our ownership, operation, maintenance, repair, replacement, improvement, modification, retirement, and decommissioning of our generating plants, transmission system, or related facilities, services provided to the member distribution cooperatives, and the acquisition and transmission of power or related services, including:

 

    payments of principal and premium, if any, and interest on all indebtedness issued by us (other than payments resulting from the acceleration of the maturity of the indebtedness);

 

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    any additional cost or expense, imposed or permitted by any regulatory agency; and

 

    additional amounts necessary to meet the requirement of any rate covenant with respect to coverage of principal and interest on our indebtedness contained in any indenture or contract with holders of our indebtedness.

The rates established under the wholesale power contracts are designed to enable us to comply with financing, regulatory, and governmental requirements, which apply to us from time to time.

Regulation of Member Distribution Cooperatives

Of our 11 member distribution cooperatives, 9 currently participate in the RUS loan or guarantee programs. These member distribution cooperatives have entered into loan documents with RUS which we understand contain affirmative and negative covenants, including with respect to matters such as accounting, issuances of securities, rates and charges for the sale of power, construction or acquisition of facilities, and the purchase and sale of power. In addition, we understand financial covenants in these member distribution cooperatives’ loan documents require them to design rates to achieve a specified times interest earned ratio and a debt service coverage ratio. Finally, we understand that the principal loan documentation of our member distribution cooperatives which do not participate in RUS loan or guarantee programs contains similar covenants.

Our member distribution cooperatives in Virginia are subject to rate regulation by the VSCC in the provision of electric services to their customers, but they have the ability to pass through changes in wholesale power costs – the demand and energy costs we charge our member distribution cooperatives – to their customers. Our Virginia member distribution cooperatives also may adjust their rates for distribution service by a maximum net increase or decrease of 5%, on a cumulative basis, in any three year period without approval by the VSCC. Additionally, they may make adjustments to their rates to collect fixed costs through a new or modified fixed monthly charge rather than through volumetric charges associated with energy usage, so long as such adjustments are revenue neutral.

The MPSC regulates the rates and services offered by our Maryland member distribution cooperative, CEC, other than wholesale power costs, which are a pass through to CEC’s customers. Our Delaware member distribution cooperative, DEC, is not regulated by the DPSC, including with respect to wholesale power costs which are a pass through to its customers.

We are not subject to any RPS; however, beginning in 2013, DEC became subject to RPS. DEC meets the RPS through owned and purchased resources and purchases of renewable energy credits. DEC may receive up to the greater of 5.0% of their power requirements or 5 MW from owned generation or other suppliers in accordance with its wholesale power contract with us. See “Wholesale Power Contracts” above.

Competition

Delaware and Maryland each have laws unbundling the power component (also known as the generation component) of electric service to retail customers, while maintaining regulation of transmission and distribution services. All retail customers in Delaware and Maryland, including retail customers of our member distribution cooperatives located in those states, are currently permitted to purchase power from the registered supplier of their choice. In Virginia, certain large retail customers have very limited rights to choose their energy suppliers. As of March 2, 2015, no entity had registered to be an alternative power supplier in any of the service territories of our member distribution cooperatives and, as a result, none of their retail customers have switched to an alternative power supplier.

 

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In Virginia, retail choice in the selection of a power supplier is available to customers that consume at least 5 MW of power individually or in the aggregate (with aggregation subject to the approval of the VSCC), and that do not account for more than 1% of the incumbent utility’s peak load during the past year. Retail choice is also available to any customer whose noncoincident peak demand exceeds 90 MW. Additionally, all customers are permitted to select an alternative power supplier that provides 100% renewable energy if their incumbent utility, such as one of our member distribution cooperatives, does not offer this same option. As of March 2, 2015, eight of our nine Virginia member distribution cooperatives provided this option. Currently, we do not anticipate that these limited rights to retail choice of our member distribution cooperatives’ customers will have a material impact on our financial condition, results of operations, or cash flows.

TEC

TEC is owned by our member distribution cooperatives, and currently is our only Class B member. We have a power sales contract with TEC under which we may sell to TEC power that we do not need to meet the needs of our member distribution cooperatives. TEC then sells this power to the market under market-based rate authority granted by FERC. Additionally, we have a separate contract under which we may purchase natural gas from TEC. TEC does not engage in speculative trading. To facilitate TEC’s participation in the power and natural gas markets, we have agreed to provide a maximum of $200.0 million in credit support to TEC. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Significant Contingent Obligations—TEC Guarantees” in Item 7.

 

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POWER SUPPLY RESOURCES

General

We provide power to our members through a combination of our interests in Clover, a coal-fired generating facility; North Anna, a nuclear power station; our three combustion turbine facilities – Louisa, Marsh Run, and Rock Springs; distributed generation facilities; and physically-delivered forward power purchase contracts and spot market energy purchases. Our energy supply resources for the past three years were as follows:

 

     Year Ended December 31,  
     2014     2013     2012  
     (in MWh and percentages)  

Generated:

               

Clover

     2,832,463         21.2     2,956,164         22.6     2,188,463         17.3

North Anna

     1,843,081         13.8        1,740,612         13.3        1,772,672         14.0   

Louisa

     195,230         1.4        124,360         0.9        73,058         0.6   

Marsh Run

     398,583         3.0        213,666         1.6        122,149         1.0   

Rock Springs

     104,043         0.8        130,422         1.0        66,695         0.5   

Distributed Generation

     2,184         —          444         —          650         —     
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Total Generated

  5,375,584      40.2      5,165,668      39.4      4,223,687      33.4   

Purchased:

Other than renewable:

Long-term and short term

  6,021,116      45.0      5,596,624      42.7      6,688,811      52.8   

Spot market

  1,192,439      8.9      1,591,103      12.1      1,302,173      10.3   
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Total Other than renewable

  7,213,555      53.9      7,187,727      54.8      7,990,984      63.1   
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Renewable (1)

  786,411      5.9      752,990      5.8      444,364      3.5   
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Total Purchased

  7,999,966      59.8      7,940,717      60.6      8,435,348      66.6   
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Total Available Energy

  13,375,550      100.0   13,106,385      100.0   12,659,035      100.0
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

 

(1)  Related to our contracts from renewable facilities from which we obtain renewable energy credits. We sell these renewable energy credits to our member distribution cooperatives and non-members.

Clover and North Anna, our baseload generating facilities, satisfied approximately 23.4% of our capacity obligations and 35.0% of our energy requirements in 2014. Louisa, Marsh Run and Rock Springs, our peaking generating facilities, collectively provided 44.1% of our 2014 capacity obligations, and 5.2% of our 2014 energy requirements. For a description of our generating facilities, see “Properties” in Item 2. In 2014, we obtained the remainder of our capacity obligations through the PJM RPM capacity auction process and purchased capacity contracts. See “PJM” below. The energy requirements not met by our owned generating facilities were obtained from various suppliers under various long-term and short-term physically-delivered forward power purchase contracts and spot market purchases. See “Power Purchase Contracts” below.

In 2014, our member distribution cooperatives’ peak demand occurred in January and was 3,111 MW, excluding power supplied by SEPA which is not an ODEC resource. See “Members—Member Distribution Cooperatives—Wholesale Power Contracts.”

We plan to continue purchasing energy into the future by utilizing a combination of physically-delivered forward power purchase contracts, as well as spot market purchases. As we have done in the past, we expect to adjust our portfolio of power supply resources to reflect our projected power requirements and changes in the market. To assist us in these efforts, we engage ACES, an energy trading and risk management company. Specifically, ACES assists us in negotiating power purchase contracts, evaluating the credit risk of counterparties, modeling our power requirements, bidding and dispatch of our combustion turbine facilities, and executing and settling energy transactions. See “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A.

 

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Power Supply Planning

By utilizing various long-term and short-term planning processes and models, we continually evaluate power supply options available to us to meet the needs of our member distribution cooperatives. Our goal is to supply 50% to 70% of our energy needs from our owned generation and long-term contracted resources. We have policies that establish targets that define how our projected power needs will be met, and one of the ways we manage these targets is the utilization of hedging. We use hedging instruments, including forwards, futures, financial transmission rights, and options, to manage our power market price risks. These hedging instruments have varying time periods ranging from one month to multiple years in advance. Additionally, we evaluate other power supply options including the acquisition or development of additional generating facilities.

Wildcat Point

We are currently constructing, and will be the sole owner of, an approximate 1,000 MW natural gas-fueled generation facility, named Wildcat Point, in Cecil County, Maryland. The development, construction, and operation of Wildcat Point are subject to obtainment of necessary governmental and regulatory approvals. On April 8, 2014, we received a Final Order granting approval of the CPCN from the MPSC. On June 2, 2014, we selected White Oak Power Constructors as the EPC contractor and began capitalizing construction costs related to Wildcat Point. Site preparation and engineering activities are in process. Permanent construction began in January 2015 and we began capitalizing interest with respect to the facility. The facility is scheduled to become operational in mid-2017. We currently anticipate that the project cost will be approximately $790.5 million, including capitalized interest.

Wildcat Point will consist of two combustion turbines, two heat recovery steam generators and one steam turbine generator. Mitsubishi will supply the combustion turbines. Alstom will supply the heat recovery steam generators and the steam turbine generator. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Wildcat Point” in Item 7.

PJM

PJM is an RTO that coordinates the transmission of wholesale electricity in all or parts of 13 states and the District of Columbia. As a federally regulated RTO, PJM must act independently and impartially in managing the regional transmission system and the wholesale electricity market. PJM is primarily responsible for ensuring the reliability of the largest centrally dispatched energy market in North America. PJM coordinates the continuous buying, selling, and delivery of wholesale electricity over its members’ service territories. PJM system operators continuously conduct dispatch operations and monitor the status of the transmission grid of its participants. PJM also oversees a regional planning process for transmission expansion to ensure the continued reliability of the PJM electric system. PJM coordinates and establishes policies for the generation, purchase, and sale of capacity and energy in the control areas of its members.

All of our member distribution cooperatives’ service territories are in PJM. As a member of PJM, we are subject to the operations of PJM, and our generating facilities are under dispatch control of PJM. We transmit power to our member distribution cooperatives through the transmission facilities subject to PJM operational control. We have agreements with PJM which provide us with access to transmission facilities under PJM’s control as necessary to deliver energy to our member distribution cooperatives. We own a limited amount of transmission facilities. See “Properties—Transmission” in Item 2.

Transmission owners within PJM have made significant investments in their transmission systems. Because transmission rates are established to recover the cost of investment plus a return on the investment, rates for network transmission services have increased dramatically in recent years. We anticipate that our transmission costs will increase significantly in 2015.

PJM balances its participants’ power requirements with the power resources available to supply those requirements. Based on this evaluation of supply and demand, PJM schedules and dispatches available generating

 

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facilities throughout its region in a manner intended to meet the demand for energy in the most reliable and cost-effective manner. Thus PJM directs the dispatch of these facilities even though it does not own them. This can result in local baseload facilities being used less frequently than has historically been the case. For example, the dispatch of Clover has decreased in recent years due to the larger dispatch pool of PJM, the increase in the number of facilities utilizing natural gas, and the decrease in the cost of natural gas. When PJM cannot dispatch the most economical generating facilities due to transmission constraints, PJM will dispatch more expensive generating facilities to meet the required power requirements. PJM participants whose power requirements cause the redispatch are obligated to pay the additional costs to dispatch the more expensive generating facilities. These additional costs are commonly referred to as congestion costs. PJM conducts the auction of financial transmission rights for future periods to provide market participants an opportunity to hedge these congestion costs.

The PJM energy market consists of day-ahead and real-time markets. PJM’s day-ahead market is a forward market in which hourly locational marginal prices are calculated for the following day based on the prices at which the owners of generating facilities, including ODEC, offer to run their facilities to meet the requirements of energy customers. PJM’s real-time market is a spot market in which current locational marginal prices are calculated at five-minute intervals.

PJM rules require that load serving entities, such as ODEC, meet certain minimum capacity obligations. These obligations can be met through a combination of owned generation resources and purchases under bilateral agreements and from forward capacity auctions under PJM’s RPM. The purpose of PJM’s RPM is to develop a longer-term pricing program for capacity resources, to provide localized pricing for capacity, and to reduce the resulting investment risk to owners of generating resources, thus encouraging new investment in generating facilities. The value of capacity resources can vary by location and RPM provides for the recognition of the locational value. To date, PJM has conducted RPM auctions for capacity to be supplied through May 31, 2018. Each annual auction is held 36 months before each subsequent delivery year, and up to three incremental auctions may be held at prescribed dates after the base residual auction for each delivery year to adjust for capacity market changes.

As a result of the extreme weather experienced during January 2014, PJM implemented a number of changes to its energy market relative to scheduling and settlements. Additionally, PJM has proposed additional changes to both its energy market and RPM which are currently under consideration by FERC. If FERC approves any or all of these proposed changes, capacity and energy prices will likely increase beginning in 2015. We are actively participating in these filings and their outcome cannot currently be determined.

Power Purchase Contracts

We purchase significant amounts of power in the market from investor-owned utilities and power marketers through long-term and short-term physically-delivered forward power purchase contracts. We also purchase power in the spot energy market. This approach to meeting our member distribution cooperatives’ energy requirements is not without risks. See “Risk Factors” in Item 1A. below. To mitigate these risks, we attempt to match our energy purchases with our energy needs to reduce our spot market purchases of energy. Additionally, we utilize policies, procedures, and various hedging instruments to manage our power market risks. These policies and procedures, developed in consultation with ACES, are designed to strike an appropriate balance between minimizing costs and reducing energy cost volatility. See “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A.

Renewable

We have contracts with companies that own and operate wind and landfill gas facilities. These contracts allow us to buy output, including renewable energy credits, from the renewable facilities at a predetermined price. We sell these renewable energy credits to our member distribution cooperatives and non-members. We do not own or operate these facilities and are not responsible for their operational costs.

 

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Fuel Supply

Coal

Virginia Power, as operating agent of Clover, has the responsibility to procure sufficient coal for the operation of the facility. Virginia Power advises us that it uses both long-term contracts and short-term spot agreements to acquire the low sulfur bituminous coal used to fuel the facility. We are not a direct party to any of these procurement contracts and we do not control their terms or duration. As of December 31, 2014, and December 31, 2013, there was a 70 day and a 46 day supply of coal at Clover, respectively. We anticipate that sufficient supplies of coal will be available in the future to operate the facility when dispatched by PJM. See “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A.

Nuclear

Virginia Power, as operating agent of North Anna, has the sole authority and responsibility to procure nuclear fuel for the facility. Virginia Power advises us that it primarily uses long-term contracts to support North Anna’s nuclear fuel requirements and that worldwide market conditions are continuously evaluated to ensure a range of supply options at reasonable prices which are dependent upon the market environment. We are not a direct party to any of these procurement contracts and we do not control their terms or duration. Virginia Power advises us that current agreements, inventories, and spot market availability are expected to support North Anna’s current and planned fuel supply needs for the near term and that additional fuel is purchased as required to attempt to ensure optimal cost and inventory levels.

Under the Nuclear Waste Policy Act of 1982, the DOE is required to provide for the permanent disposal of spent nuclear fuel produced by nuclear facilities, such as North Anna, in accordance with contracts executed with the DOE. The DOE did not begin accepting spent fuel in 1998 as specified in its contract. As a result, Virginia Power sought reimbursement for certain spent nuclear fuel-related costs incurred and in 2012 signed a settlement agreement with the DOE. See Note 1 of the Notes to Consolidated Financial Statements.

Natural Gas

Our three combustion turbine facilities are fueled by natural gas and are located adjacent to natural gas transmission pipelines. We are responsible for procuring the natural gas to be used by all of our units at Louisa, Marsh Run, and Rock Springs. We have developed and utilize a natural gas supply strategy for providing natural gas to each of the three combustion turbine facilities. The strategy includes securing transportation contracts and incorporating the ability to use No. 2 distillate fuel oil as a backup fuel for Louisa and Marsh Run, as needed, to minimize natural gas pipeline transportation costs. We have identified our primary natural gas suppliers and have negotiated the contracts needed for procurement of physical natural gas. We have put in place strategies and mechanisms to financially hedge our natural gas needs. We anticipate that sufficient supplies of natural gas will be available in the future to support the operation of our combustion turbine facilities, as well as our proposed Wildcat Point facility, but significant price volatility may occur. See “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A.

 

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REGULATION

General

We are subject to regulation by FERC and, to a limited extent, state public service commissions. Some of our operations also are subject to regulation by the VDEQ, the Maryland Department of the Environment, the DOE, the NRC, and other federal, state, and local authorities. Compliance with future laws or regulations may increase our operating and capital costs by requiring, among other things, changes in the design or operation of our generating facilities.

Rate Regulation

We establish our rates for power furnished to our member distribution cooperatives pursuant to our formula rate, which has been accepted by FERC. The formula rate is intended to permit us to collect revenues, which, together with revenues from all other sources, are equal to all of our costs and expenses, plus a targeted amount equal to 20% of our total interest charges, plus additional equity contributions as approved by our board of directors. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting Results—Formula Rate” in Item 7.

On September 30, 2013, we filed with FERC to revise our cost-based formula rate to more closely align our cost recovery from our member distribution cooperatives with the methodologies used by PJM to allocate costs to us. On November 8, 2013, Bear Island, a customer of REC, filed a motion to intervene, protest, and request for hearing. On December 2, 2013, FERC issued its order accepting the proposed revisions for filing to become effective January 1, 2014, subject to refund, and establishing hearing and settlement procedures. A hearing was held in December 2014, and briefs were filed in January 2015. We are currently awaiting an initial decision.

FERC may review our rates upon its own initiative or upon complaint and order a reduction of any rates determined to be unjust, unreasonable, or otherwise unlawful and order a refund for amounts collected during such proceedings in excess of the just, reasonable, and lawful rates. Our charges to TEC are established under our market-based sales tariff filed with FERC.

Our rates and services are regulated by FERC. The VSCC, the DPSC, and the MPSC do not have jurisdiction over our rates, charges, and services.

Regulatory Proceedings Related to Wildcat Point

The development, construction, and operation of Wildcat Point are subject to obtainment of necessary governmental and regulatory approvals. See “Power Supply Resources—Wildcat Point” above.

Other Regulation

In addition to its jurisdiction over rates, FERC also regulates the issuance of securities and assumption of liabilities by us, as well as mergers, consolidations, the acquisition of securities of other utilities, and the disposition of property under FERC jurisdiction. Under FERC regulations, we are prohibited from selling, leasing, or otherwise disposing of the whole of our facilities subject to FERC jurisdiction, or any part of such facilities having a value in excess of $10.0 million without FERC approval. We are also required to seek FERC approval prior to merging or consolidating our facilities with those of any other entity having a value in excess of $10.0 million.

The VSCC, the DPSC, and the MPSC oversee the siting of our utility facilities in their respective jurisdictions.

 

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Environmental

We are subject to federal, state, and local laws and regulations, and permits designed to both protect human health and the environment and to regulate the emission, discharge, or release of pollutants into the environment. We believe we are in material compliance with all current requirements of such environmental laws and regulations and permits. However, as with all electric utilities, the operation of our generating units could be affected by future environmental regulations. Capital expenditures and increased operating costs required to comply with any future regulations could be significant. See “Risk Factors” in Item 1A. Our environmental related capital expenditures at our generating facilities were approximately $2.7 million in 2014 and 2013. Additionally, in 2014, we procured and capitalized $3.4 million of emission reduction credits related to the construction of Wildcat Point.

Clean Air Act (“CAA”)

Currently, the most important environmental law affecting our operations is the CAA. The CAA requires, among other things, that owners and operators of fossil fuel-fired power stations limit emissions of SO2, PM, Hg, and NOx. Additionally, regulatory programs are in place for new units and are being proposed for existing units to limit emissions of CO2 and other GHG. Discussed below are certain standards and regulations under the CAA.

We are impacted by the following regulations under the CAA:

 

    Clean Air Interstate Rule

 

    Cross-State Air Pollution Rule

 

    Acid Rain Program

 

    Mercury and Air Toxics Standards

 

    Reciprocating Internal Combustion Engine National Emissions Standards for Hazardous Air Pollutants

 

    National Ambient Air Quality Standards

 

    CO2 New Source Performance Standards for EGUs

 

    Clean Power Plan

 

    Greenhouse Gas Prevention of Significant Deterioration Permitting

Clean Air Interstate Rule (“CAIR”)

CAIR required significant reductions of SO2 and NOx in the eastern United States, including Virginia and Maryland. During 2014, our facilities were regulated under CAIR and we met the CAIR 2014 compliance obligations. CAIR remained in effect through December 31, 2014. Based upon the U.S. Supreme Court’s April 29, 2014, decision, the EPA terminated CAIR and implemented CSAPR on January 1, 2015, as discussed below.

Cross-State Air Pollution Rule (“CSAPR”)

The EPA proposed CSAPR, also known as the “Transport Rule,” requires 27 states and the District of Columbia to significantly improve air quality by reducing power plant SO2 and NOx emissions that contribute to ozone and fine particle pollution in other states. CSAPR was originally scheduled to go into effect in 2012, however numerous petitions by industry participants resulted in a successful motion for stay. In October 2014, the D.C. Circuit granted the EPA’s motion to lift the stay of CSAPR. Further, the D.C. Circuit granted the EPA’s request to shift the CSAPR compliance deadlines by three years, so that Phase 1 emissions budgets (which would have gone into effect in 2012 and 2013) will apply in 2015 and 2016, and Phase 2 emissions budgets will apply in 2017 and beyond. Future outcomes of any additional litigation and/or any action to issue a revised rule could affect the assessment regarding cost of compliance. Based upon published allocations/new source set asides for Virginia and Maryland, we anticipate that we will have to purchase a large number of NOx and a limited number of SO2 CSAPR allowances for Clover and the majority of projected emissions allowances when Wildcat Point commences operation. We will be monitoring the allowance markets to determine potential financial impacts.

 

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Wildcat Point can apply for set-aside new source NOX allowances from Maryland. The number of set-aside allowances available for Wildcat Point will depend on the number of new sources requesting the allowances. Wildcat Point will need to purchase allowances for any emissions that exceed the number of new source set-aside allowances received. Currently, there is an adequate supply of NOx allowances available for purchase for Wildcat Point.

Acid Rain Program

With respect to SO2, under the CAA’s Acid Rain Program, each of our fossil fuel-fired plants must have SO2 allowances equal to the number of tons of SO2 they emit into the atmosphere annually. The total number of SO2 allowances for all facilities is capped, and SO2 allowances issued to individual sources can be traded. As a facility that was built before the Acid Rain Program, Clover is included in the Acid Rain Program budget and receives an annual allocation of SO2 allowances at no cost based upon its baseline operations. Newer facilities, including Louisa, Marsh Run, Rock Springs, and Wildcat Point, need to obtain allowances under the Acid Rain Program; however, because they are primarily gas-fired generating facilities, the number of SO2 allowances they must obtain is typically minimal and can be supplied from any excess SO2 allowances allocated to Clover.

Mercury and Air Toxics Standards (“MATS”)

MATS will regulate mercury, acid gases, and other air toxic organic compounds from coal and oil-fired power plants. Coal and oil-fired power plants will need to meet maximum achievable control technology standards to control the pollutants regulated by MATS by April 16, 2015. We do not anticipate that any additional capital control measures will be required at Clover to comply with MATS due to Clover’s existing pollution control equipment, which removes greater than 90% of the mercury emitted from the facility.

Reciprocating Internal Combustion Engine National Emissions Standards for Hazardous Air Pollutants (“RICE”)

Under the RICE standards, compression ignition diesel engines used for emergency/black start power or for firewater pumping at the power stations will only have to maintain records of the hours of operation and document regular preventive maintenance. Our five distributed generation facilities that are operated at various remote substations have the capability to operate for peak shaving purposes in addition to supplying power during emergency situations. Based upon continuing this capability, we installed the required control equipment and monitoring systems prior to the May 3, 2013 compliance date.

National Ambient Air Quality Standards (“NAAQS”)

In May 2012, the EPA issued final designations for the 75 parts per billion ozone air quality standard. As part of the NAAQS, states will be required to develop and implement plans to address sources emitting pollutants which contribute to the formation of ozone. In November 2014, the EPA issued a new proposal to revise the ozone standard and expects to finalize the rule in October 2015. The EPA is not expected to complete attainment designations for a new standard until 2017 and states will have until 2020 to develop plans to address the new standard. The EPA is still developing the implementation guidance related to the NAAQS. We will continue to follow this rulemaking in order to determine potential impacts related to our existing or planned facilities.

CO2 New Source Performance Standards for EGUs

On January 8, 2014, the EPA proposed national standards for CO2 emissions from new fossil fuel-fired electric generating units under 111(b) of the CAA. The proposed standards would limit CO2 emissions from new fossil fuel-fired electric generating units to 1,000 pounds per MWh. The EPA has stated they intend to finalize 111(b) standards in the summer of 2015. We will continue to follow this rulemaking in order to determine potential impacts related to our planned facilities.

 

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CO2 Emissions Guidelines for Existing EGUs (“Clean Power Plan”)

On June 2, 2014, the EPA proposed emission guidelines for CO2 from existing electric utility generating units under 111(d) of the CAA. This proposal, referred to as the Clean Power Plan, requires that each state develop, submit, and implement a plan to achieve the interim and final state-specific goals detailed in the rulemaking. The EPA proposal has defined the following four areas of focus which the states are to utilize to meet the proposed goals:

 

    increase efficiency of existing fossil-fuel plants;

 

    increase dispatch of existing natural gas combined-cycle units;

 

    utilize and expand the use of zero-emitting generation (additional renewables and nuclear); and

 

    increase demand-side energy efficiency.

Public hearings on the CPP were held by the EPA on July 29 – August 1, 2014, and the EPA expects to finalize the rule in the summer of 2015. There are a number of legal challenges related to the CPP, including whether or not the EPA can finalize standards for existing plants under Section 111(d) until standards are finalized for new plants under Section 111(b) as discussed above. We will continue to follow this rulemaking in order to determine potential impacts related to our existing facilities.

Greenhouse Gas Prevention of Significant Deterioration Permitting

In 2010, the EPA issued the Tailoring Rule to address GHG emissions from stationary sources under the CAA permitting programs. The final rule set thresholds for GHG emissions that define when permits under the New Source Review Prevention of Significant Deterioration and Title V Operating Permit programs are required for new and existing industrial facilities. In late 2010, the EPA issued a series of rules that provide the necessary regulatory framework for permitting of both new and existing large stationary sources. Regulation of GHG emissions will affect the renewal of Title V Operating Permits for Clover, Louisa, Marsh Run, and Rock Springs, as the rules will require that existing facilities quantify and establish limits for GHGs emissions in their operating permits.

Regional Greenhouse Gas Initiative (“RGGI”)

RGGI provides for a cap and trade program to regulate CO2 emissions among certain northeastern and mid-Atlantic states, including Delaware and Maryland. Since Rock Springs is located in Maryland, we are required to purchase RGGI CO2 emissions allowances for each ton of CO2 emitted by our Rock Springs units. Additionally, Wildcat Point will be required to purchase RGGI CO2 emissions allowances for each ton of CO2 emitted once operational. The regulations require all allowances to be auctioned rather than allocated directly to utilities. There is currently an adequate quantity of CO2 allowances available for purchase to support Rock Springs and Wildcat Point.

Wildcat Point Emission Reduction Credits

Because Wildcat Point is located in an ozone nonattainment area, the permitting process requires us to provide NOx and volatile organic compound emissions offsets for the project. Additionally, because the water intake emergency generator will be located in a nonattainment area, we are required to provide emissions offsets for this source as well. We procured all necessary emission reduction credits from approved sources in Pennsylvania and Maryland to provide the needed offsets for Wildcat Point prior to the start of construction.

 

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Clean Water Act

The Clean Water Act and applicable state laws regulate water intake structures, discharges of cooling water, storm water run-off, and other wastewater discharges at our generating facilities. Our permits are subject to periodic review and renewal proceedings, and can be made more restrictive over time. Limitations on the thermal discharges in cooling water, or withdrawal of cooling water during low flow conditions, can restrict our operations. On June 7, 2013, the EPA proposed revising limits on certain toxic pollutants that would require most steam electric (including coal and combined cycle, natural gas) facilities to strengthen existing or implement new controls to water discharges from their sites. We will continue to follow this rulemaking in order to determine potential impacts related to our facilities.

Resource Conservation Recovery Act (“RCRA”)

The EPA regulates CCRs under the RCRA to address the risks from disposal of CCRs generated by coal combustion at electric generating facilities. On December 19, 2014, the EPA signed the “Disposal of Coal Combustion Residuals for Electric Utilities” which addresses the risks for coal ash disposal – leaking of contaminants into groundwater, blowing of contaminants into the air as dust, and the catastrophic failure of coal ash surface impoundments. The final rule establishes technical requirements for CCR landfills and surface impoundments.

Renewable Portfolio Standards

We are not subject to any RPS; however, beginning in 2013, DEC became subject to RPS in Delaware.

Future Regulation

New legislative and regulatory proposals are frequently introduced on both the federal level and state level that would modify the environmental regulatory programs applicable to our facilities. Changing regulatory requirements can increase our capital and operating costs, and adversely affect the ability to operate our existing facilities, as well as restrict construction of new facilities.

 

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ITEM 1A. – RISK FACTORS

RISK FACTORS

The following risk factors and all other information contained in this report should be considered carefully when evaluating ODEC. These risk factors could affect our actual results and cause these results to differ materially from those expressed in any forward-looking statements of ODEC. Other risks and uncertainties, in addition to those that are described below, may also impair our business operations. We consider the risks listed below to be material, but you may view risks differently than we do and we may omit a risk that we consider immaterial but you consider important. An adverse outcome of any of the following risks could materially affect our business or financial condition. These risk factors should be read in conjunction with the other detailed information set forth elsewhere in this report, including “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7, including “Caution Regarding Forward-looking Statements”, and the notes to Consolidated Financial Statements.

We rely substantially on purchases of energy from other power suppliers which exposes us to market price risk.

We supply our member distribution cooperatives with all of their power (energy and demand) requirements, with limited exceptions. Our costs to provide this energy and demand are passed through to our member distribution cooperatives under our wholesale power contracts. We obtain the power to serve their requirements from generating facilities in which we have an interest and purchases of power from other power suppliers.

Historically, our power supply strategy has relied substantially on purchases of energy from other power suppliers. In 2014, we purchased approximately 59.8% of our energy resources. These purchases consisted of a combination of purchases under physically-delivered forward contracts and purchases of energy in the spot market. Our reliance on purchases of energy from other suppliers will continue into the future and likely will increase until the anticipated commercial operation of Wildcat Point in mid-2017, as our member distribution cooperatives’ requirements for power increase. Our reliance on energy purchases could also increase because the operation of our generating facilities is subject to many risks, including the shutdown of our facilities, or breakdown or failure of equipment.

Purchasing power helps us mitigate high fixed costs related to the ownership of generating facilities but exposes us to significant market price risk because energy prices can fluctuate substantially. When we enter into long-term power purchase contracts or agree to purchase energy at a date in the future, we utilize our judgment and assumptions in our models. These judgments and assumptions relate to factors such as future demand for power and market prices of energy and the price of commodities, such as natural gas, used to generate electricity. Our models cannot predict what will actually occur and our results may vary from what our models predict, which may in turn impact our resulting costs to our members. Our models become less reliable the further into the future that the estimates are made. Although we have developed strategies to attempt to meet our power requirements in an economical manner and we have implemented a hedging strategy to limit our exposure to variability in the market, we still may purchase energy at a price which is higher than other utilities’ costs of generating energy or future market prices of energy. For further discussion of our market price risk, see “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A.

Changes in fuel and purchased power costs could increase our operating costs.

We are subject to changes in fuel costs, which could increase the cost of generating power, as well as changes in purchased power costs. Increases in fuel costs and purchased power costs increase the cost to our member distribution cooperatives. The market prices for fuel may fluctuate over relatively short periods of time. Factors that could influence fuel and purchased power costs are:

 

    Weather;

 

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    Supply and demand;

 

    The availability of competitively priced alternative energy sources;

 

    The transportation of fuels;

 

    Price competition among fuels used to produce electricity, including natural gas, coal, and oil;

 

    Energy transmission or natural gas transportation capacity constraints;

 

    Impact of implementation of new technologies in the power industry;

 

    Federal, state, and local energy and environmental regulation and legislation; including increased regulation of the extraction of natural gas and coal; and

 

    Natural disasters, war, terrorism, and other catastrophic events.

Environmental regulation may limit our operations or increase our costs or both.

We are required to comply with numerous federal, state, and local laws and regulations relating to the protection of the environment. We believe that we have obtained all material environmental-related approvals currently required to own and operate our existing facilities or that necessary approvals have been applied for and will be issued in a timely manner. We may incur significant additional costs because of compliance with these requirements. Failure to comply with environmental laws and regulations could have a material effect on us, including potential civil or criminal liability and the imposition of fines or expenditures of funds to bring our facilities into compliance. Delay in obtaining, or failure to obtain and maintain in effect, any environmental approvals, or the delay or failure to satisfy any applicable environmental regulatory requirements related to the operation of our existing facilities or the sale of energy from these facilities could result in significant additional cost to us.

We cannot predict the cost or the effect of any future legislation or regulation. New laws or regulations, the revision or reinterpretation of existing laws or regulations, or penalties imposed for non-compliance with existing laws or regulations may require us to incur additional expenses and could have a material adverse effect on the cost of power we supply our member distribution cooperatives. See “Regulation—Environmental” in Item 1.

Our financial condition is largely dependent upon our member distribution cooperatives.

Our financial condition is largely dependent upon our member distribution cooperatives satisfying their obligations under the wholesale power contract that each has executed with us. The wholesale power contracts require our member distribution cooperatives to pay us for power furnished to them in accordance with our FERC formula rate. Our board of directors, which is composed of representatives of our members, can approve changes in the rates we charge to our member distribution cooperatives without seeking FERC approval, with limited exceptions. In 2014, 65.1% of our revenues from sales to our member distribution cooperatives were received from our three largest members, REC, SVEC, and DEC.

Our member distribution cooperatives’ ability to collect their costs from their members may have an impact on our financial condition. Economic conditions may make it difficult for some customers of our member distribution cooperatives to pay their power bills in a timely manner, which could ultimately affect the timeliness of our member distribution cooperatives’ payments to us.

 

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We are subject to risks associated with owning an interest in a nuclear generating facility.

We have an 11.6% undivided ownership interest in North Anna which provided approximately 13.8% of our energy requirements in 2014. Ownership of an interest in a nuclear generating facility involves risks, including:

 

    potential liabilities relating to harmful effects on the environment and human health resulting from the operation of the facility and the storage, handling, and disposal of radioactive materials;

 

    significant capital expenditures relating to maintenance, operation, and repair of the facility, including repairs required by the NRC;

 

    limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with operation of the facility; and

 

    uncertainties regarding the technological and financial aspects of decommissioning a nuclear plant at the end of its licensed life.

The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of North Anna. If the facility is not in compliance, the NRC may impose fines or shut down the units until compliance is achieved, or both depending upon its assessment of the situation. Revised safety requirements issued by the NRC have, in the past, necessitated substantial capital expenditures at other nuclear generating facilities. North Anna’s operating and safety procedures may be subject to additional federal or state regulatory scrutiny as a result of world-wide events related to nuclear facilities. In addition, if a serious nuclear incident at North Anna did occur, it could have a material but presently undeterminable adverse effect on our operations or financial condition. Further, any unexpected shut down at North Anna as a result of regulatory non-compliance or unexpected maintenance will require us to purchase replacement energy.

We may not complete generating facility construction or expansion projects that we commence, or we may complete such projects on materially different terms or timing than initially anticipated and we may not be able to achieve the intended benefits of any such projects, if completed.

We are currently in the process of constructing a new combined cycle generating facility, Wildcat Point, which will result in significant capital expenditures in the future. Construction and expansion projects, such as investments in generation assets, carry with them the risk that decisions made today can have implications well into the future. Failure to anticipate market, technology, and regulatory risks regarding particular capital assets can impact their cost to operate and value in the future. We anticipate that we will need to seek additional financing in the future to fund these construction and expansion projects and we may not be able to secure such financing on favorable terms. Construction carries with it risks relating to timely completion and operational effectiveness. We may not be able to complete the construction or expansion projects on time or at all as a result of weather conditions, delays in obtaining or failure to obtain regulatory approvals, delays in obtaining key materials, labor difficulties, other construction delays, difficulties with partners or potential partners or other factors beyond our control. Even if the construction and expansion projects are completed, the total costs of the construction and expansion projects may be higher than anticipated and the performance of our business following the construction and expansion projects may not meet expectations. Further, we may not be able to timely and effectively integrate the construction and expansion projects into our operations, or the integration may result in unforeseen operating difficulties or unanticipated costs. Any of these or other factors could adversely affect our ability to realize the anticipated benefits from construction and expansion projects.

Failure of an investment in a lease of our interest in Clover Unit 1 could reduce investment income currently used to fund the majority of our rental payment obligations and fixed purchase price.

In conjunction with our 1996 lease and subsequent leaseback of our interest in Clover Unit 1, we purchased an investment that provides for a substantial portion of our periodic rent payments under the leaseback and the fixed

 

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purchase price of our interest in Unit 1 at the end of the term of the leaseback, if we exercise our option to purchase the interest at that time. The investment, which had a balance of $308.5 million at December 31, 2014, was issued by Rabobank, which has senior debt obligations which are currently rated “A+” by S&P and “Aa2” by Moody’s. If Rabobank fails to make disbursements from the investment, we remain liable for all rental payments under the leaseback and the fixed purchase price if we choose to exercise that option. At December 31, 2014, the total balance of our remaining lease obligation was $342.8 million. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Significant Contingent Obligations—Clover Lease” in Item 7.

Counterparties under power purchase arrangements may fail to perform their obligations to us.

Because we rely substantially on the purchase of energy from other power suppliers, we are exposed to the risk that counterparties will default in performance of their obligations to us. On an on-going basis we analyze and monitor the default risks of counterparties and other credit issues related to these purchases, and we may require our counterparties to post collateral with us; however, defaults may still occur. Defaults may take the form of failure to physically deliver the purchased energy. If a default occurs, we may be forced to enter into alternative contractual arrangements or purchase energy in the forward or spot markets at then-current market prices that may exceed the prices previously agreed upon with the defaulting counterparty.

The use of hedging instruments could impact our liquidity.

We use various hedging instruments, including forwards, futures, financial transmission rights, and options, to manage our power market price risks. These hedging instruments generally include collateral requirements that require us to deposit funds or post letters of credit with counterparties when a counterparty’s credit exposure to us is in excess of agreed upon credit limits. When commodity prices decrease to levels below the levels where we have hedged future costs, we may be required to use a material portion of our cash or liquidity facilities to cover these collateral requirements. Additionally, existing or new regulations related to the use of hedging instruments may impact our access to and use of hedging instruments.

Adverse changes in our credit ratings could negatively impact our liquidity and our ability to access capital, and may require us to provide credit support for some of our obligations.

S&P, Moody’s, and Fitch Ratings, Inc., currently rate our outstanding obligations issued under our Indenture at “A,” “A2,” and “A,” respectively. Additionally, we have an issuer credit rating of “A” from S&P, and an implied senior unsecured rating of “A” from Fitch Ratings, Inc. If these agencies were to downgrade our ratings, particularly below investment grade, we may be required to deposit funds or post letters of credit related to our power purchase arrangements, which may reduce our available liquidity and impact our access to future liquidity resources. Also, we may be required to pay higher interest rates on financings which we may need to undertake in the future, and our potential pool of investors and funding sources could decrease. In addition, in limited circumstances, we have obligations to provide credit support if our obligations issued under the Indenture are rated below specified thresholds by S&P and Moody’s. These circumstances relate to the lease and leaseback of our undivided interest in Clover Unit 1 and some of our power purchase contracts. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Significant Contingent Obligations” in Item 7. To the extent that we would have to provide additional credit support as a result of a downgrade in our credit ratings, our ability to access additional credit may be limited and our liquidity may be materially impaired.

Failure to comply with regulatory reliability standards, and other regulatory requirements could subject us to substantial monetary penalties.

As a result of EPAct of 2005, owners, operators, and users of bulk electric systems, including ODEC, are subject to mandatory reliability standards enacted by NERC and its regional entities, and enforced by FERC. We must follow these standards, which are in place to require that proper functions are performed to ensure the

 

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reliability of the bulk power system. Although the standards are developed by the NERC Standards Committee, which includes representatives of various electric energy sectors, and must be just and reasonable, the standards are legally binding and compliance may require increased capital expenditures and costs to provide electricity to our member distribution cooperatives under our wholesale power contracts. If we are found to be in non-compliance with any mandatory reliability standards we could be subject to sanctions, including potentially substantial monetary penalties. New, revised or reinterpreted laws or regulations related to reliability standards and/or participation in wholesale power markets could also result in substantial monetary penalties if ODEC is found to have violated or failed to comply with applicable standards, laws and regulations.

Poor market performance will affect the asset values in our nuclear decommissioning trust and our defined benefit retirement plans, which may increase our costs.

We are required to maintain a funded trust to satisfy our future obligation to decommission the North Anna facility. A decline in the market value of those assets due to poor investment performance or other factors may increase our funding requirements for these obligations which may increase our costs.

We participate in the NRECA Retirement Security Plan and its pension restoration plan. The cost of these plans is funded by our payments to NRECA. Poor performance of investments in these benefit plans may increase our costs to make up our allocable portion of any underfunding.

War, acts and threats of terrorism, sabotage, cyber security breach, natural disaster, and other significant events could adversely affect our operations.

We cannot predict the impact that any future terrorist attacks, sabotage, or natural disaster may have on the energy industry in general, or on our business in particular. Infrastructure facilities, such as electric generation, transmission, and distribution facilities, and RTOs, could be direct targets of, or indirect casualties of, an act of terror, sabotage, or cyber security breach. The physical or cyber security compromise of our facilities could adversely affect our ability to operate or manage our facilities effectively. Additionally, any retaliatory military strikes or sustained military campaign may affect the operation of our facilities in unpredictable ways, such as changes in financial markets, and disruptions of fuel supplies and energy markets. We also use third-party vendors to electronically process certain of our business transactions. Information systems, both ours and those of third-party information processors, are vulnerable to cyber security breach. Cyber security incidents could impact the ability to operate our generation and transmission assets, delay the development and construction of new facilities or capital improvement projects to existing facilities, and result in unauthorized disclosure of personal information regarding employees and their dependents, contractors, and other individuals. We have programs and procedures in place to safeguard our operating systems. Instability in financial markets as a result of terrorism, war, sabotage, natural disasters, pandemic, credit crises, recession, or other factors could result in a significant decline in the U.S. economy, and the increased cost of financing and insurance coverage, which could negatively impact our results of operations and financial condition.

Potential changes in accounting practices may adversely affect our financial results.

We cannot predict the impact that future changes in accounting standards or practices may have on public companies in general, the energy industry, or our operations specifically. New accounting standards could be issued that could change the way we record revenues, expenses, assets, and liabilities. These changes in accounting standards could adversely affect our reported earnings or could increase reported liabilities.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None

 

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ITEM 2. PROPERTIES

Our principal properties consist of our interest in five electric generating facilities, additional distributed generation facilities across our member distribution cooperatives’ service territories and a limited amount of transmission facilities. Substantially all of our physical properties are subject to the lien of our Indenture. Our generating facilities consist of the following:

 

Generating Facility

  Ownership
Interest
   

Location

 

Primary

Fuel

 

Commercial

Operation Date

  Net Capacity
Entitlement(1)
 

Clover

    50.0 %(2)    Halifax County, Virginia   Coal  

Unit 1 – 10/1995

Unit 2 – 03/1996

   

 

219 MW

218 MW

  

  

         

 

 

 
  437 MW   

North Anna

  11.6 Louisa County, Virginia Nuclear

Unit 1 – 06/1978(3)

Unit 2 – 12/1980(3)

 

 

110 MW

110 MW

  

  

         

 

 

 
  220 MW   

Louisa

  100.0 Louisa County, Virginia

Natural

Gas(4)

Unit 1 – 06/2003

Unit 2 – 06/2003

Unit 3 – 06/2003

Unit 4 – 06/2003

Unit 5 – 06/2003

 

 

 

 

 

84 MW

84 MW

84 MW

84 MW

168 MW

  

  

  

  

  

         

 

 

 
  504 MW   

Marsh Run

  100.0 Fauquier County, Virginia

Natural

Gas(4)

Unit 1 – 09/2004

Unit 2 – 09/2004

Unit 3 – 09/2004

 

 

 

168 MW

168 MW

168 MW

  

  

  

         

 

 

 
  504 MW   

Rock Springs

  50.0 %(5)  Cecil County, Maryland

Natural

Gas

Unit 1 – 06/2003

Unit 2 – 06/2003

 

 

168 MW

168 MW

  

  

         

 

 

 
  336 MW   

Distributed Generation

  100.0 Multiple Diesel 10 units – 07/2002   20 MW   
         

 

 

 
Total   2,021 MW   
         

 

 

 

 

(1)  Represents an approximation of our entitlement to the maximum dependable capacity for Clover and North Anna, which does not represent actual usage. Represents a nominal average of summer and winter capacities for Louisa, Marsh Run, and Rock Springs.
(2) Our interest in Clover Unit 1 is subject to a long-term lease. See “Clover—Clover Lease” below.
(3)  We purchased our 11.6% undivided ownership interest in North Anna in December 1983.
(4)  The units at this facility also operate on No. 2 distillate fuel oil.
(5) We own 100.0% of two units, each with a net capacity rating of 168 MW, and 50.0% of the common facilities for the facility. See “Combustion Turbine Facilities—Rock Springs” below.

Clover

Virginia Power, the co-owner of Clover, is responsible for operating Clover and procuring and arranging for the transportation of the fuel required to operate Clover. See “Business—Power Supply Resources—Fuel Supply—Coal” in Item 1. ODEC and Virginia Power are each entitled to half of the power generated by Clover. Additionally, we have contractual arrangements with Virginia Power under which we purchase reserve capacity for Clover and have the option to purchase reserve energy. We are responsible for and must fund half of all additions and operating costs associated with Clover, as well as half of Virginia Power’s administrative and general expenses directly attributable to Clover.

 

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Clover Lease

In 1996, we entered into a lease with an owner trust for the benefit of an investor in which we leased our interest in Clover Unit 1 and related common facilities, subject to the lien of the Indenture, for a term extendable by the owner trust up to the full productive life of Clover Unit 1, and simultaneously entered into an approximately 21.8 year leaseback of the interest. The interest of the owner trust in Clover Unit 1 is subject and subordinate to the lien of the Indenture. The lease contains events of default, which, if they occur, could result in termination of the lease, and, consequently, our loss of possession and right to the output of Clover Unit 1. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Significant Contingent Obligations—Clover Lease” in Item 7 for a discussion of our options and obligations at the end of the term of the leaseback of Clover Unit 1 and sources of funding for these obligations.

North Anna

The NRC has granted operating licenses for North Anna Unit 1 and Unit 2 that extend through April 1, 2038 and August 21, 2040, respectively. Virginia Power, the co-owner of North Anna, is responsible for operating North Anna. Virginia Power also has the authority and responsibility to procure nuclear fuel for North Anna. See “Business—Power Supply Resources—Fuel Supply—Nuclear” in Item 1. We are entitled to 11.6% of the power generated by North Anna. Additionally, we have contractual arrangements with Virginia Power under which we purchase reserve capacity for North Anna and have the option to purchase reserve energy. We are responsible for and must fund 11.6% of all post-acquisition date additions and operating costs associated with North Anna, as well as a pro-rata portion of Virginia Power’s administrative and general expenses directly attributable to North Anna. In addition, we separately fund our pro-rata portion of the decommissioning costs of North Anna. ODEC and Virginia Power also bear pro-rata any liability arising from ownership of North Anna, except for liabilities resulting from the gross negligence of the other.

Combustion Turbine Facilities

Louisa

We are responsible for the operation and maintenance of Louisa and we supply all services, goods, and materials required to operate and maintain the facility, including arranging for the transportation and supply of the natural gas and No. 2 distillate fuel oil required by the facility.

Marsh Run

We are also responsible for the operation and maintenance of Marsh Run and we supply all services, goods, and materials required to operate and maintain the facility, including arrangement for the transportation and supply of the natural gas and No. 2 distillate fuel oil required by the facility.

Rock Springs

ODEC and EP each individually own two units (a total of 336 MWs each) and 50.0% of the common facilities at Rock Springs. Additionally, ODEC and EP each individually bid its respective units into PJM as determined to be necessary and prudent.

Rock Springs is currently operated and maintained by Essential Power Operating Co., LLC, an affiliate of EP, pursuant to a service agreement under which Essential Power Operating Co., LLC, supplies all services, goods, and materials, other than natural gas, required to operate the facility. We are responsible for all costs associated with the development, construction, additions, and operating costs and administrative and general expenses relating to our two units and the proportional share of the costs relating to the common facilities for Rock Springs.

 

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We arrange for the transportation and supply of the natural gas required by the operator for our units at Rock Springs.

Distributed Generation Facilities

We have distributed generation facilities in our member distribution cooperatives’ service territories primarily to enhance our system’s reliability. Four diesel generators service our member distribution cooperatives in the Virginia mainland territory and six diesel generators service our member distribution cooperatives in the Delmarva Peninsula territory. We are currently installing additional diesel generators, totaling 5 MW, in the Virginia mainland territory and we anticipate commercial operation of the additional generators beginning in mid-2015.

Transmission

We own approximately 100 miles of transmission lines on the Virginia portion of the Delmarva Peninsula. We also own two 1,100 foot 500 kV transmission lines and a 500 kV substation at Rock Springs jointly with EP. As a transmission owner in PJM, we have relinquished dispatch control of all of these transmission facilities to PJM and contracted with third parties to operate and maintain them.

In 2013, we commenced construction of 14.5 miles of new 69 kV transmission line and a rebuild of 14.5 miles of existing 69 kV line on the Delmarva Peninsula. We anticipate that construction of the new line will be completed in the second quarter of 2015 and the rebuilt line will be completed in the second quarter of 2016. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Capital Expenditures” in Item 7.

Wildcat Point

We are currently constructing, and will be the sole owner of, an approximate 1,000 MW natural gas-fueled generation facility, named Wildcat Point, in Cecil County, Maryland. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview—Wildcat Point” in Item 7.

Indenture

The Indenture grants a lien on substantially all of our real property and tangible personal property and some of our intangible personal property in favor of the trustee, with limited exceptions. The obligations outstanding under the Indenture, including all of our long-term indebtedness, are secured equally and ratably by the trust estate under the Indenture.

ITEM 3. LEGAL PROCEEDINGS

FERC Proceeding Related to Formula Rate

On September 30, 2013, we filed with FERC to revise our cost-based formula rate to more closely align our cost recovery from our member distribution cooperatives with the methodologies used by PJM to allocate costs to us. On November 8, 2013, Bear Island, a customer of REC, filed a motion to intervene, protest, and request for hearing. On December 2, 2013, FERC issued its order accepting the proposed revisions for filing to become effective January 1, 2014, subject to refund, and establishing hearing and settlement procedures. A hearing was held in December 2014, and briefs were filed in January 2015. We are currently awaiting an initial decision.

 

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Other

Other than the issues discussed above and certain other legal proceedings arising out of the ordinary course of business that management believes will not have a material adverse impact on our results of operations or financial condition, there is no other litigation pending or threatened against us.

ITEM 4. MINE SAFETY DISCLOSURES

Not Applicable

 

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY,

RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Not Applicable

ITEM 6. SELECTED FINANCIAL DATA

The selected financial data below present selected historical information relating to our financial condition and results of operations. The financial data for the five years ended December 31, 2014, is derived from our audited consolidated financial statements. You should read the information contained in this table together with our consolidated financial statements, the related notes to the consolidated financial statements, and the discussion of this information in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7.

 

     Year Ended December 31,  
     2014      2013      2012      2011      2010  
     (in thousands, except ratios)  

Statement of Operations Data

              

Operating Revenues

   $ 951,576       $ 842,069       $ 842,681       $ 891,539       $ 844,470   

Operating Margin

     50,525         52,590         59,145         62,590         53,671   

Net Margin attributable to ODEC (1)

     9,100         9,573         9,939         10,807         10,158   

Margins for Interest Ratio

     1.21         1.21         1.21         1.22         1.23   

 

     December 31,  
     2014     2013     2012     2011     2010  
     (in thousands, except ratios)  

Balance Sheet Data

          

Net Electric Plant

   $ 1,097,669      $ 965,378      $ 991,340      $ 1,012,905      $ 1,037,404   

Total Investments

     252,062        255,984        263,024        235,199        196,597   

Other Assets

     289,011        309,235        289,157        325,876        278,434   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Assets

$ 1,638,742    $ 1,530,597    $ 1,543,521    $ 1,573,980    $ 1,512,435   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Patronage capital

$ 379,097    $ 369,997    $ 360,424    $ 350,485    $ 339,678   

Non-controlling interest

  5,687      5,691      13,257      13,093      13,166   

Long-term debt

  721,038      749,330      737,836      766,128      449,798   

Revolving credit facilities

  86,000      —        —        —        7,043   

Long-term debt due within one year (2)

  28,292      28,292      28,292      28,292      238,917   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Capitalization and Short-term Debt

$ 1,220,114    $ 1,153,310    $ 1,139,809    $ 1,157,998    $ 1,048,602   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Equity Ratio (3)

  31.2   32.2   32.0   30.6   32.8

 

(1) For 2010, net margin attributable to ODEC includes an additional equity contribution of $1.3 million.
(2)  For 2010, long-term debt due within one year includes our $215.0 million 2001 Series A Bonds which were repaid on June 1, 2011.
(3)  Equity ratio equals patronage capital divided by the sum of our long-term debt, revolving credit facilities, long-term debt due within one year, and patronage capital.

 

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Our Indenture obligates us to establish and collect rates for service to our member distribution cooperatives, which are reasonably expected to yield a margin for interest ratio for each fiscal year equal to at least 1.10, subject to any necessary regulatory or judicial approvals. The Indenture requires that these amounts, together with other moneys available to us, provide us moneys sufficient to remain in compliance with our obligations under the Indenture. We calculate the margins for interest ratio by dividing our margins for interest by our interest charges.

Margins for interest under the Indenture equal:

 

    our net margins;

 

    plus revenues that are subject to refund at a later date which were deducted in the determination of net margins;

 

    plus non-recurring charges that may have been deducted in determining net margins;

 

    plus total interest charges (calculated as described below);

 

    plus income tax accruals imposed on income after deduction of total interest for the applicable period.

In calculating margins for interest under the Indenture, we factor in any item of net margin, loss, income, gain, earnings or profits of any of our affiliates or subsidiaries, only if we have received those amounts as a dividend or other distribution from the affiliate or subsidiary or if we have made a contribution to, or payment under a guarantee or like agreement for an obligation of, the affiliate or subsidiary. Any amounts that we are required to refund in subsequent years do not reduce margins for interest as calculated under the Indenture for the year the refund is paid.

Interest charges under the Indenture equal our total interest charges (other than capitalized interest) related to (1) all obligations under the Indenture, (2) indebtedness secured by a lien equal or prior to the lien of the Indenture, and (3) obligations secured by liens created or assumed in connection with a tax-exempt financing for the acquisition or construction of property used by us, in each case including amortization of debt discount and expense or premium.

 

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

Caution Regarding Forward-looking Statements

Management’s Discussion and Analysis of Financial Condition and Results of Operations contains forward-looking statements regarding matters that could have an impact on our business, financial condition, and future operations. These statements, based on our expectations and estimates, are not guarantees of future performance and are subject to risks, uncertainties, and other factors. These risks, uncertainties, and other factors include, but are not limited to, general business conditions, demand for energy, federal and state legislative and regulatory actions and legal and administrative proceedings, changes in and compliance with environmental laws and policies, general credit and capital market conditions, weather conditions, the cost of commodities used in our industry, and unanticipated changes in operating expenses and capital expenditures. Our actual results may vary materially from those discussed in the forward-looking statements as a result of these and other factors. Any forward-looking statement speaks only as of the date on which the statement is made, and we undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which the statement is made even if new information becomes available or other events occur in the future.

Basis of Presentation

The accompanying financial statements reflect the consolidated accounts of ODEC and TEC. See “Note 1—Summary of Significant Accounting Policies in the Notes to the Consolidated Financial Statements” in Item 8.

Overview

We are a not-for-profit power supply cooperative owned entirely by our eleven Class A member distribution cooperatives and a Class B member, TEC. We supply our member distribution cooperatives’ energy and demand requirements through a portfolio of resources including generating facilities, long-term and short-term physically-delivered forward power purchase contracts, and spot market energy purchases. We also supply the transmission services necessary to deliver this power to our member distribution cooperatives.

Our results for the year ended December 31, 2014, were still significantly impacted by the extremely cold weather experienced by the entire mid-Atlantic region during the first quarter of 2014, which increased energy sales and fuel and purchased power expense, and changed our deferred energy balance from an over-collection to an under-collection. Our average energy cost increased 13.0%, primarily driven by a $79.9 million increase in fuel expense and a $55.7 million increase in purchased power expense. The increase in fuel expense was primarily impacted by a 49.0% increase in the dispatch of our combustion turbine facilities as well as a 164.6% increase in the average cost of fuel for these facilities. The increase in purchased power expense was primarily driven by an 11.0% increase in the average cost of purchased energy. For the year ended December 31, 2014, we under-collected energy costs from our member distribution cooperatives by $57.1 million. Any over-or under-collection of energy costs is recorded as deferred energy expense. As a result, our deferred energy balance, which represents the cumulative difference between energy revenues and energy expenses, changed from an over-collection of $37.2 million at December 31, 2013, to an under-collection of $19.9 million at December 31, 2014. To address the under-collection of energy costs, we increased our total energy rate 11.8% effective April 1, 2014, and an additional 2.4% effective October 1, 2014. For further discussion on deferred energy, see “Critical Accounting Policies—Deferred Energy” below.

Wildcat Point

We are currently constructing, and will be the sole owner of, an approximate 1,000 MW natural gas-fueled generation facility, named Wildcat Point, in Cecil County, Maryland. The development, construction, and operation of Wildcat Point are subject to obtainment of necessary governmental and regulatory approvals. On April 8, 2014, we received a Final Order granting approval of the CPCN from the MPSC. On June 2, 2014, we selected White Oak

 

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Power Constructors as the EPC contractor. Site preparation and engineering activities are in process, and permanent construction began in January 2015. The facility is scheduled to become operational in mid-2017. We currently have a ground lease related to the land associated with Wildcat Point and are currently accounting for it as an operating lease. Once Wildcat Point becomes operational, the lease will be reevaluated and likely will become a capital lease. We currently anticipate that the project cost will be approximately $790.5 million, including capitalized interest, but excluding the lease. To fund a portion of the project cost, on January 15, 2015, we issued $332.0 million of first mortgage bonds in a private placement transaction. See “Liquidity and Capital Resources—Sources—Financings” below.

Wildcat Point will consist of two combustion turbines, two heat recovery steam generators and one steam turbine generator. Mitsubishi will supply the combustion turbines. Alstom will supply the heat recovery steam generators and the steam turbine generator. Beginning in June 2014, following the approval of the CPCN and our selection of the EPC contractor, we began capitalizing all construction-related costs related to Wildcat Point. Through December 31, 2014, we capitalized construction costs related to Wildcat Point totaling $115.8 million, which are recorded in construction work in progress. In January 2015, we began capitalizing interest with respect to the facility upon commencement of permanent construction. For 2014 and 2013, we expensed $4.5 million and $7.7 million, respectively, of non-capital costs related to Wildcat Point, which are recorded in administrative and general expense.

Formula Rate

On September 30, 2013, we filed with FERC to revise our cost-based formula rate to more closely align our cost recovery from our member distribution cooperatives with the methodologies used by PJM to allocate costs to us. On November 8, 2013, Bear Island, a customer of REC, filed a motion to intervene, protest, and request for hearing. On December 2, 2013, FERC issued its order accepting the proposed revisions for filing to become effective January 1, 2014, subject to refund, and establishing hearing and settlement procedures. A hearing was held in December 2014, and briefs were filed in January 2015. We are currently awaiting an initial decision. See “Factors Affecting Results—Formula Rate” below.

Critical Accounting Policies

The preparation of our financial statements in conformity with generally accepted accounting principles requires that our management make estimates and assumptions that affect the amounts reported in our financial statements. We base these estimates and assumptions on information available as of the date of the financial statements and they are not necessarily indicative of the results to be expected for the year. We consider the following accounting policies to be critical accounting policies due to the estimation involved in each.

Accounting for Regulated Operations

We are a rate-regulated entity and, as a result, are subject to the accounting requirements of Accounting for Regulated Operations. In accordance with Accounting for Regulated Operations, certain of our revenues and expenses can be deferred at the discretion of our board of directors, which has budgetary and rate setting authority, if it is probable that these amounts will be recovered or returned through our formula rate in future periods. Regulatory assets on our Consolidated Balance Sheet represent costs that we expect to recover from our member distribution cooperatives based on rates approved by our board of directors in accordance with our formula rate. Regulatory liabilities on our Consolidated Balance Sheet represent probable future reductions in our revenues associated with amounts that we expect to return to our member distribution cooperatives based on rates approved by our board of directors in accordance with our formula rate. See “Factors Affecting Results—Formula Rate” below. Regulatory assets are generally included in deferred charges and regulatory liabilities are generally included in deferred credits and other liabilities. Deferred energy, which can be either a regulatory asset or regulatory liability, is included in current assets or current liabilities, respectively, on our Consolidated Balance Sheet. We recognize regulatory assets and liabilities as expenses or as a reduction in expenses, respectively, concurrent with their recovery through rates.

 

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Deferred Energy

In accordance with Accounting for Regulated Operations, we use the deferral method of accounting to recognize differences between our energy expenses and our energy revenues collected from our member distribution cooperatives. Deferred energy on our Consolidated Statements of Revenues, Expenses, and Patronage Capital represents the difference between energy revenues, which are based upon energy rates approved by our board, and energy expenses, which are based upon actual energy costs incurred. The deferred energy balance on our Consolidated Balance Sheet represents the net accumulation of any under- or over-collection of energy costs. Under-collected energy costs appear as an asset on our Consolidated Balance Sheet and will be collected from our member distribution cooperatives in subsequent periods through our formula rate. Conversely, over-collected energy costs appear as a liability on our Consolidated Balance Sheet and will be returned to our member distribution cooperatives in subsequent periods through our formula rate.

Margin Stabilization

Margin Stabilization allows us to review our actual demand-related costs of service and demand revenues and adjust revenues from our member distribution cooperatives to meet our financial coverage requirements and accumulate additional equity as approved by our board of directors. Our formula rate allows us to recover and return amounts utilizing Margin Stabilization. We record all adjustments, whether increases or decreases, in the year affected and allocate any adjustments to our member distribution cooperatives based on power sales during that year. We collect these increases from our member distribution cooperatives, or offset decreases against amounts owed by our member distribution cooperatives to us, generally in the succeeding calendar year. We adjust operating revenues and accounts receivable–members or accounts payable–members, as appropriate, to reflect these adjustments. These adjustments are treated as due, owed, incurred, and accrued for the year to which the adjustment relates. In 2014, we did not record an adjustment to operating revenues utilizing Margin Stabilization, since the actual net margin attributable to ODEC, excluding any budgeted additional equity contributions, equaled 19.5% of our actual total interest charges. In accordance with our formula rate, no adjustment is recorded if the actual net margin attributable to ODEC, excluding any budgeted additional equity contributions, is more than 10% but less than 20% of our actual total interest charges. In 2013 and 2012, utilizing Margin Stabilization, we reduced operating revenues by $9.8 million, and $15.0 million, respectively. See “Factors Affecting Results—Formula Rate” below.

Accounting for Asset Retirement and Environmental Obligations

Accounting for Asset Retirement and Environmental Obligations requires legal obligations associated with the retirement of long-lived assets to be recognized at fair value when incurred and capitalized as part of the related long-lived asset. In the absence of quoted market prices, we estimate the fair value of our asset retirement obligations using present value techniques, in which estimates of future cash flows associated with retirement activities are discounted using a credit-adjusted risk-free rate. Asset retirement obligations currently reported on our Consolidated Balance Sheet were measured during a period of historically low interest rates. The impact on measurements of new asset retirement obligations using different rates in the future may be significant.

A significant portion of our asset retirement obligations relates to our share of the future cost to decommission North Anna. At December 31, 2014 and 2013, North Anna’s nuclear decommissioning asset retirement obligation totaled $93.7 million, or approximately 89.3% of our total asset retirement obligations, and $72.1 million, or approximately 89.1% of our total asset retirement obligations, respectively. Because of its significance, the following discussion of critical third-party assumptions inherent in determining the fair value of asset retirement obligations relates to those associated with our nuclear decommissioning obligations.

Approximately every four years, a new decommissioning study for North Anna is performed by third-party experts. The third-party experts provide us with periodic site-specific “base year” cost studies in order to estimate the nature, cost, and timing of planned decommissioning activities for North Anna. These cost studies are based on relevant information available at the time they are performed; however, estimates of future cash flows for extended

 

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periods are by nature highly uncertain and may vary significantly from actual results. In addition, these estimates are dependent on subjective factors, including the selection of cost escalation rates, which we consider to be a critical assumption. Our current estimate is based on a study that was performed in 2014 and adopted effective December 1, 2014, which resulted in an increase to our asset retirement obligation of $18.0 million. We are not aware of any events that have occurred since the 2014 study that would materially impact our estimate. We are currently evaluating the impact of the 2014 study on the funding status of our nuclear decommissioning trust.

We determine cost escalation rates, which represent projected cost increases over time, due to both general inflation and increases in the cost of specific decommissioning activities. The following table details the weighted average cost escalation rates used by the study:

 

Year Study Performed

   Weighted
Average Cost
Escalation Rate
 

2002

     3.27

2005

     2.42   

2009

     2.30   

2014

     2.04   

The weighted average cost escalation rate was applied if the cash flows increased as compared to the previous study. The original weighted average cost escalation rate was applied if the cash flows decreased as compared to the previous study. The use of alternative rates would have been material to the liabilities recognized. For example, had we increased the cost escalation rates by 0.5%, the amount recognized as of December 31, 2014, for our asset retirement obligations related to nuclear decommissioning would have been $15.5 million higher.

Accounting for Derivatives and Hedging

We primarily purchase power under both long-term and short-term physically-delivered forward contracts to supply power to our member distribution cooperatives. These forward purchase contracts meet the accounting definition of a derivative; however, a majority of these forward purchase derivative contracts qualify for the normal purchases/normal sales accounting exception under Accounting for Derivatives and Hedging. As a result, these contracts are not recorded at fair value. We record a liability and purchased power expense when the power under the physically-delivered forward contract is delivered. We also purchase natural gas futures generally for three years or less to hedge the price of natural gas for the operation of our combustion turbine facilities. These derivatives do not qualify for the normal purchases/normal sales accounting exception.

For all derivative contracts that do not qualify for the normal purchases/normal sales accounting exception, we defer all unrealized gains and losses on a net basis as a regulatory asset or regulatory liability, respectively, in accordance with Accounting for Regulated Operations. These amounts are subsequently reclassified as purchased power or fuel expense in our Consolidated Statements of Revenues, Expenses, and Patronage Capital as the power or fuel is delivered and/or the contract settles.

Generally, derivatives are reported at fair value on the Consolidated Balance Sheet in the regulatory assets or regulatory liabilities account and deferred charges–other and deferred credits and other liabilities–other. The measurement of fair value is based on actively quoted market prices, if available. Otherwise, we seek indicative price information from external sources, including broker quotes and industry publications.

 

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Factors Affecting Results

Margins

We operate on a not-for-profit basis and, accordingly, seek to generate revenues sufficient to recover our cost of service and produce margins sufficient to establish reasonable reserves, meet financial coverage requirements, and accumulate additional equity approved by our board of directors. Revenues in excess of expenses in any year are designated as net margin attributable to ODEC in our Consolidated Statements of Revenues, Expenses, and Patronage Capital. We designate retained net margins attributable to ODEC in our Consolidated Balance Sheet as patronage capital, which we assign to each of our members on the basis of its class of membership and business with us. Any distributions of patronage capital are subject to the discretion of our board of directors and restrictions contained in our Indenture and our syndicated credit agreement.

Formula Rate

Our power sales are comprised of two power products – energy and demand. Energy is the physical electricity delivered through transmission and distribution facilities to customers. We must have sufficient committed energy available to us for delivery to our member distribution cooperatives to meet their maximum energy needs at any time, with limited exceptions. This committed available energy at any time is referred to as demand.

The rates we charge our member distribution cooperatives for sales of energy and demand are determined by a formula rate accepted by FERC which is intended to permit collection of revenues which will equal the sum of:

 

    all of our costs and expenses;

 

    20% of our total interest charges; and

 

    additional equity contributions approved by our board of directors.

The formula rate identifies the cost components that we can collect through rates, but not the actual amounts to be collected. With limited minor exceptions, we can change our rates periodically to match the costs we have incurred and we expect to incur without seeking FERC approval.

Energy costs, which are primarily variable costs, such as nuclear, coal, and natural gas fuel costs and the energy costs under our power purchase contracts with third parties, are recovered through two separate rates, the base energy rate and the energy adjustment rate. Through December 31, 2013, the base energy rate was a fixed rate that required FERC approval prior to adjustment. To the extent the base energy rate over- or under-collected our energy costs, we credited or charged the difference through an energy adjustment rate. We reviewed our energy costs at least every six months to determine whether the base energy rate and the current energy adjustment rate together were recovering our actual and anticipated energy costs and revised the energy adjustment rate accordingly. Effective January 1, 2014, pursuant to FERC’s acceptance of revisions to the formula rate as issued in FERC’s December 2, 2013 order, the base energy rate is no longer a fixed rate that requires FERC approval prior to adjustment. The base energy rate now is developed annually to collect energy costs as estimated in our budget including amounts in the deferred energy account from the prior year. As of January 1 of each year, the energy adjustment rate will be zero. With board approval, we can revise the energy adjustment rate at any time during the year if it becomes apparent that the combined base energy rate and the current energy adjustment rate are over-collecting or under-collecting our actual and anticipated energy costs. See “FERC Proceeding Related to Formula Rate” in “Legal Proceedings” in Part I, Item 3.

Demand costs, which are primarily fixed costs, such as depreciation expense, interest expense, administrative and general expenses, capacity costs under power purchase contracts with third parties, transmission costs, and our margin requirements and additional equity contributions approved by our board of directors are

 

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recovered through our demand rates. The formula rate allows us to change the actual demand rates we charge as our demand-related costs change, without FERC approval, with the exception of decommissioning cost, which is a fixed number in the formula rate that requires FERC approval prior to any adjustment. FERC approval is also needed to change account classifications currently in the formula or to add accounts not otherwise included in the current formula. Additionally, depreciation studies are required to be filed with FERC for its approval if they would result in a change in our depreciation rates. Through December 31, 2013, we collected our total demand costs through a single demand rate. Effective January 1, 2014, pursuant to FERC’s acceptance of the revisions to the formula rate as issued in FERC’s December 2, 2013 order, we now collect our total demand costs through the following three separate rates:

 

    Transmission service rate – designed to collect transmission-related and distribution-related costs;

 

    RTO capacity service rate – a proxy rate based on capacity prices in PJM which PJM allocates to ODEC and all other PJM members; and

 

    Remaining owned capacity service rate – recovers all remaining demand costs not billed and/or recovered under the transmission service and RTO capacity service rates.

As stated above, our margin requirements and additional equity contributions approved by our board of directors are recovered through our demand rates. We establish our demand rates to produce a net margin attributable to ODEC equal to 20% of our budgeted total interest charges plus additional equity contributions approved by our board of directors. Through December 31, 2013, utilizing Margin Stabilization, we adjusted our operating revenues to reflect actual demand costs incurred, including a net margin attributable to ODEC equal to 20% of actual interest charges plus additional equity contributions approved by our board of directors. Effective January 1, 2014:

 

    At year end, if the actual net margin attributable to ODEC, excluding any budgeted additional equity contributions, equals more than 20% of our actual total interest charges, our board of directors may approve that, utilizing Margin Stabilization, revenues will be reduced by the amount of such excess margins, or that such excess margins will be retained as an additional equity contribution. For year-to-date interim reporting, if the actual net margin attributable to ODEC, excluding any budgeted additional equity contributions, equals more than 20% of our actual total interest charges, utilizing Margin Stabilization, revenues will be reduced by the amount of such excess margins.

 

    At year end and for year-to-date interim reporting, if the actual net margin attributable to ODEC, excluding any budgeted additional equity contributions, equals more than 10% but less than 20% of our actual total interest charges, no adjustment is recorded.

 

    At year end and for year-to-date interim reporting, if the actual net margin attributable to ODEC, excluding any budgeted additional equity contributions, equals less than 10% of our actual total interest charges, utilizing Margin Stabilization, revenues will be increased to produce a net margin attributable to ODEC, excluding any budgeted additional equity contributions, equal to 10% of our actual total interest charges.

For the year ended December 31, 2014, we did not record an adjustment to operating revenues utilizing Margin Stabilization, since the actual net margin attributable to ODEC, excluding any budgeted additional equity contributions, equaled 19.5% of our actual total interest charges. In accordance with our formula rate, no adjustment is recorded if the actual net margin attributable to ODEC, excluding any budgeted additional equity contributions, is more than 10% but less than 20% of our actual total interest charges. For the years ended December 31, 2013 and 2012, we recorded a reduction in operating revenues of $9.8 million and $15.0 million, respectively, utilizing Margin Stabilization, to produce a net margin equal to 20% of our actual total interest charges. See “Critical Accounting Policies—Margin Stabilization” above.

 

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We may revise our budget at any time to the extent that our current budget does not accurately reflect our costs and expenses or estimates of our sales of power. Increases or decreases in our budget automatically amend the energy and/or the demand components of our formula rate, as necessary. The formula rate also permits us to adjust revenues from the member distribution cooperatives to equal our actual total demand costs. We make these adjustments under Margin Stabilization. See “Critical Accounting Policies—Margin Stabilization” above. If at any time our board of directors determines that the formula does not meet all of our costs and expenses, it may adopt a new formula to meet those costs and expenses, subject to any necessary regulatory review and approval.

Recognition of Revenue

Our operating revenues on our Consolidated Statements of Revenues, Expenses, and Patronage Capital reflect the actual demand-related costs we incurred plus the energy costs that we collected during each calendar quarter and at year-end. Estimated demand-related costs are collected during the period through the demand components of our formula rate. In accordance with Margin Stabilization, these costs, as well as operating revenues, are adjusted at the end of each reporting period to reflect actual demand-related costs incurred during that period. See “Critical Accounting Policies—Margin Stabilization” above. Estimated energy costs are collected during the period through the energy components of our formula rate. Operating revenues are not adjusted at the end of each reporting period to reflect actual energy costs incurred during that period. The difference between actual energy costs incurred and energy costs collected during each period is recorded as deferred energy expense. See “Critical Accounting Policies—Deferred Energy” above.

Through December 31, 2013, we billed our total demand costs to each of our member distribution cooperatives based on its requirement for energy during the hour of the month when the need for energy among all of the customers in the Virginia mainland or the Delmarva Peninsula, as applicable, was highest, as measured in MW. The hour of the month when the need for energy is highest is referred to as the coincident peak. Through December 31, 2013, and currently, we billed energy to each of our member and non-member customers based on the total MWh delivered to them each month. Effective January 1, 2014, pursuant to FERC’s acceptance of the revisions to the formula rate as issued in FERC’s December 2, 2013 order, we now bill and collect our total demand costs through three separate rates: a transmission service rate, an RTO capacity service rate, and a remaining owned capacity service rate. See “Factors Affecting Results—Formula Rate” above. The transmission service rate is billed to each of our member distribution cooperatives based on its contribution to the single zonal coincident peak for the prior year within each of the PJM transmission zones. The RTO capacity service rate is billed to each of our member distribution cooperatives based on its contribution to the average of the five hourly PJM coincident peaks in the prior year, subject to add-backs for participation in PJM demand response programs. The remaining owned capacity service rate is billed to each of our member distribution cooperatives based on its contribution to the monthly zonal coincident peak.

Customers’ Requirements for Power

Growth in the number of customers and growth in customers’ requirements for power significantly affect our member distribution cooperatives’ customers’ requirements for power. Factors affecting our member distribution cooperatives’ customers’ requirements for power include:

 

    Weather – Weather affects the demand for electricity. Relatively higher or lower temperatures tend to increase the demand for energy to use air conditioning and heating systems, respectively. Mild weather generally reduces the demand because heating and air conditioning systems are operated less. Weather also plays a role in the price of market energy through its effects on the market price for fuel, particularly natural gas.

 

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    Heating and cooling degree days are measurement tools used to quantify the need to utilize heat or cooling, respectively, for a building. The heating and cooling degree days for the three years ended December 31, were as follows:

 

     2014      2013      2012  

Heating degree days

     3,869         3,461         2,880   

Cooling degree days

     1,064         1,131         1,363   

 

    Economy – General economic conditions have an impact on the rate of growth of our member distribution cooperatives’ energy requirements.

 

    Residential growth – Residential growth in our member distribution cooperatives’ service territories increases the requirements for power.

 

    Commercial growth – The amount, size, and usage of electronics and machinery and the expansion of operations among our member distribution cooperatives’ commercial and industrial customers impacts the requirements for power.

For additional discussion of our member distribution cooperatives’ customers’ growth, see “Members—Member Distribution Cooperatives—Service Territories and Customers” in Item 1.

Power Supply Resources

In an attempt to provide stable power costs to our member distribution cooperatives, we utilize a combination of our owned generating resources and purchases from the market. We also regularly evaluate options for future power sources, including additional owned generation and power purchase contracts.

Market forces influence the structure and price of new power supply contracts into which we enter. When we enter into long-term power purchase contracts or agree to purchase energy at a date in the future, we rely on models based on our judgments and assumptions of factors such as future demand for power and market prices of energy and the price of commodities, such as natural gas, used to generate electricity. Our actual results may vary from what our models predict, which may in turn impact our resulting costs to our members. Additionally, our models become less reliable the further into the future that the estimates are made. See “Risk Factors” in Item 1A.

In 2014, we satisfied approximately 67.5% of our member distribution cooperatives’ capacity requirements and 40.2% of their energy requirements through our ownership interests in Clover, North Anna, Louisa, Marsh Run, and Rock Springs, and we purchased power under physically-delivered forward contracts and in the spot market to supply the remaining needs of our member distribution cooperatives. See “Business—Power Supply Resources” in Item 1 and “Properties” in Item 2.

In 2014, we began construction of an approximate 1,000 MW natural gas-fueled generation facility, named Wildcat Point, in Cecil County, Maryland. See “Wildcat Point” above.

PJM

PJM is an RTO that serves all of Delaware and Maryland, and most of Virginia, as well as other areas outside our member distribution cooperatives’ service territories. We are a member of PJM and are therefore subject to the operations of PJM. PJM coordinates and establishes policies for the generation, purchase, and sale of capacity and energy in the control areas of its members, including all of the service territories of our member distribution cooperatives. As a result, our generating facilities are under dispatch control of PJM.

PJM balances its participants’ power requirements with the power resources available to supply those requirements. Based on this evaluation of supply and demand, PJM schedules and dispatches available generating facilities throughout its region in a manner intended to meet the demand for energy in the most reliable and cost-effective

 

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manner. Thus, PJM directs the dispatch of these facilities even though it does not own them. When PJM cannot dispatch the most economical generating facilities due to transmission constraints, PJM will dispatch more expensive generating facilities to meet power requirements. For these reasons, actions by PJM may materially affect our operating results. PJM compensates us for the capacity of our generating facilities made available without regard to whether our generating facilities are dispatched. See “Business—Power Supply Resources—PJM” in Item 1.

We transmit power to our member distribution cooperatives through the transmission facilities subject to PJM operational control. We have agreements with PJM which provide us with access to transmission facilities under PJM’s control as necessary to deliver energy to our member distribution cooperatives. We own a limited amount of transmission facilities. See “Properties—Transmission” in Item 2.

Transmission owners within PJM have made significant investments in their transmission systems. Because transmission rates are established to recover the cost of investment plus a return on the investment, rates for network transmission services have increased dramatically in recent years. We anticipate that our transmission costs will increase significantly in 2015. Our transmission costs are impacted each year by billing determinants, which are based on our usage during the peak hour of the year for each transmission area. The billing determinants for transmission were significantly higher than anticipated in 2014 due to the impact of the unseasonably cold weather in January 2014 which will directly impact our transmission costs for 2015.

Generating Facilities

Our operating expenses, and consequently our rates to our member distribution cooperatives, are significantly affected by the operations of our baseload generating facilities, Clover and North Anna. Baseload generating facilities, particularly nuclear power plants such as North Anna, generally have relatively high fixed costs. Nuclear facilities operate with relatively low variable costs due to lower fuel costs and technological efficiencies. In addition, coal-fired facilities have relatively low variable costs, as compared to combustion turbine facilities such as Louisa, Marsh Run, and Rock Springs. Our combustion turbine facilities have relatively low fixed costs and greater operational flexibility; however, they are more expensive to operate and, as a result, are dispatched only when the market price of energy makes their operation economical or when their operation is required by PJM to meet system reliability requirements.

As previously mentioned, our generating facilities are under dispatch control of PJM. See “PJM” above. Typically, nuclear facilities are almost always dispatched and coal-fired and combustion turbine facilities are generally dispatched based upon economic factors including the market price of energy, and to meet system reliability requirements. The operational availability of our owned generating resources for the past three years was as follows:

 

     Year Ended December 31,  
     2014     2013     2012  

Clover

     87.7     96.3     85.3

North Anna

     93.9        88.8        90.7   

Louisa

     96.8        97.8        97.5   

Marsh Run

     98.7        95.4        98.7   

Rock Springs

     94.9        97.1        96.8   

The output of Clover and North Anna for the past three years as a percentage of maximum dependable capacity rating of the facilities was as follows:

 

     Year Ended December 31,  
     2014     2013     2012  

Clover

     74.7     78.0     58.1

North Anna

     95.9        90.6        92.9   

 

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The scheduled and unscheduled outages for Clover and North Anna for the past three years were as follows:

 

     Clover
Year Ended December 31,
     North Anna
Year Ended December 31,
 
     2014      2013      2012      2014      2013      2012  
     (in days)      (in days)  

Scheduled

     72.0         15.7         62.0         34.0         65.2         36.0   

Unscheduled

     18.0         11.4         45.7         10.3         16.3         29.0   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

  90.0      27.1      107.7      44.3      81.5      65.0   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

The unscheduled outages for Clover in 2014 were related to maintenance items associated with the boiler and boiler feed pump rework. The unscheduled outages for Clover in 2013 were related to maintenance items associated with the boiler. The majority of the unscheduled outages for Clover in 2012 were related to the extension of planned maintenance outages due to findings during the outages and other maintenance items.

Each unit at North Anna is scheduled for refueling approximately every 18 months. While only one unit is refueled at a time, this typically results in both units being off-line for refueling during the same calendar year once every three years. During 2014, Unit 2 at North Anna was off-line for refueling. During 2013, both units at North Anna were off-line for refueling.

The majority of the unscheduled outage time for North Anna during 2014 related to reactor coolant system maintenance. The majority of the unscheduled outages for North Anna during 2013 related to maintenance items. The majority of the unscheduled items during 2012 related to an extension of the spring outage for Unit 1 and an unscheduled reactor coolant pump seal replacement for Unit 2.

Increasing Environmental Regulation

We are subject to extensive federal and state regulation regarding environmental matters. This regulation is becoming increasingly stringent through amendments to federal and state statutes and the development of regulations authorized by existing law. Future federal and state legislation and regulations present the potential for even greater obligations to limit the impact on the environment from the operation of our generation and transmission facilities. See “Business—Regulation— Environmental” in Item 1 and “Risk Factors” in Item 1A.

Sales to Member Distribution Cooperatives

Revenues from sales to our member distribution cooperatives are a function of our formula rate for sales of power and sales of renewable energy credits to our member distribution cooperatives, and our member distribution cooperatives’ customers’ requirements for power. Our formula rate is based on our cost of service in meeting these requirements. See “Factors Affecting Results—Formula Rate” above.

Sales to TEC

In accordance with Consolidation Accounting, TEC is considered a variable interest entity for which ODEC is the primary beneficiary. The financial statements of TEC are consolidated and the inter-company balances are eliminated in consolidation. TEC’s sales to third parties are reflected as non-member revenues; however, in 2014, 2013, and 2012, TEC had no sales to third parties.

 

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Sales to Non-members

Sales to non-members consist of sales of excess purchased and generated energy and sales of renewable energy credits. We primarily sell excess energy to PJM at the prevailing market price at the time of sale. Excess energy is the result of changes in our purchased power portfolio, differences between actual and forecasted needs, and changes in market conditions. Renewable energy credits that are not sold to our member distribution cooperatives are sold to non-members.

Results of Operations

Operating Revenues

Our operating revenues are derived from sales of power and renewable energy credits to our member distribution cooperatives and non-members. Our operating revenues by type of purchaser for the past three years were as follows:

 

     Year Ended December 31,  
     2014      2013      2012  
     (in thousands)  

Revenues from sales to:

  

Member distribution cooperatives

        

Energy revenues (1)

   $ 586,327       $ 504,886       $ 527,517   

Demand revenues

     321,706         305,253         299,309   
  

 

 

    

 

 

    

 

 

 

Total revenues from sales to member distribution cooperatives

  908,033      810,139      826,826   

Non-members (2)

  43,543      31,930      15,855   
  

 

 

    

 

 

    

 

 

 

Total operating revenues

$ 951,576    $ 842,069    $ 842,681   
  

 

 

    

 

 

    

 

 

 

Average cost of energy to member distribution cooperatives (per MWh)

$ 46.17    $ 40.86    $ 43.61   

Average cost of demand to member distribution cooperatives (per MWh)

  25.33      24.71      24.74   
  

 

 

    

 

 

    

 

 

 

Average total cost to member distribution cooperatives (per MWh)

$ 71.50    $ 65.57    $ 68.35   
  

 

 

    

 

 

    

 

 

 

 

(1)  Includes sales of renewable energy credits of $1.3 million and $1.4 million in 2014 and 2013, respectively. Sales of renewable energy credits in 2012 were immaterial.
(2)  Includes sales of renewable energy credits of $5.9 million, $6.1 million, and $0.5 million in 2014, 2013, and 2012, respectively.

Our energy sales in MWh to our member distribution cooperatives and non-members for the past three years were as follows:

 

     Year Ended December 31,  
     2014      2013      2012  
     (in MWh)  

Energy sales to:

  

Member distribution cooperatives

     12,699,956         12,356,005         12,096,230   

Non-members

     579,461         626,856         508,443   
  

 

 

    

 

 

    

 

 

 

Total energy sales

  13,279,417      12,982,861      12,604,673   
  

 

 

    

 

 

    

 

 

 

In 2014, our energy sales in MWh to our member distribution cooperatives were 2.8% higher, as compared to 2013. In the first quarter of 2014, the entire mid-Atlantic region experienced extremely cold weather. In 2013, our energy sales in MWh to our member distribution cooperatives were 2.1% higher, as compared to 2012.

In 2014, our energy sales in MWh to non-members were 7.6% lower as compared to 2013, as a result of the decrease in the volume of excess purchased and generated energy. In 2013, our energy sales in MWh to non-members were 23.3% higher as compared to 2012. Sales to non-members consist of sales of excess purchased and generated energy.

 

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In 2014, total revenues from sales to our member distribution cooperatives increased $97.9 million, or 12.1%, as compared to 2013 primarily due to the increase in energy revenues which was driven by increases in our total energy rate and volume of energy sales in MWh. In 2013, total revenues from sales to our member distribution cooperatives decreased $16.7 million, or 2.0%, as compared to 2012 primarily due to the 6.3% decrease in the average cost of energy slightly offset by the 2.0% increase in the demand costs we incurred.

The average cost per MWh to our member distribution cooperatives is affected by changes in our revenues as well as the sales volumes. In 2014, our average total cost to member distribution cooperatives per MWh was 9.0% higher as compared to 2013. In 2013, our average total cost to member distribution cooperatives per MWh was 4.1% lower as compared to 2012.

The following table summarizes the changes to our total energy rate since 2012 which were implemented to address the differences in our realized as well as projected energy costs:

 

Effective Date of Rate Change:

   % Change  

April 1, 2012

     (4.6

October 1, 2012

     (6.8

April 1, 2013

     (2.4

October 1, 2013

     4.7   

January 1, 2014

     0.5   

April 1, 2014

     11.8   

October 1, 2014

     2.4   

Non-member revenue increased $11.6 million, or 36.4%, in 2014 as compared to the same period in 2013, due to a 45.7% increase in revenue from sales of excess energy slightly offset by a 3.3% decrease in revenue from sales of renewable energy credits. The increase in revenue from sales of excess energy was primarily due to a 57.7% increase in the average price of excess energy sold which was sold at the prevailing market price. Non-member revenue increased $16.1 million, or 101.4%, in 2013 as compared to 2012, primarily due to the 23.3% increase in the volume of excess energy sales and the 36.4% increase in the average price of excess energy sold which was sold at the prevailing market price.

Operating Expenses

The following is a summary of the components of our operating expenses for the past three years.

 

     Year Ended December 31,  
     2014      2013      2012  
     (in thousands)  

Fuel

   $ 213,528       $ 133,592       $ 90,874   

Purchased power

     518,814         463,159         471,557   

Transmission

     75,959         66,590         66,189   

Deferred energy

     (57,141      (18,834      21,315   

Operations and maintenance

     49,599         41,546         42,615   

Administrative and general

     40,279         42,385         35,958   

Depreciation and amortization

     42,049         42,346         42,012   

Amortization of regulatory asset/(liability), net

     5,838         6,310         735   

Accretion of asset retirement obligations

     3,870         3,980         3,739   

Taxes, other than income taxes

     8,256         8,405         8,542   
  

 

 

    

 

 

    

 

 

 

Total Operating Expenses

$ 901,051    $ 789,479    $ 783,536   
  

 

 

    

 

 

    

 

 

 

Our operating expenses are comprised of the costs that we incur to generate and purchase power to meet the needs of our member distribution cooperatives, and the costs associated with any sales of power to non-members. Our energy costs generally are variable and include the energy portion of our purchased power expense,

 

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fuel expense, and the variable portion of operations and maintenance expense. Our demand costs generally are fixed and include the fixed portion of operations and maintenance, administrative and general, and depreciation and amortization expenses, as well as the capacity portion of our purchased power expense. Additionally, all non-operating expenses and income items, including interest charges, net and investment income, are components of our demand costs. See “Factors Affecting Results—Formula Rate” above.

Total operating expenses were $111.6 million, or 14.1% higher for 2014 as compared to 2013. The increases in fuel, purchased power, transmission, and operations and maintenance expenses were offset by the decrease in deferred energy.

 

    Fuel expense increased $79.9 million, or 59.8%, primarily due to the 49.0% increase in the dispatch of our combustion turbine facilities as well as the 164.6% increase in the average cost of fuel for our combustion turbine facilities.

 

    Purchased power expense, which includes the cost of purchased energy and capacity, increased $55.7 million, or 12.0%, primarily due to the 11.0% increase in the average cost of purchased energy.

 

    Transmission expense increased $9.4 million, or 14.1%, primarily due to an increase in PJM rates for network transmission services. See “Power Supply Resources—PJM” in Item 1.

 

    Operations and maintenance expense increased $8.1 million, or 19.4%, primarily due to scheduled maintenance outages at Clover.

 

    Deferred energy expense decreased $38.3 million. In 2014, we under-collected $57.1 million in energy costs, whereas in 2013, we under-collected $18.8 million. Deferred energy expense represents the difference between energy revenues and energy expenses.

Total operating expenses were relatively flat for 2013 as compared to 2012. The increases in fuel and administrative and general expenses were offset by decreases in deferred energy and purchased power expenses.

 

    Fuel expense increased $42.7 million, or 47.0%, primarily due to the operational availability of Clover and PJM’s increased economic dispatch of Clover and our combustion turbine facilities, partially offset by the lower average cost of fuel for the combustion turbine facilities.

 

    Administrative and general expense increased $6.4 million, or 17.9%, primarily due to $7.7 million of preconstruction expenses related to Wildcat Point.

 

    Deferred energy expense decreased $40.1 million. During 2013, we under-collected $18.8 million in energy costs; whereas in 2012, we over-collected $21.3 million in energy costs. The under-collection in 2013 was the result of rate decreases approved by our board of directors in part to return previously over-collected energy costs to our member distribution cooperatives. See “Critical Accounting Policies—Deferred Energy” above. The over-collection in 2012 was the result of energy costs being less than anticipated in 2012.

 

    Purchased power expense, which includes the cost of purchased energy and capacity, decreased $8.4 million, or 1.8%, primarily due to a 5.9% decrease in the volume of purchased energy due to increased generation from our owned generating facilities, partially offset by a 4.2% increase in the average cost of purchased energy.

 

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Other Items

Gain/(loss) on Investments, Net

In accordance with regulatory accounting, we defer the difference between asset retirement expense, and interest income and realized gains and losses on the nuclear decommissioning trust, to our regulatory liability (North Anna asset retirement obligation deferral). See Note 10 of the Notes to Consolidated Financial Statements. In December 2013 and July 2012, the investments in the nuclear decommissioning trust were rebalanced resulting in a net realized gain of $2.3 million and a net realized loss of $2.2 million, respectively. The gain and loss are recorded in “Gain/(loss) on investments, net” on the Consolidated Statements of Revenues, Expenses, and Patronage Capital; however, the gain and loss are deferred to the regulatory liability referred to above via “Amortization of regulatory asset/(liability), net.” Therefore, there is no net impact on the Consolidated Statements of Revenues, Expenses, and Patronage Capital. The impact on the Consolidated Statements of Cash Flows is reflected in the purchases of and proceeds from sale of available for sale securities.

Investment Income

Investment income increased in 2014, by $2.0 million, or 37.8%, as compared to 2013, and in 2013 increased by $1.2 million, or 29.2%, as compared to 2012, primarily due to higher income earned on our nuclear decommissioning trust.

Interest Charges, Net

The primary factors affecting our interest charges, net are issuance of indebtedness, scheduled payments of principal on our indebtedness, interest charges related to our revolving credit facility, and capitalized interest. The major components of interest charges, net for the past three years were as follows:

 

     Year Ended December 31,  
     2014      2013      2012  
     (in thousands)  

Interest on long-term debt

   $ (45,058    $ (46,753    $ (48,139

Interest on revolving credit facility

     (1,231      (847      (844

Other interest

     (340      (325      (711
  

 

 

    

 

 

    

 

 

 

Total interest charges

$ (46,629 $ (47,925 $ (49,694

Allowance for borrowed funds used during construction

  936      245      996   
  

 

 

    

 

 

    

 

 

 

Interest charges, net

$ (45,693 $ (47,680 $ (48,698
  

 

 

    

 

 

    

 

 

 

In 2014, interest charges, net decreased $2.0 million, or 4.2%, primarily as a result of the decrease in total interest charges due to scheduled principal payments on long-term debt.

In 2013, interest charges, net decreased $1.0 million, or 2.1%, primarily as a result of the decrease in total interest charges due to scheduled principal payments on long-term debt and the redemption of our $60.2 million 2002 Series A Bonds, partially offset by the interest charges related to the issuance of $100.0 million of long-term debt in June 2013.

Net Margin Attributable to ODEC`

In 2014, our net margin attributable to ODEC, decreased $0.5 million, or 4.9%, as compared to 2013, due to lower total interest charges in 2014 as compared to 2013, and demand revenues that produced a net margin attributable to ODEC that equaled 19.5% of our actual total interest charges. See “Factors Affecting Results—Formula Rate” above. In 2013, our net margin attributable to ODEC, decreased $0.4 million, or 3.7%, as compared to 2012, due to lower total interest charges in 2013 as compared to 2012.

 

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Financial Condition

The principal changes in our financial condition from December 31, 2013 to December 31, 2014, were caused by the increase in construction work in progress and revolving credit facility, the change in deferred energy, and increases in accounts payable, asset retirement obligations, fuel, materials, and supplies, and accounts payable–members.

 

    Construction work in progress increased $135.5 million primarily due to expenditures related to Wildcat Point and nuclear fuel.

 

    Revolving credit facility increased $86.0 million due to outstanding borrowings under our revolving credit facility.

 

    Deferred energy changed $57.1 million as a result of the under-collection of our energy costs in 2014. The deferred energy balance changed from a $37.2 million liability (over-collection) at December 31, 2013 to a $19.9 million asset (under-collection) at December 31, 2014.

 

    Accounts payable increased $28.1 million primarily due to increased payables related to Wildcat Point.

 

    Asset retirement obligations increased $24.1 million due to the change in our asset retirement obligations related to North Anna and Clover, as well as accretion. In 2014, a new decommissioning study was performed resulting in an increase to our asset retirement obligation related to North Anna of $18.0 million. We also recorded new obligations totaling $2.3 million related to ash landfills at Clover.

 

    Fuel, materials, and supplies increased $14.9 million primarily due to increases in coal, diesel fuel, renewable energy credits, and spare parts for Clover and North Anna.

 

    Accounts payable–members increased $10.2 million due to the increase in member prepayments offset by the decrease in amounts owed to our member distribution cooperatives under Margin Stabilization.

Liquidity and Capital Resources

Sources

Cash generated by our operations, periodic borrowings under our revolving credit facility, and occasional issuances of long-term indebtedness provide our sources of liquidity and capital.

Operations

In 2014, 2013, and 2012, our operating activities provided cash flows of $16.8 million, $20.1 million, and $51.3 million, respectively. Operating activities in 2014 were primarily impacted by the following:

 

    Deferred energy changed $57.1 million due to the under-collection of energy costs in 2014. To address the under-collection of energy costs, we increased our total energy rate 11.8% effective April 1, 2014, and an additional 2.4% effective October 1, 2014.

 

    Current liabilities changed $9.2 million primarily due to the $10.2 million increase in accounts payable–members.

 

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Revolving Credit Facility

We currently maintain a $500.0 million, five-year revolving credit facility to cover our short-term and medium-term funding needs. Commitments under this syndicated credit agreement extend until March 5, 2019. At December 31, 2014, we had $86.0 million in borrowings outstanding under this facility, at an interest rate of 1.5%. Additionally, at December 31, 2014, we had a letter of credit in the amount of $10.0 million outstanding. At December 31, 2013, we did not have any borrowings or letters of credit outstanding under this facility; however, the interest rate on any borrowings would have been 1.1%.

Our syndicated credit agreement contains customary events of default, which, if they occur, would terminate our ability to borrow amounts under this facility and potentially accelerate any outstanding loans under this facility at the election of the lenders. Some of these customary events of default relate to:

 

    our failure to timely pay any principal and interest due under the credit facility;

 

    a breach by us of our representations and warranties in the credit agreement or related documents;

 

    a breach of a covenant contained in the credit agreement, which, in some cases we are given an opportunity to cure and, in certain cases includes a debt to capitalization financial covenant;

 

    failure to pay, when due, other indebtedness above a specified amount;

 

    an unsatisfied judgment above specified amounts;

 

    bankruptcy events relating to us;

 

    invalidity of the credit agreement and related loan documentation or our assertion of invalidity; and

 

    a failure by our member distribution cooperatives to pay amounts in excess of an agreed threshold owing to us beyond a specified cure period.

Financings

We fund the portion of our capital expenditures that we are not able to fund from operations through borrowings under our revolving credit facility and financings in the debt capital markets. These capital expenditures consist primarily of the costs related to the development, construction, acquisition, or improvement of our owned generating facilities.

Our 2002 Series A Bonds, with an aggregate principal amount of $60.2 million outstanding, were subject to optional redemption by ODEC on or after June 1, 2013. We issued a call notice for the 2002 Series A Bonds in the second quarter of 2013 and redeemed these bonds on June 1, 2013.

On June 28, 2013, we issued $100.0 million of first mortgage bonds in a private placement transaction. The issuance consisted of $50.0 million of 4.21% First Mortgage Bonds, 2013 Series A due December 1, 2043 and $50.0 million of 4.36% First Mortgage Bonds, 2013 Series B due December 1, 2053.

On January 15, 2015, we issued $332.0 million of first mortgage bonds in a private placement transaction. The issuance consisted of $260.0 million of 4.46% First Mortgage Bonds, 2015 Series A due December 1, 2044 and $72.0 million of 4.56% First Mortgage Bonds, 2015 Series B due December 1, 2053.

Uses

Our uses of liquidity and capital relate to funding our working capital needs, investment activities, and financing activities. Substantially all of our investment activities relate to capital expenditures in connection with our generating facilities. We expect that cash flow from our operations, borrowings under our syndicated credit facility, and financings in the debt capital markets will be sufficient to meet our currently anticipated future operational and capital requirements.

 

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Capital Expenditures

We regularly forecast our capital expenditures as part of our long-term business planning activities. We review these projections frequently in order to update our calculations to reflect changes in our future plans, construction costs, market factors, and other items affecting our forecasts. Our actual capital expenditures could vary significantly from these projections. The table below summarizes our actual and projected capital expenditures, including capitalized interest, for 2012 through 2017:

 

     Actual
Year Ended December 31,
     Projected
Year Ended December 31,
 
     2012      2013      2014(1)      2015(1)      2016      2017  
     (in millions)  

Wildcat Point

   $ —         $ 6.0       $ 80.8       $ 455.8       $ 162.1       $ 85.8   

Clover

     11.2         7.1         17.5         22.8         6.9         13.6   

North Anna nuclear fuel

     12.6         7.3         16.4         9.6         10.6         17.3   

North Anna

     6.0         6.4         7.5         8.3         7.3         5.8   

Transmission

     0.3         3.6         9.9         7.1         5.3         6.3   

Combustion turbine facilities

     0.6         1.0         1.0         2.5         1.2         1.2   

Other

     1.7         0.7         2.8         2.2         0.6         0.6   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

$ 32.4    $ 32.1    $ 135.9    $ 508.3    $ 194.0    $ 130.6   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1)  For 2014, includes an adjustment for accounts payable of $29.0 million for Wildcat Point, $0.1 million for Clover, $1.2 million for North Anna, $1.1 million for transmission, and $1.9 million for combustion turbine facilities. These adjustments are reflected as projected capital expenditures in 2015.

Nearly all of our capital expenditures consist of additions to electric plant and equipment, particularly for the construction of Wildcat Point in the next few years. Capital expenditures for “Other” include costs related to our administrative and general assets, and distributed generation facilities. We intend to use our cash flow from operations, borrowings under our revolving credit facility, and financings in the debt capital markets to fund all of our currently projected capital requirements through 2017.

 

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Contractual Obligations

In the normal course of business, we enter into long-term arrangements relating to the construction, operation and maintenance of our generating facilities, power purchases for capacity and energy, the financing of our operations, and other matters. See “Business—Power Supply Resources—Power Purchase Contracts” in Item 1. The following table summarizes our long-term contractual obligations at December 31, 2014:

 

     Payments due by Period  
     Total      2015      2016-2017      2018-2019      2020 and
Thereafter
 
     (in millions)  

Long-term debt obligations (1)

   $ 1,410.9       $ 69.2       $ 133.5       $ 213.0       $ 995.2   

Power purchase obligations

     1,075.8         279.8         361.8         356.3         77.9   

Asset retirement obligations

     379.9         —           —           1.8         378.1   

Operating lease obligations

     112.2         0.5         1.0         1.5         109.2   

Construction obligations

     535.2         400.7         134.5         —           —     
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

$ 3,514.0    $ 750.2    $ 630.8    $ 572.6    $ 1,560.4   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) In January 2015, we issued $332.0 million of first mortgage bonds in a private placement transaction, which is not reflected in this line item. The issuance consisted of $260.0 million of 4.46% First Mortgage Bonds, 2015 Series A due December 1, 2044 and $72.0 million of 4.56% First Mortgage Bonds, 2015 Series B due December 1, 2053.

We expect to fund these obligations with cash flow from operations, borrowings under our revolving credit facility, and financings in the debt capital markets.

Long-term Debt Obligations

At December 31, 2014, our long-term debt obligations include long-term debt issued privately and to the public under the Indenture, and borrowings under our revolving credit facility. Long-term debt includes both the principal of and interest on long-term debt, and long-term debt due within one year.

On January 15, 2015, we issued $332.0 million of first mortgage bonds in a private placement transaction. See “Liquidity and Capital Resources—Sources—Financings” above.

Power Purchase Obligations

As part of our power supply strategy, we entered into a number of agreements for the purchase of capacity or energy, or both, in order to meet our member distribution cooperatives’ requirements. See “Business—Power Supply Resources—Power Purchase Contracts” in Item 1.

Asset Retirement Obligations

We account for our asset retirement obligations in accordance with Accounting for Asset Retirement and Environmental Obligations which requires legal obligations associated with the retirement of long-lived assets to be recognized at fair value when incurred and capitalized as part of the related long-lived asset. A significant portion of our asset retirement obligations relates to the future decommissioning of North Anna. See “Critical Accounting Policies—Accounting for Asset Retirement and Environmental Obligations” above.

Operating Lease Obligations

Our obligation described above primarily relates to our portion of the Clover Unit 1 purchase option price at the end of the term of the leaseback that will be satisfied by our investment in United States Treasury securities. See “Significant Contingent Obligations—Clover Lease” below.

 

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Construction Obligations

This includes payments related to Wildcat Point EPC contractor payments and major equipment purchase contracts. See “Overview—Wildcat Point” above.

Significant Contingent Obligations

In addition to these existing contractual obligations, we have significant contingent obligations. These obligations primarily relate to power purchase arrangements, our arrangement with TEC, and our lease of our interest in Clover Unit 1.

In limited circumstances, we have obligations to provide credit support if our obligations issued under the Indenture are rated below specified thresholds by S&P and Moody’s. These circumstances relate to our Clover Unit 1 lease and some of our purchases of power in the market.

Power Purchase Arrangements

Under the terms of most of our hedging instruments, we typically agree to provide collateral under certain circumstances and we require comparable terms from our counterparties. The collateral we may be required to post with a counterparty, and vice versa, is normally a function of the collateral thresholds we negotiate with a counterparty relative to a range of credit ratings as well as the value of our transaction(s) under a contract with a respective counterparty. At December 31, 2014, the collateral we had posted with counterparties pursuant to the hedging instruments we have in place was $15.5 million. Typically, collateral thresholds under our contracts are zero once an entity is rated below investment grade by S&P or Moody’s (i.e., “BBB-” or “Baa3,” respectively). At December 31, 2014, if our credit ratings had been below investment grade we estimate we would have been obligated to post between $600.0 million and $700.0 million of collateral with our counterparties. This calculation is based on energy prices on December 31, 2014, and delivered power for which we have not yet paid. Depending on the difference between the price of power under our contracts and the price of power in the market at the time of the calculation, this amount could increase or decrease.

Additionally, in accordance with its credit policy, PJM subjects each applicant, participant and member of PJM to a credit evaluation to determine its creditworthiness, and whether it must provide any collateral to support its obligations in connection with its PJM transactions. A material change in our financial condition, including the downgrading of our credit rating by any rating agency, could cause PJM to re-evaluate our creditworthiness and require that we provide collateral. At December 31, 2014, if PJM had determined that we needed to provide collateral to support our obligations, PJM could have asked us to provide up to approximately $14.8 million.

TEC Guarantees

TEC is considered a variable interest entity for which we are the primary beneficiary, and we have consolidated its results and eliminated all intercompany balances and transactions in consolidation. To facilitate the ability of TEC to sell power in the market, we have agreed to guarantee up to a maximum of $200.0 million of TEC’s delivery and payment obligations associated with its energy trades if requested. See “Business—Members—TEC” in Item 1. Our agreement to guarantee these obligations continues in effect until we elect to terminate it by providing at least 30 days prior written notice of termination or until all amounts owed to us by TEC have been paid. Our guarantee of TEC’s obligations will enable it to maintain sufficient credit support to meet its delivery and payment obligations associated with its energy trades. At December 31, 2014, we did not have any guarantees outstanding in support of TEC’s obligations.

Clover Lease

In 1996, we entered into a lease transaction relating to our 50% undivided ownership interest in Clover Unit 1 and related common facilities. In this transaction, we leased our undivided interest in the facility to an owner

 

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trust for the benefit of an investor for the full productive life of the unit in exchange for a one-time rental payment of $315.0 million at the beginning of the lease. Immediately after the lease to the owner trust, we leased the unit and common facilities back for a term of 21.8 years and agreed to make periodic rental payments to the owner trust.

We used a portion of the one-time rental payment we received to enter into a payment undertaking agreement and to purchase an investment, which provides for substantially all of:

 

    our periodic rent payments under the leaseback; and

 

    the fixed purchase price of the interest in Unit 1 at the end of the term of the leaseback if we were to exercise our option to purchase the interest of the owner trust in Unit 1 and the common facilities at that time. The fixed purchase price is $430.5 million.

After entering into the payment undertaking agreement, making the investment and paying transaction costs, we had $23.7 million remaining (the gain on the transaction) and we retained possession and our initial entitlement to the output of Unit 1.

The payment undertaking agreement was issued by Rabobank which has senior debt obligations which are currently rated “A+” by S&P and “Aa2” by Moody’s. Under this agreement, we made a payment to Rabobank; in return Rabobank agreed to make payments directly to the lender in the related lease transaction in satisfaction of a portion of our rent payment obligation under the leaseback and a portion of the fixed purchase price if we choose to exercise that option. We remain liable for all rental payments under the leaseback if Rabobank fails to make such payments, although the owner trust has agreed to pursue Rabobank before pursuing payment from us. For 2014, Rabobank paid $15.2 million of rent. At December 31, 2014, both the value of the portion of our lease obligations to be paid by Rabobank to the owner trust, as well as the value of our interest in the related payment undertaking agreement, totaled approximately $308.5 million.

In connection with the lease and leaseback, we also agreed to deliver a letter of credit to the investor to the lease within 90 days after our obligations under the Indenture are either rated below “A-” by S&P or “Baa2” by Moody’s, or if such obligations are placed on negative credit watch by either S&P or Moody’s while rated “A-” by S&P or “Baa2” by Moody’s, respectively. If our ratings had been below this minimum rating at December 31, 2014, the estimated amount of the letter of credit we would have been required to provide was approximately $5.4 million. The amount of any letter of credit we are required to deliver in connection with the lease is impacted by the changes in market value of the investment we purchased and ultimately decreases to zero by December 18, 2018.

At the end of the term of the Clover Unit 1 leaseback, we have the option to purchase the owner trust’s interest in the unit or arrange for an acceptable third party to enter into a power purchase agreement with the owner trust. If we decide to purchase the owner trust’s interest in the unit, we must pay the owner trust a fixed purchase price of $430.5 million. Payments under the payment undertaking agreement are expected to fund approximately $289.7 million of these payments. These payments also will be funded by United States Treasury securities with a maturity value of $108.6 million. The remaining $32.2 million will be provided by us, but will in turn be paid to us as the holder of a loan to the owner trust. If we do not elect to purchase the owner trust’s interest in Clover Unit 1, Virginia Power has an option to purchase that interest. If Virginia Power elects to purchase the interest but fails to pay the purchase price when due, we are obligated to make that payment, with interest, within 30 days.

If we elect not to purchase the owner trust’s interest in Clover Unit 1, we can arrange for a third-party to purchase the owner trust’s output of the unit at a price which will preserve the owner trust’s net economic return as if we had purchased the related unit at the purchase option price. To be an eligible power purchaser, the third-party must have, among other things, a net worth of at least $500.0 million and minimum specified credit ratings or other acceptable credit enhancement. We would assist in transmitting power to the third-party by entering into a transmission and interconnection agreement with the owner trust. We also would be obligated to assist the owner trust in arranging new financing for the lease debt which remains outstanding at the expiration of the leaseback. We would not be obligated, however, to provide this financing. If alternate financing is not available or we otherwise

 

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fail to satisfy the conditions to arrange for a new third-party purchaser, we must either exercise our purchase option or make a termination payment to the owner trust. We also must provide management services to the owner trust if power is being sold to the third-party.

As a third option, at the end of the term of the leaseback, we may pay to the owner trust an amount equal to the difference between a specified termination amount and the fair market value of its interest in Unit 1 and return possession of the interest in the unit back to the owner trust. The amount we are obligated to pay cannot exceed the specified termination amount minus 20% of the fair market value of the owner trust’s interest in the unit at the time the lease was entered into in 1996 or be less than the amount of the owner trust’s debt to its lenders at the expiration of the leaseback. If we do not purchase the interest and the owner trust requests, we are obligated to use our best efforts to sell the owner trust’s interest in the unit at the end of the leaseback. Any sale proceeds would be credited against the payment we are obligated to make to the owner trust. If we are not able to sell the interest by the end of the leaseback, we must pay the owner trust the full amount of the required payment but we are entitled to be reimbursed out of the proceeds of the sale in excess of 20% of the value of the owner trust’s interest at the time the lease was entered into in 1996, plus interest, if the facility is sold within the following 36 months.

Off-Balance Sheet Arrangements

Clover Unit 1

See “Significant Contingent Obligations—Clover Lease” above.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The operation of our business exposes us to several common market risks, including changes in market prices for power and fuel, and interest rates and equity prices.

Market Price Risk

We are exposed to market price risk by purchasing power to supply the power requirements of our member distribution cooperatives that are not met by our owned generation. See “Business—Power Supply Resources” in Item 1. In addition, the purchase of fuel to operate our generating facilities also exposes us to market price risk.

The fair value of the hedging instruments we use to mitigate market price risk is impacted by changes in market prices. At December 31, 2014, we estimate that the fair value of our purchased power agreements and forward sales of renewable energy credits, and forward purchases of energy and natural gas was between $1.8 billion and $1.9 billion. Approximately 22% of the fair value of this portfolio is estimable using observable market prices. The remaining 78% of the fair value of this portfolio is related to less liquid products and the fair values of these products are not directly estimable using observable market prices. In the absence of observable market prices, the valuation of the 78% of this portfolio that relates to less liquid products involves management judgment, the use of estimates, and the underlying assumptions in our portfolio model. As a result, changes in estimates and underlying assumptions or use of alternate valuation methods could affect the estimated fair value of this portfolio. As an example of our portfolio’s exposure to market price risk, it is estimated that a 10% change in the price of the commodities hedged by the portion of this portfolio with observable market prices would have changed the fair value of this portion of the portfolio by approximately $40.7 million at December 31, 2014. To the extent all or portions of our portfolio are liquidated above or below our original cost, these gains or losses are factored into the costs billed to our member distribution cooperatives pursuant to our formula rate. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting Results—Formula Rate” in Item 7.

 

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We have formulated policies and procedures to manage the risks associated with these market price fluctuations. Additionally, we use various hedging instruments, including forwards, futures, financial transmission rights, and options, to manage our power market price risks. ACES assists us in managing our market price risks by:

 

    maintaining a portfolio model that identifies our power producing resources (including our power purchase contract positions and generating capacity, and fuel supply, transportation, and storage arrangements) and analyzing the optimal use of these resources in light of costs and market risks associated with using these resources;

 

    modeling our power obligations and assisting us with analyzing alternatives to meet our member distribution cooperatives’ power requirements;

 

    selling excess power as our agent; and

 

    executing hedge trades to stabilize the cost of fuel requirements, primarily natural gas, used to operate our combustion turbine facilities.

We also are subject to market price risk relating to purchases of fuel for Clover and North Anna. We manage these risks indirectly through our participation in the management arrangements for these facilities. However, Virginia Power, as operator of these facilities, has the sole authority and responsibility to procure coal and nuclear fuel for Clover and North Anna, respectively.

Virginia Power advises us it uses both long-term contracts and short-term spot agreements to acquire the low sulfur bituminous coal used to fuel Clover. See “Business—Power Supply Resources—Fuel Supply—Coal” in Item 1.

Virginia Power advises us it primarily uses long-term contracts to support North Anna’s nuclear fuel requirements and that worldwide market conditions are continuously evaluated to ensure a range of supply options at reasonable prices which are dependent upon the market environment. See “Business—Power Supply Resources—Fuel Supply—Nuclear” in Item 1.

Interest Rate Risk and Equity Price Risk

In 2014, all of our outstanding long-term debt accrued interest at fixed rates.

We have a $500.0 million five-year revolving credit facility. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Sources—Revolving Credit Facility” in Item 7. Any amounts we borrow under this facility will accrue interest at a variable rate. At December 31, 2014, we had $86.0 million outstanding under this facility, which is recorded in revolving credit facility in the capitalization section of the balance sheet. The interest rate related to these borrowings is 1.5%. We also had a letter of credit in the amount of $10.0 million outstanding at December 31, 2014.

We accrue decommissioning costs over the expected service life of North Anna and have made periodic deposits to a trust so that the trust balance will cover the estimated cost to decommission North Anna at the time of decommissioning. At December 31, 2014, $45.2 million of the funds in the trust were invested in debt securities and $100.2 million of the funds in the trust were invested in equity securities. The value of these debt and equity securities will be impacted by changes in interest rates and price fluctuations in equity markets. To minimize adverse changes in the aggregate value of the trust, we actively monitor our portfolio by measuring the performance of the investments against market indices and by maintaining and reviewing established target allocation percentages of assets in the trust to various investment options. We believe the trust’s exposure to changes in interest rates and price fluctuations in equity markets will not have a material impact on our financial results.

 

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

CONSOLIDATED FINANCIAL STATEMENTS

INDEX

 

     Page
Number
 

Report of Management on ODEC’s Internal Control over Financial Reporting

     52   

Report of Independent Registered Public Accounting Firm

     53   

Consolidated Balance Sheets

     54   

Consolidated Statements of Revenues, Expenses, and Patronage Capital

     55   

Consolidated Statements of Cash Flows

     56   

Notes to Consolidated Financial Statements

     57   

 

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Report of Management on ODEC’s Internal Control over Financial Reporting

Management of Old Dominion Electric Cooperative (“ODEC”) has assessed ODEC’s internal control over financial reporting as of December 31, 2014, based on criteria for effective internal control over financial reporting described in the “2013 Internal Control – Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management believes that as of December 31, 2014, our system of internal control over financial reporting was properly designed and operating effectively based upon the specified criteria.

Management of ODEC is responsible for establishing and maintaining adequate internal control over financial reporting. ODEC’s internal control over financial reporting is comprised of policies, procedures, and reports designed to provide reasonable assurance to ODEC’s management and board of directors that the financial reporting and the preparation of the financial statements for external reporting purposes has been handled in accordance with accounting principles generally accepted in the United States. Internal control over financial reporting includes those policies and procedures that (1) govern records to accurately and fairly reflect the transactions and dispositions of assets of ODEC; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of ODEC are being made only in accordance with authorizations of the management and directors of ODEC; and (3) provide reasonable safeguards against or timely detection of material unauthorized acquisition, use or disposition of ODEC’s assets.

Internal controls over financial reporting may not prevent or detect all misstatements. Accordingly, even effective internal control can provide only reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles.

 

March 11, 2015

/s/ JACKSON E. REASOR

/s/ ROBERT L. KEES

Jackson E. Reasor Robert L. Kees
President and Chief Executive Officer Senior Vice President and Chief Financial Officer

 

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Report of Independent Registered Public Accounting Firm

The Board of Directors of

Old Dominion Electric Cooperative

We have audited the accompanying consolidated balance sheets of Old Dominion Electric Cooperative as of December 31, 2014 and 2013, and the related consolidated statements of revenues, expenses and patronage capital, and cash flows for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Cooperative’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Old Dominion Electric Cooperative at December 31, 2014 and 2013, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, in conformity with U.S. generally accepted accounting principles.

 

/s/ Ernst & Young LLP
Richmond, Virginia
March 11, 2015

 

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OLD DOMINION ELECTRIC COOPERATIVE

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2014 AND 2013

 

     2014     2013  
     (in thousands)  

ASSETS:

    

Electric Plant:

    

Property, plant, and equipment

   $ 1,690,555     $ 1,660,548  

Less accumulated depreciation

     (784,215     (755,288
  

 

 

   

 

 

 

Net Property, plant, and equipment

  906,340     905,260  

Nuclear fuel, at amortized cost

  19,376     23,636  

Construction work in progress

  171,953     36,482  
  

 

 

   

 

 

 

Net Electric Plant

  1,097,669     965,378  
  

 

 

   

 

 

 

Investments:

Nuclear decommissioning trust

  145,822     134,454  

Lease deposits

  99,191     96,634  

Unrestricted investments and other

  7,049     24,896  
  

 

 

   

 

 

 

Total Investments

  252,062     255,984  
  

 

 

   

 

 

 

Current Assets:

Cash and cash equivalents

  1,424     51,669  

Accounts receivable

  8,656     12,742  

Accounts receivable–deposits

  —        4,400  

Accounts receivable–members

  83,108     88,545  

Fuel, materials, and supplies

  64,154     49,246  

Deferred energy

  19,948     —     

Prepayments and other

  5,131     3,892  
  

 

 

   

 

 

 

Total Current Assets

  182,421     210,494  
  

 

 

   

 

 

 

Deferred Charges:

Regulatory assets

  87,987     87,983  

Other

  18,603     10,758  
  

 

 

   

 

 

 

Total Deferred Charges

  106,590     98,741  
  

 

 

   

 

 

 

Total Assets

$ 1,638,742   $ 1,530,597  
  

 

 

   

 

 

 

CAPITALIZATION AND LIABILITIES:

Capitalization:

Patronage capital

$ 379,097   $ 369,997  

Non-controlling interest

  5,687     5,691  
  

 

 

   

 

 

 

Total Patronage capital and Non-controlling interest

  384,784     375,688  

Long-term debt

  721,038     749,330  

Revolving credit facility

  86,000     —     
  

 

 

   

 

 

 

Total Long-term debt and Revolving credit facility

  807,038     749,330  
  

 

 

   

 

 

 

Total Capitalization

  1,191,822     1,125,018  
  

 

 

   

 

 

 

Current Liabilities:

Long-term debt due within one year

  28,292     28,292  

Accounts payable

  96,702     68,560  

Accounts payable–members

  35,217     24,998  

Accrued expenses

  4,568     4,991  

Deferred energy

  —        37,193  
  

 

 

   

 

 

 

Total Current Liabilities

  164,779     164,034  
  

 

 

   

 

 

 

Deferred Credits and Other Liabilities:

Asset retirement obligations

  104,936     80,860  

Obligations under long-term lease

  84,730     79,227  

Regulatory liabilities

  78,764     76,940  

Other

  13,711     4,518  
  

 

 

   

 

 

 

Total Deferred Credits and Other Liabilities

  282,141     241,545  
  

 

 

   

 

 

 

Commitments and Contingencies

  —        —     
  

 

 

   

 

 

 

Total Capitalization and Liabilities

$ 1,638,742   $ 1,530,597  
  

 

 

   

 

 

 

The accompanying notes are an integral part of the consolidated financial statements.

 

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OLD DOMINION ELECTRIC COOPERATIVE

CONSOLIDATED STATEMENTS OF REVENUES, EXPENSES, AND PATRONAGE CAPITAL

FOR THE YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

 

     2014     2013     2012  
     (in thousands)  

Operating Revenues

   $ 951,576     $ 842,069     $ 842,681  
  

 

 

   

 

 

   

 

 

 

Operating Expenses:

Fuel

  213,528     133,592     90,874  

Purchased power

  518,814     463,159     471,557  

Transmission

  75,959     66,590     66,189  

Deferred energy

  (57,141   (18,834   21,315  

Operations and maintenance

  49,599     41,546     42,615  

Administrative and general

  40,279     42,385     35,958  

Depreciation and amortization

  42,049     42,346     42,012  

Amortization of regulatory asset/(liability), net

  5,838     6,310     735  

Accretion of asset retirement obligations

  3,870     3,980     3,739  

Taxes, other than income taxes

  8,256     8,405     8,542  
  

 

 

   

 

 

   

 

 

 

Total Operating Expenses

  901,051     789,479     783,536  
  

 

 

   

 

 

   

 

 

 

Operating Margin

  50,525     52,590     59,145  

Other expense, net

  (3,086   (2,562   (2,224

Gain/(loss) on investments, net

  —        2,269     (2,156

Investment income

  7,349     5,333     4,129  

Interest charges, net

  (45,693   (47,680   (48,698

Income taxes

  1     (143   (93
  

 

 

   

 

 

   

 

 

 

Net Margin including Non-controlling interest

  9,096     9,807     10,103  

Non-controlling interest

  4     (234   (164
  

 

 

   

 

 

   

 

 

 

Net Margin attributable to ODEC

  9,100     9,573     9,939  

Patronage Capital - Beginning of Year

  369,997     360,424     350,485  
  

 

 

   

 

 

   

 

 

 

Patronage Capital - End of Year

$ 379,097   $ 369,997   $ 360,424  
  

 

 

   

 

 

   

 

 

 

The accompanying notes are an integral part of the consolidated financial statements.

 

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OLD DOMINION ELECTRIC COOPERATIVE

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2014, 2013, AND 2012

 

     2014     2013     2012  
     (in thousands)  

Operating Activities:

      

Net Margin including Non-controlling interest

   $ 9,096     $ 9,807     $ 10,103  

Adjustments to reconcile net margin to net cash provided by operating activities:

      

Depreciation and amortization

     42,049       42,346       42,012  

Other non-cash charges

     17,766       18,604       14,616  

Amortization of lease obligations

     5,503       5,141       4,801  

Interest on lease deposits

     (2,841     (2,774     (2,710

Change in current assets

     (2,224     (3,060     (2,861

Change in deferred energy

     (57,141     (18,834     21,315  

Change in current liabilities

     9,204       (20,555     (32,399

Change in regulatory assets and liabilities

     (2,467     (9,004     (248

Change in deferred charges-other and deferred credits and other liabilities-other

     (2,096     (1,564     (3,319
  

 

 

   

 

 

   

 

 

 

Net Cash Provided by Operating Activities

  16,849     20,107     51,310  
  

 

 

   

 

 

   

 

 

 

Investing Activities:

Purchases of held to maturity securities

  (3,931   (112,454   (103,420

Proceeds from sale of held to maturity securities

  21,746     143,605     91,278  

Purchases of available for sale securities

  —        —        (24,290

Proceeds from sale of available for sale securities

  —        —        24,308  

Increase in other investments

  (6,760   (7,468   (4,900

Electric plant additions

  (135,857   (32,093   (32,407
  

 

 

   

 

 

   

 

 

 

Net Cash Used for Investing Activities

  (124,802   (8,410   (49,431
  

 

 

   

 

 

   

 

 

 

Financing Activities:

Issuance of long-term debt

  —        100,000     —     

Debt issuance costs

  —        (744   —     

Payments of long-term debt

  (28,292   (88,827   (28,292

Dividend - non-controlling interest

  —        (7,800   —     

Draws on revolving credit facility

  387,604     —        —     

Repayments on revolving credit facility

  (301,604   —        —     
  

 

 

   

 

 

   

 

 

 

Net Cash Provided by (Used for) Financing Activities

  57,708     2,629     (28,292
  

 

 

   

 

 

   

 

 

 

Net Change in Cash and Cash Equivalents

  (50,245   14,326     (26,413

Cash and Cash Equivalents - Beginning of Year

  51,669     37,343     63,756  
  

 

 

   

 

 

   

 

 

 

Cash and Cash Equivalents - End of Year

$ 1,424   $ 51,669   $ 37,343  
  

 

 

   

 

 

   

 

 

 

The accompanying notes are an integral part of the consolidated financial statements.

 

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OLD DOMINION ELECTRIC COOPERATIVE

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—Summary of Significant Accounting Policies

General

The accompanying financial statements reflect the consolidated accounts of Old Dominion Electric Cooperative and TEC. In accordance with Consolidation Accounting, TEC is considered a variable interest entity for which we are the primary beneficiary. We have eliminated all intercompany balances and transactions in consolidation. During 2013, TEC refunded $7.8 million of equity to its owners in the form of a cash dividend. The assets and liabilities, and non-controlling interest of TEC are recorded at carrying value and the consolidated assets were $5.7 million at December 31, 2014 and December 31, 2013. The income taxes reported on our Consolidated Statements of Revenues, Expenses, and Patronage Capital relate to the tax provision for TEC. As TEC is 100% owned by our Class A members, its equity is presented as a non-controlling interest in our consolidated financial statements. Our non-controlling, 50% or less, ownership interest in other entities for which we have significant influence is recorded using the equity method of accounting. We have a power sales contract with TEC under which we may sell to TEC power that we do not need to meet the needs of our member distribution cooperatives. TEC then sells this power to the market under market-based rate authority granted by FERC. Additionally, we have a separate contract under which we may purchase natural gas from TEC. TEC does not engage in speculative trading.

We are a not-for-profit wholesale power supply cooperative, incorporated under the laws of the Commonwealth of Virginia in 1948. We have two classes of members. Our eleven Class A members are customer-owned electric distribution cooperatives engaged in the retail sale of power to customers located in Virginia, Delaware, and Maryland. Our sole Class B member, TEC, a taxable corporation, is owned by our member distribution cooperatives. Our board of directors is composed of two representatives from each of the member distribution cooperatives and one representative from TEC. Our rates are not regulated by the public service commissions of the states in which our member distribution cooperatives operate, but are set periodically by a formula that was accepted for filing by FERC.

We comply with the Uniform System of Accounts prescribed by FERC. In conformity with GAAP, the accounting policies and practices applied by us in the determination of rates are also employed for financial reporting purposes.

The preparation of our consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported therein. Actual results could differ from those estimates.

We did not have any other comprehensive income for the periods presented.

Electric Plant

Electric plant is stated at original cost when first placed in service. Such cost includes contract work, direct labor and materials, allocable overhead, an allowance for borrowed funds used during construction and asset retirement costs. Upon the partial sale or retirement of plant assets, the original asset cost and current disposal costs less sale proceeds, if any, are charged or credited to accumulated depreciation. In accordance with industry practice, no profit or loss is recognized in connection with normal sales and retirements of property units.

Maintenance and repair costs are expensed as incurred. Replacements and renewals of items considered to be units of property are capitalized to the property accounts.

 

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Depreciation

We conduct depreciation studies approximately every five years and our depreciation rates were as follows:

 

     Depreciation Rates  

Generating Facility

   2014     2013     2012  

Clover

     1.8     1.8     1.8

North Anna

     3.0        3.0        3.0   

Louisa

     3.5        3.5        3.5   

Marsh Run

     3.2        3.2        3.2   

Rock Springs

     3.3        3.3        3.3   

Our last depreciation study was performed in 2011.

Nuclear Fuel

Nuclear fuel is amortized on a unit of production basis sufficient to fully amortize the cost of fuel over its estimated service life and is recorded in fuel expense.

Virginia Power, as operating agent of North Anna, has the sole authority and responsibility to procure nuclear fuel for the facility. Virginia Power advises us that it primarily uses long-term contracts to support North Anna’s nuclear fuel requirements and that worldwide market conditions are continuously evaluated to ensure a range of supply options at reasonable prices which are dependent upon the market environment. We are not a direct party to any of these procurement contracts and we do not control their terms or duration. Virginia Power advises us that current agreements, inventories, and spot market availability are expected to support North Anna’s current and planned fuel supply needs for the near term and that additional fuel is purchased as required to attempt to ensure optimal cost and inventory levels.

Under the Nuclear Waste Policy Act of 1982, the DOE is required to provide for the permanent disposal of spent nuclear fuel produced by nuclear facilities, such as North Anna, in accordance with contracts executed with the DOE. The DOE did not begin accepting spent fuel in 1998 as specified in its contract. As a result, Virginia Power sought reimbursement for certain spent nuclear fuel-related costs incurred and in 2012 signed a settlement agreement with the DOE. By mutual agreement of the parties, the settlement agreement is extendable to provide for resolution of damages. The settlement agreement has been extended to provide for periodic payments for damages incurred through December 31, 2016. During 2014 and 2013, we recorded our proportionate share of $0.9 million and $1.8 million, respectively, as a reduction to fuel expense related to the settlement agreement and during 2014, we also recorded a $0.6 million reduction to property, plant, and equipment, as the settlement includes a reimbursement of costs related to fixed assets. At December 31, 2014 and 2013, we had an outstanding receivable of $3.3 million and $3.9 million, respectively.

Fuel, Materials, and Supplies

Fuel, materials, and supplies is primarily comprised of fuel and spare parts for our generating assets. Fuel, which consists primarily of coal and No. 2 fuel oil, is recorded at cost. Spare parts for our generating assets are recorded at cost.

Allowance for Borrowed Funds Used During Construction

Allowance for borrowed funds used during construction is defined as the net cost of borrowed funds used for construction purposes during the construction period and a reasonable rate on other funds when so used. We capitalize interest on borrowings for significant construction projects. Interest capitalized in 2014, 2013, and 2012, was $0.9 million, $0.2 million, and $1.0 million, respectively.

 

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Income Taxes

As a not-for-profit electric cooperative, we are currently exempt from federal income taxation under IRC Section 501(c)(12), and we intend to continue to operate in this manner. Based on our assessment and evaluations of relevant authority, we believe we could sustain treatment as a tax-exempt utility in the event of a challenge of our tax status. Accordingly, no provision for income taxes has been recorded based on ODEC’s operations in the accompanying consolidated financial statements.

TEC is a taxable corporation and its provision for income taxes was immaterial for the years ended December 31, 2014, 2013, and 2012.

Operating Revenues

Our operating revenues are derived from sales to our members and non-members and are recorded when power, including renewable energy credits, is delivered. We sell energy to our Class A members pursuant to long-term wholesale power contracts that we maintain with each of our member distribution cooperatives. These wholesale power contracts obligate each member distribution cooperative to pay us for power furnished in accordance with our rates. For the years ended December 31, 2014, 2013, and 2012, revenue from sales to our member distribution cooperatives, including the sale of renewable energy credits, was $908.0 million, $810.1 million, and $826.8 million, respectively. For the years ended December 31, 2014, 2013, and 2012, the sale of renewable energy credits included in revenue from sales to our member distribution cooperatives was $1.3 million and $1.4 million in 2014 and 2013, respectively, and was immaterial in 2012. See Note 5—Wholesale Power Contracts.

We sell excess purchased and generated energy, if any, to TEC, our Class B member, or to third parties under FERC market-based rate authority. Sales to TEC consist of sales of excess energy that we do not need to meet the actual needs of our member distribution cooperatives. TEC’s sales to third parties are reflected as non-member revenues; however, in 2014, 2013, and 2012, TEC had no sales to third parties. Excess purchased and generated energy that is not sold to TEC is sold to PJM under its rates for providing energy imbalance service, or to third parties. For the years ended December 31, 2014, 2013, and 2012, energy sales to non-members, including the sale of renewable energy credits, were $43.5 million, $31.9 million, and $15.9 million, respectively. For the years ended December 31, 2014, 2013, and 2012, the sale of renewable energy credits included in energy sales to non-members was $5.9 million, $6.1 million, and $0.5 million, respectively.

Formula Rate

Our power sales are comprised of two power products – energy and demand. Energy is the physical electricity delivered through transmission and distribution facilities to customers. We must have sufficient committed energy available to us for delivery to our member distribution cooperatives to meet their maximum energy needs at any time, with limited exceptions. This committed available energy at any time is referred to as demand.

The rates we charge our member distribution cooperatives for sales of energy and demand are determined by a formula rate accepted by FERC which is intended to permit collection of revenues which will equal the sum of:

 

    all of our costs and expenses;

 

    20% of our total interest charges; and

 

    additional equity contributions approved by our board of directors.

 

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The formula rate identifies the cost components that we can collect through rates, but not the actual amounts to be collected. With limited minor exceptions, we can change our rates periodically to match the costs we have incurred and we expect to incur without seeking FERC approval.

Energy costs, which are primarily variable costs, such as nuclear, coal, and natural gas fuel costs and the energy costs under our power purchase contracts with third parties, are recovered through two separate rates, the base energy rate and the energy adjustment rate. Through December 31, 2013, the base energy rate was a fixed rate that required FERC approval prior to adjustment. To the extent the base energy rate over- or under-collected our energy costs, we credited or charged the difference through an energy adjustment rate. We reviewed our energy costs at least every six months to determine whether the base energy rate and the current energy adjustment rate together were recovering our actual and anticipated energy costs and revised the energy adjustment rate accordingly. Effective January 1, 2014, pursuant to FERC’s acceptance of revisions to the formula rate as issued in FERC’s December 2, 2013 order, the base energy rate is no longer a fixed rate that requires FERC approval prior to adjustment. The base energy rate now is developed annually to collect energy costs as estimated in our budget including amounts in the deferred energy account from the prior year. As of January 1 of each year, the energy adjustment rate will be zero. With board approval, we can revise the energy adjustment rate at any time during the year if it becomes apparent that the combined base energy rate and the current energy adjustment rate are over-collecting or under-collecting our actual and anticipated energy costs. See “FERC Proceeding Related to Formula Rate” in “Legal Proceedings” in Part I, Item 3.

Demand costs, which are primarily fixed costs, such as depreciation expense, interest expense, administrative and general expenses, capacity costs under power purchase contracts with third parties, transmission costs, and our margin requirements and additional equity contributions approved by our board of directors are recovered through our demand rates. The formula rate allows us to change the actual demand rates we charge as our demand-related costs change, without FERC approval, with the exception of decommissioning cost, which is a fixed number in the formula rate that requires FERC approval prior to any adjustment. FERC approval is also needed to change account classifications currently in the formula or to add accounts not otherwise included in the current formula. Additionally, depreciation studies are required to be filed with FERC for its approval if they would result in a change in our depreciation rates. Through December 31, 2013, we collected our total demand costs through a single demand rate. Effective January 1, 2014, pursuant to FERC’s acceptance of the revisions to the formula rate as issued in FERC’s December 2, 2013 order, we now collect our total demand costs through the following three separate rates:

 

    Transmission service rate – designed to collect transmission-related and distribution-related costs;

 

    RTO capacity service rate – a proxy rate based on capacity prices in PJM which PJM allocates to ODEC and all other PJM members; and

 

    Remaining owned capacity service rate – recovers all remaining demand costs not billed and/or recovered under the transmission service and RTO capacity service rates.

As stated above, our margin requirements and additional equity contributions approved by our board of directors are recovered through our demand rates. We establish our demand rates to produce a net margin attributable to ODEC equal to 20% of our budgeted total interest charges plus additional equity contributions approved by our board of directors. Through December 31, 2013, utilizing Margin Stabilization, we adjusted our operating revenues to reflect actual demand costs incurred, including a net margin attributable to ODEC equal to 20% of actual interest charges plus additional equity contributions approved by our board of directors. Effective January 1, 2014:

 

   

At year end, if the actual net margin attributable to ODEC, excluding any budgeted additional equity contributions, equals more than 20% of our actual total interest charges, our board of directors may approve that, utilizing Margin Stabilization, revenues will be reduced by the amount of such excess margins, or that such excess margins will be retained as an additional equity

 

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contribution. For year-to-date interim reporting, if the actual net margin attributable to ODEC, excluding any budgeted additional equity contributions, equals more than 20% of our actual total interest charges, utilizing Margin Stabilization, revenues will be reduced by the amount of such excess margins.

 

    At year end and for year-to-date interim reporting, if the actual net margin attributable to ODEC, excluding any budgeted additional equity contributions, equals more than 10% but less than 20% of our actual total interest charges, no adjustment is recorded.

 

    At year end and for year-to-date interim reporting, if the actual net margin attributable to ODEC, excluding any budgeted additional equity contributions, equals less than 10% of our actual total interest charges, utilizing Margin Stabilization, revenues will be increased to produce a net margin attributable to ODEC, excluding any budgeted additional equity contributions, equal to 10% of our actual total interest charges.

For the year ended December 31, 2014, we did not record an adjustment to operating revenues utilizing Margin Stabilization, since the actual net margin attributable to ODEC, excluding any budgeted additional equity contributions, equaled 19.5% of our actual total interest charges. In accordance with our formula rate, no adjustment is recorded if the actual net margin attributable to ODEC, excluding any budgeted additional equity contributions, is more than 10% but less than 20% of our actual total interest charges. For the years ended December 31, 2013 and 2012, we recorded a reduction in operating revenues of $9.8 million and $15.0 million, respectively, utilizing Margin Stabilization, to produce a net margin equal to 20% of our actual total interest charges. See “Critical Accounting Policies—Margin Stabilization” above.

We may revise our budget at any time to the extent that our current budget does not accurately reflect our costs and expenses or estimates of our sales of power. Increases or decreases in our budget automatically amend the energy and/or the demand components of our formula rate, as necessary. The formula rate also permits us to adjust revenues from the member distribution cooperatives to equal our actual total demand costs. We make these adjustments under Margin Stabilization. See “Critical Accounting Policies—Margin Stabilization” above. If at any time our board of directors determines that the formula does not meet all of our costs and expenses, it may adopt a new formula to meet those costs and expenses, subject to any necessary regulatory review and approval.

Regulatory Assets and Liabilities

We account for certain revenues and expenses as a rate-regulated entity in accordance with Accounting for Regulated Operations. This allows certain of our revenues and expenses to be deferred at the discretion of our board of directors, which has budgetary and rate setting authority, if it is probable that these amounts will be recovered or returned through our formula rate in future periods. Regulatory assets represent costs that we expect to recover from our member distribution cooperatives based on rates approved by our board of directors in accordance with our formula rate. Regulatory liabilities represent probable future reductions in our revenues associated with amounts that we expect to return to our member distribution cooperatives based on rates approved by our board of directors in accordance with our formula rate. Regulatory assets are included in deferred charges and regulatory liabilities are included in deferred credits and other liabilities. Deferred energy, which can be either a regulatory asset or a regulatory liability, is included in current assets or current liabilities, respectively. See “Deferred Energy” below. We recognize regulatory assets and liabilities as expenses or as a reduction in expenses, respectively, concurrent with their recovery through rates.

Debt Issuance Costs

Capitalized costs associated with the issuance of long-term debt and the revolving credit facility totaled $6.7 million at December 31, 2014 and 2013, and are included in deferred charges – other. These costs are being amortized using the effective interest method over the life of the respective long-term debt issuances and the revolving credit facility, and are included in interest charges, net.

 

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Deferred Charges – Other

Deferred charges – other, includes unamortized debt issuance costs, the deferred rent related to the Wildcat Point operating lease, NYMEX margin mark-to-market asset, and the long-term portion of the prepayment of premiums on an insurance policy related to Wildcat Point.

Deferred Credits and Other Liabilities – Other

Deferred credits and other liabilities – other, includes NYMEX margin mark-to-market liability, Wildcat Point retainage, a gain on a long-term lease transaction (see Note 8—Long-term Lease Transaction), DOE decontamination and decommissioning liability, and liabilities associated with benefit plans for certain executives.

Deferred Energy

We use the deferral method of accounting to recognize differences between our energy expenses and our energy revenues collected from our member distribution cooperatives. The deferred energy balance represents the net accumulation of any under- or over-collection of energy costs. At December 31, 2014, we had an under-collected deferred energy balance of $19.9 million. At December 31, 2013, we had an over-collected deferred energy balance of $37.2 million. In January 2014, the entire mid-Atlantic region experienced extremely cold weather, which increased our member distribution cooperatives’ customers’ requirements for power as well as increased our purchased power and fuel expenses. As a result, our deferred energy balance changed from an over-collection of energy costs to an under-collection of energy costs. To address the under-collection of energy costs, we increased our total energy rate 11.8% effective April 1, 2014, and an additional 2.4% effective October 1, 2014. Under-collected deferred energy balances will be collected from our member distribution cooperatives in subsequent periods through our formula rate. Over-collected deferred energy balances are refunded to our member distribution cooperatives in subsequent periods.

Financial Instruments (including Derivatives)

Investments included in the nuclear decommissioning trust are classified as available for sale, and accordingly, are carried at fair value. Unrealized gains and losses on investments held in the nuclear decommissioning trust are deferred as a regulatory liability or a regulatory asset, respectively, until realized.

Unrestricted investments and lease deposits in debt securities that we have the positive intent and ability to hold to maturity are classified as held to maturity and are recorded at amortized cost. Non-marketable equity investments in other investments are recorded at cost. Equity securities in other investments are recorded at fair value. See Note 9—Investments.

We primarily purchase power under both long-term and short-term physically-delivered forward contracts to supply power to our member distribution 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 provided for under Accounting for Derivatives and Hedging. As a result, these contracts are not recorded at fair value. We record a liability and purchased power expense when the power under the physically-delivered forward contract is delivered. We also purchase natural gas futures generally for three years or less to hedge the price of natural gas for the operation of our combustion turbine facilities. These derivatives do not qualify for the normal purchases/normal sales exception.

For all derivative contracts that do not qualify for the normal purchases/normal sales accounting exception, we may elect cash flow hedge accounting in accordance with Accounting for Derivatives and Hedging. Accordingly, gains and losses on derivative contracts are deferred into other comprehensive income until the hedged underlying transaction occurs or is no longer likely to occur. We do not have any other comprehensive income for the periods presented. For derivative contracts where hedge accounting is not utilized, or for which ineffectiveness exists, we defer all remaining gains and losses on a net basis as a regulatory asset or regulatory liability,

 

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respectively, in accordance with Accounting for Regulated Operations. These amounts are subsequently reclassified as purchased power or fuel expense in our Consolidated Statements of Revenues, Expenses, and Patronage Capital as the power or fuel is delivered and/or the contract settles. There were no contracts for which we have elected cash flow hedge accounting and therefore, there was no hedge ineffectiveness during the years ended December 31, 2014, 2013, or 2012.

Generally, derivatives are reported at fair value on the Consolidated Balance Sheet in the regulatory assets or regulatory liabilities account and deferred charges–other and deferred credits and other liabilities–other. The measurement of fair value is based on actively quoted market prices, if available. Otherwise, we seek indicative price information 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.

Patronage Capital

We are organized and operate as a cooperative. Patronage capital represents our retained net margins, which have been allocated to our members based upon their respective power purchases in accordance with our bylaws. Any distributions of patronage capital are subject to the discretion of our board of directors and the restrictions contained in our Indenture and our syndicated credit agreement. See Note 11—Long-term Debt for discussion of the restrictions contained in the Indenture.

Concentrations of Credit Risk

Financial instruments that potentially subject us to concentrations of credit risk consist of cash equivalents, investments, derivatives, and receivables arising from sales to our members and non-members. Concentrations of credit risk with respect to receivables arising from sales to our member distribution cooperatives as reflected by accounts receivable–members were $83.1 million and $88.5 million, at December 31, 2014 and 2013, respectively.

Segment

We are organized for the purpose of supplying the power our member distribution cooperatives require to serve their customers on a cost-effective basis. Our President and CEO serves as our chief operating decision maker who manages and reviews our operating results as one operating, and therefore one reportable, segment. We supply our member distribution cooperatives’ energy and demand requirements through a portfolio of resources including generating facilities, physically-delivered forward power purchase contracts, and spot market energy purchases.

Cash Equivalents

For purposes of our Consolidated Statements of Cash Flows, we consider all unrestricted highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents.

Reclassifications

Certain reclassifications have been made to the prior years’ consolidated financial statements to conform to the current year’s presentation.

 

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NOTE 2—Electric Plant

Our net electric plant is comprised of the following for 2014:

 

     Clover     North
Anna
    Combustion
Turbine
Facilities
    Wildcat
Point
     Other     Total  
     (in thousands)  

Property, plant, and equipment

   $ 678,006     $ 351,636     $ 587,955     $ —         $ 72,958     $ 1,690,555  

Accumulated depreciation

     (352,271     (190,317     (218,020     —           (23,607     (784,215
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 

Net Property, plant, and equipment

  325,735     161,319     369,935     —        49,351     906,340  

Nuclear fuel, at amortized cost

  —        19,376     —        —        —        19,376  

Construction work in progress

  11,364     33,580     —        115,779     11,230     171,953  
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 

Net Electric Plant

$ 337,099   $ 214,275   $ 369,935   $ 115,779   $ 60,581   $ 1,097,669  
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 

Our net electric plant is comprised of the following for 2013:

 

     Clover     North
Anna
    Combustion
Turbine
Facilities
    Other     Total  
     (in thousands)  

Property, plant, and equipment (1)

   $ 671,708     $ 335,151     $ 585,067     $ 68,622     $ 1,660,548  

Accumulated depreciation

     (349,197     (184,314     (198,520     (23,257     (755,288
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net Property, plant, and equipment

  322,511     150,837     386,547     45,365     905,260  

Nuclear fuel, at amortized cost

  —        23,636     —        —        23,636  

Construction work in progress

  6,670     20,536     —        9,276     36,482  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net Electric Plant

$ 329,181   $ 195,009   $ 386,547   $ 54,641   $ 965,378  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1)  Other includes $6.0 million related to Wildcat Point and $3.1 million for transmission.

We hold a 50% undivided ownership interest in Clover, a two-unit, 874 MW (net capacity entitlement) coal-fired electric generating facility operated by Virginia Power, which owns the balance of the plant. We are responsible for and must fund half of all additions and operating costs associated with Clover, as well as half of Virginia Power’s administrative and general expenses directly attributable to Clover. Our portion of assets, liabilities, and operating expenses associated with Clover are included in our consolidated financial statements in accordance with proportionate consolidation accounting. At December 31, 2014 and 2013, we had an outstanding accounts payable balance of $11.4 million and $12.7 million, respectively, due to Virginia Power for operation, maintenance, and capital investment at Clover.

We hold an 11.6% undivided ownership interest in North Anna, a two-unit, 1,897 MW (net capacity entitlement) nuclear power facility operated by Virginia Power, which owns the balance of the plant. We are responsible for and must fund 11.6% of all post-acquisition date additions and operating costs associated with North Anna, as well as a pro-rata portion of Virginia Power’s administrative and general expenses directly attributable to North Anna. Our portion of assets, liabilities, and operating expenses associated with North Anna are included in our consolidated financial statements in accordance with proportionate consolidation accounting. At December 31, 2014 and 2013, we had an outstanding accounts payable balance of $3.1 million and $4.1 million, respectively, due to Virginia Power for the operation, maintenance, and capital investment at North Anna.

We own three combustion turbine facilities that are carried at cost, less accumulated depreciation. We also own distributed generation facilities, which are included in “Other” in the net electric plant table. Additionally, we own approximately 100 miles of transmission lines on the Virginia portion of the Delmarva Peninsula included in “Other,” as well as two 1,100 foot 500 kV transmission lines and a 500 kV substation at our combustion turbine site in Maryland included in “Combustion Turbine Facilities.”

 

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Wildcat Point

We are currently constructing, and will be the sole owner of, an approximate 1,000 MW natural gas-fueled generation facility, named Wildcat Point, in Cecil County, Maryland. The development, construction, and operation of Wildcat Point are subject to obtainment of necessary governmental and regulatory approvals. On April 8, 2014, we received a Final Order granting approval of the CPCN from the MPSC. On June 2, 2014, we selected White Oak Power Constructors as the EPC contractor. Site preparation and engineering activities are in process, and permanent construction began in January 2015. The facility is scheduled to become operational in mid-2017. We currently have a ground lease related to the land associated with Wildcat Point and are currently accounting for it as an operating lease. Once Wildcat Point becomes operational, the lease will be reevaluated and likely will become a capital lease. We currently anticipate that the project cost will be approximately $790.5 million, including capitalized interest, but excluding the lease. To fund a portion of the project cost, on January 15, 2015, we issued $332.0 million of first mortgage bonds in a private placement transaction. See Note 12—Liquidity Resources.

Wildcat Point will consist of two combustion turbines, two heat recovery steam generators and one steam turbine generator. Mitsubishi will supply the combustion turbines. Alstom will supply the heat recovery steam generators and the steam turbine generator. Beginning in June 2014, following the approval of the CPCN and our selection of the EPC contractor, we began capitalizing all construction-related costs related to Wildcat Point. Through December 31, 2014, we capitalized construction costs related to Wildcat Point totaling $115.8 million, which are recorded in construction work in progress. In January 2015, we began capitalizing interest with respect to the facility upon commencement of permanent construction. For 2014 and 2013, we expensed $4.5 million and $7.7 million, respectively, of non-capital costs related to Wildcat Point, which are recorded in administrative and general expense.

NOTE 3—Accounting for Asset Retirement and Environmental Obligations

We account for our asset retirement obligations in accordance with Accounting for Asset Retirement and Environmental Obligations. This requires that legal obligations associated with the retirement of long-lived assets be recognized at fair value when incurred and capitalized as part of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized asset is depreciated over the useful life of the long-lived asset.

In the absence of quoted market prices, we estimate the fair value of our asset retirement obligations by using present value techniques, in which estimates of future cash flows associated with retirement activities are discounted using a credit-adjusted risk-free rate. Our estimated liability could change significantly if actual costs vary from assumptions or if governmental regulations change significantly.

A significant portion of our asset retirement obligations relate to our share of the future costs to decommission North Anna. At December 31, 2014 and 2013, North Anna’s nuclear decommissioning asset retirement obligation totaled $93.7 million and $72.1 million, respectively. Approximately every four years, a new decommissioning study for North Anna is performed by third-party experts. A new study was performed in 2014, and we adopted it effective December 1, 2014, which resulted in an additional layer related to the asset retirement obligation associated with North Anna. The additional layer resulted in an increase to our asset retirement cost and our asset retirement obligation of $18.0 million. Increased spent fuel costs, including interim storage, insurance premiums, and regulatory and environmental permits and fees, as a result of the DOE delay for acceptance of spent fuel, is the primary driver for the increase in the asset retirement obligation. We are not aware of any events that have occurred since the 2014 study that would materially impact our estimate. We are required to maintain a funded trust to satisfy our future obligation to decommission the North Anna facility. See Note 9—Investments. We are currently evaluating the impact of the 2014 study on the funding status of our nuclear decommissioning trust.

 

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In 2014, we established two additional asset retirement obligations for Clover ash landfills and also determined that we no longer had an asset retirement obligation for a waste pond for Clover.

The following represents changes in our asset retirement obligations for the years ended December 31, 2014 and 2013 (in thousands):

 

Asset retirement obligations at December 31, 2012

$ 76,880  

Accretion expense

  3,980  
  

 

 

 

Asset retirement obligations at December 31, 2013

$ 80,860  

Accretion expense

  3,870  

Increase in asset retirement obligations - new layer

  17,953  

Additional asset retirement obligations, net

  2,253  
  

 

 

 

Asset retirement obligations at December 31, 2014

$ 104,936  
  

 

 

 

The cash flow estimates for North Anna’s asset retirement obligations are based upon the 20-year life extension which was granted in 2003 and extends the life of Unit 1 to April 1, 2038 and the life of Unit 2 to August 21, 2040. Given the life extension in 2003, the nuclear decommissioning trust was, and currently is, estimated to be adequate to fund North Anna’s asset retirement obligations and no additional funding was, or is, currently required. We ceased collection of decommissioning expense in August 2003 with the approval of FERC. As we are not currently collecting decommissioning expense in our rates, we are deferring the difference between the earnings on the nuclear decommissioning trust and the total asset retirement obligation related depreciation and accretion expense for North Anna as part of our asset retirement obligation regulatory liability. See Note 10—Regulatory Assets and Liabilities.

NOTE 4—Power Purchase Agreements

In 2014, 2013, and 2012, our owned generating facilities together furnished approximately 40.2%, 39.4%, and 33.4%, respectively, of our energy requirements. The remaining needs were satisfied through purchases of power in the market from investor owned utilities and power marketers through long-term and short-term physically-delivered forward power purchase contracts. We also purchase power in the spot energy market. This approach to meeting our member distribution cooperatives’ energy requirements is not without risks. To mitigate these risks, we attempt to match our energy purchases with our energy needs to reduce our spot market purchases of energy. Additionally, we utilize policies, procedures, and various hedging instruments to manage our power market price risks. These policies and procedures, developed in consultation with ACES, an energy trading and risk management company, are designed to strike an appropriate balance between minimizing costs and reducing energy cost volatility. At December 31, 2014, we were not required to post collateral with our counterparties. At December 31, 2013, due to changes in energy prices, we were required to post $4.4 million with our counterparties pursuant to contracts we had in place with them.

Our purchased power costs for 2014, 2013, and 2012 were $518.8 million, $463.2 million, and $471.6 million, respectively.

 

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As of December 31, 2014, our energy and capacity purchase obligations under the various agreements were as follows:

 

Year Ending December 31,

   Energy and
Capacity
Obligations
 
     (in millions)  

2015

   $ 279.8   

2016

     200.3   

2017

     161.5   
  

 

 

 
$ 641.6   
  

 

 

 

NOTE 5—Wholesale Power Contracts

We have a wholesale power contract with each of our eleven member distribution cooperatives. The wholesale power contracts are “all-requirements” contracts. Each contract obligates us to sell and deliver to the member distribution cooperative, and obligates the member distribution cooperative to purchase and receive from us, all power that it requires for the operation of its system, with limited exceptions, to the extent that we have the power and facilities available to do so. These contracts are effective until January 1, 2054 and beyond this date unless either party gives the other at least three years notice of termination.

The principal exception to the all-requirements obligations of the member distribution cooperatives relates to the ability of our eight mainland Virginia member distribution cooperatives to purchase hydroelectric power allocated to them from SEPA. Purchases under this exception constituted approximately 1.4% of our member distribution cooperatives’ total energy requirements in 2014.

Two additional limited exceptions to the all-requirements nature of the contract permit the member distribution cooperatives to receive up to the greater of 5.0% of their power requirements or 5 MW from owned generation or other suppliers, and to purchase additional power from other suppliers in limited circumstances following approval by our board of directors. In 2014, our member distribution cooperatives collectively received 8.7 MW under these exceptions. We do not anticipate that this will have a material impact on our financial condition, results of operations, or cash flows.

Each member distribution cooperative is required to pay us monthly for power furnished under its wholesale power contract in accordance with our formula rate. The formula rate, which has been filed with and accepted by FERC, is designed to recover our total cost of service and create a firm equity base. More specifically, the formula rate is intended to meet all of our costs, expenses, and financial obligations associated with our ownership, operation, maintenance, repair, replacement, improvement, modification, retirement, and decommissioning of our generating plants, transmission system, or related facilities, services provided to the member distribution cooperatives, and the acquisition and transmission of power or related services, including:

 

    payments of principal and premium, if any, and interest on all indebtedness issued by us (other than payments resulting from the acceleration of the maturity of the indebtedness);

 

    any additional cost or expense, imposed or permitted by any regulatory agency; and

 

    additional amounts necessary to meet the requirement of any rate covenant with respect to coverage of principal and interest on our indebtedness contained in any indenture or contract with holders of our indebtedness.

The rates established under the wholesale power contracts are designed to enable us to comply with financing, regulatory, and governmental requirements, which apply to us from time to time.

 

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Revenues from our member distribution cooperatives for the past three years were as follows:

 

     Year Ended December 31,  
     2014      2013      2012  
     (in millions)  

Rappahannock Electric Cooperative

   $ 311.7      $ 275.9      $ 280.4  

Shenandoah Valley Electric Cooperative

     172.1        150.4        152.1  

Delaware Electric Cooperative, Inc.

     106.8        94.7        95.4  

Choptank Electric Cooperative, Inc.

     80.2        72.1        75.9  

Southside Electric Cooperative

     70.2        64.5        66.0  

A&N Electric Cooperative

     53.0        47.8        48.4  

Mecklenburg Electric Cooperative

     43.8        39.7        40.6  

Prince George Electric Cooperative

     23.5        21.6        22.1  

Northern Neck Electric Cooperative

     21.3        19.5        19.7  

Community Electric Cooperative

     15.3        13.9        14.1  

BARC Electric Cooperative

     10.1        10.0        12.1  
  

 

 

    

 

 

    

 

 

 

Total

$ 908.0   $ 810.1   $ 826.8  
  

 

 

    

 

 

    

 

 

 

NOTE 6Fair Value Measurements

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability.

 

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The following table summarizes our financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2014 and 2013:

 

     December 31,
2014
     Quoted Prices
in Active
Markets for
Identical
Assets

(Level 1)
     Significant
Other
Observable
Inputs

(Level 2)
     Significant
Unobservable
Inputs

(Level 3)
 
     (in thousands)  

Nuclear decommissioning trust (1)(2)

   $ 145,822      $ 45,573      $ 100,249      $ —     

Unrestricted investments and other (3)

     198        —           198        —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Financial Assets

$ 146,020   $ 45,573   $ 100,447   $ —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Derivatives - gas and power (4)

$ 5,215   $ 5,215   $ —      $ —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Financial Liabilities

$ 5,215   $ 5,215   $ —      $ —     
  

 

 

    

 

 

    

 

 

    

 

 

 

 

     December 31,
2013
     Quoted Prices
in Active
Markets for
Identical
Assets

(Level 1)
     Significant
Other
Observable
Inputs
(Level 2)
     Significant
Unobservable
Inputs

(Level 3)
 
     (in thousands)  

Nuclear decommissioning trust (1)(2)

   $ 134,454      $ 42,661      $ 91,793      $ —     

Unrestricted investments and other (3)

     173        173        —           —     

Derivatives - gas and power (4)

     412        412        —           —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Financial Assets

$ 135,039   $ 43,246   $ 91,793   $ —     
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) For additional information about our nuclear decommissioning trust see Note 9—Investments.
(2) Nuclear decommissioning trust includes investments that are available for sale and classified as Level 2. These Level 2 assets consist of an equity fund that attempts to replicate the return of the S&P 500, an equity fund that invests in small capitalization stocks, and an equity fund that invests in international stocks. The fair values of the investments in the nuclear decommissioning trust have been estimated using the net asset value per share.
(3) Unrestricted investments and other includes investments that are related to equity securities.
(4) Derivatives – gas and power represent natural gas futures contracts which are recorded on our Consolidated Balance Sheet in either deferred charges-other or deferred credits and other liabilities–other, and which are indexed against NYMEX. For additional information about our derivative financial instruments see Note 1—Summary of Significant Accounting Policies.

We did not have any financial assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category.

NOTE 7Derivatives and Hedging

We are exposed to market price risk by purchasing power to supply the power requirements of our member distribution cooperatives that are not met by our owned generation. In addition, the purchase of fuel to operate our generating facilities also exposes us to market price risk. To manage this exposure, we utilize derivative instruments. See Note 1—Summary of Significant Accounting Policies.

Changes in the fair value of our derivative instruments accounted for at fair value are recorded as a regulatory asset or regulatory liability. The change in these accounts is included in the operating activities section of our Consolidated Statements of Cash Flows.

 

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Excluding contracts accounted for as normal purchase/normal sale, we had the following outstanding derivative instruments:

 

Commodity

   Unit of Measure    As of
December 31, 2014
Quantity
     As of
December 31, 2013
Quantity
 

Natural Gas

   MMBTU      5,610,000         1,470,000   

The fair value of our derivative instruments, excluding contracts accounted for as normal purchase/normal sale, was as follows:

 

          Fair Value  
     Balance Sheet Location    As of
December 31,

2014
     As of
December 31,

2013
 
          (in thousands)  

Derivatives in an asset position:

        

Natural gas futures contracts

   Deferred charges-other    $ —         $ 412   
     

 

 

    

 

 

 

Total derivatives in an asset position

$ —      $ 412   
     

 

 

    

 

 

 

Derivatives in a liability position:

Natural gas futures contracts

Deferred credits and
other liabilities-other
$ 5,215    $ —     
     

 

 

    

 

 

 

Total derivatives in a liability position

$ 5,215    $ —     
     

 

 

    

 

 

 

The Effect of Derivative Instruments on the Statements of Revenues, Expenses, and Patronage Capital for the Years Ended December 31, 2014 and 2013

 

Derivatives Accounted for Utilizing Regulatory Accounting

   Amount of
Gain (Loss)
Recognized in
Regulatory

Asset/Liability for
Derivatives as of
December 31,
     Location of Gain
(Loss) Reclassified
from Regulatory
Asset/Liability into
Income
   Amount of Gain
(Loss) Reclassified
from Regulatory
Asset/Liability into
Income for the

Year Ended
December 31,
 
     2014     2013           2014     2013  
     (in thousands)           (in thousands)  

Natural gas futures contracts (1)

   $ (5,497   $ 419      Fuel    $ (1,170   $ (3,031

Purchased power contracts - excess sales

     —          —         Operating revenues      90       —     
  

 

 

   

 

 

       

 

 

   

 

 

 

Total

$ (5,497 $ 419   $ (1,080 $ (3,031
  

 

 

   

 

 

       

 

 

   

 

 

 

 

(1)  As of December 31, 2014, includes a regulatory liability of $0.3 million and as of December 31, 2013, includes a regulatory asset of $7.0 thousand, to be recognized in future periods as the result of the contracts being effectively settled.

 

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NOTE 8—Long-term Lease Transaction

On March 1, 1996, we entered into a long-term lease transaction with an owner trust for the benefit of an investor. Under the terms of the transaction, we entered into a 48.8 year lease of our interest in Clover Unit 1, valued at $315.0 million, to such owner trust, and immediately after we entered into a 21.8 year lease of the interest back from such owner trust. As a result of the transaction, we recorded a deferred gain of $23.7 million, which is being amortized into income ratably over the 21.8 year operating lease term, as a reduction to depreciation and amortization expense. At December 31, 2014 and 2013, the unamortized portion of the deferred gain was $3.2 million and $4.3 million, respectively.

We used a portion of the one-time rental payment of $315.0 million we received to enter into a payment undertaking agreement and to purchase an investment that would provide for substantially all of our periodic rent payments under the leaseback, and the fixed purchase price of the interest in the unit at the end of the term of the leaseback if we were to exercise our option to purchase the interest of the owner trust in the unit at that time. The payment undertaking agreement, which had a balance of $308.5 million at December 31, 2014, is issued by Rabobank, which has senior debt obligations which are currently rated “A+” by S&P and “Aa2” by Moody’s, respectively. The amount of debt considered to be extinguished by in substance defeasance was $308.5 million and $309.7 million, at December 31, 2014 and 2013, respectively.

At the end of the term of the leaseback, we have three options: (1) retain possession of the interest in the unit by paying a fixed purchase price to the owner trust, (2) return possession of the interest to the owner trust and arrange for an acceptable third-party to enter into a power purchase agreement with the owner trust, or (3) return possession of the interest and pay a termination amount to the owner trust.

 

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NOTE 9—Investments

Investments were as follows at December 31, 2014 and 2013:

 

Description

  

Designation

   Cost      Gross
Unrealized
Gains
     Gross
Unrealized
Losses
    Fair Value      Carrying
Value
 
          (in thousands)  

December 31, 2014

                

Nuclear decommissioning trust (1)

                

Debt securities

   Available for sale    $ 41,654      $ 3,516      $ —        $ 45,170      $ 45,170  

Equity securities

   Available for sale      68,259        31,990        —          100,249        100,249  

Cash and other

   Available for sale      403        —           —          403        403  
     

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Total Nuclear Decommissioning Trust

$ 110,316   $ 35,506   $ —      $ 145,822   $ 145,822  
     

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Lease Deposits (2)

Government obligations

Held to maturity $ 99,191   $ 5,569   $ —      $ 104,760   $ 99,191  
     

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Total Lease Deposits

$ 99,191   $ 5,569   $ —      $ 104,760   $ 99,191  
     

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Unrestricted investments

Government obligations

Held to maturity $ 2,005   $ —      $ —      $ 2,005   $ 2,005  

Debt securities

Held to maturity   2,636     —        (18   2,618     2,636  
     

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Total Unrestricted Investments

$ 4,641   $ —      $ (18 $ 4,623   $ 4,641  
     

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Other

Equity securities

Trading $ 151   $ 47   $ —      $ 198   $ 198  

Non-marketable equity investments

Equity   2,210     1,821     —        4,031     2,210  
     

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Total Other

$ 2,361   $ 1,868   $ —      $ 4,229   $ 2,408  
     

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 
$ 252,062  
                

 

 

 

December 31, 2013

Nuclear decommissioning trust (1)

Debt securities

Available for sale $ 40,352   $ 1,719   $ —      $ 42,071   $ 42,071  

Equity securities

Available for sale   62,293     29,500     —        91,793     91,793  

Cash and other

Available for sale   590     —        —        590     590  
     

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Total Nuclear Decommissioning Trust

$ 103,235   $ 31,219   $ —      $ 134,454   $ 134,454  
     

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Lease Deposits (2)

Government obligations

Held to maturity $ 96,634   $ 5,676   $ —      $ 102,310   $ 96,634  
     

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Total Lease Deposits

$ 96,634   $ 5,676   $ —      $ 102,310   $ 96,634  
     

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Unrestricted investments

Government obligations

Held to maturity $ 20,174   $ 1   $ —      $ 20,175   $ 20,174  

Debt securities

Held to maturity   2,200     —        (4   2,196     2,200  
     

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Total Unrestricted Investments

$ 22,374   $ 1   $ (4 $ 22,371   $ 22,374  
     

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Other

Equity securities

Trading $ 131   $ 42   $ —      $ 173   $ 173  

Non-marketable equity investments

Equity   2,349     1,735     —        4,084     2,349  
     

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Total Other

$ 2,480   $ 1,777   $ —      $ 4,257   $ 2,522  
     

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 
$ 255,984  
                

 

 

 

 

(1)  Investments in the nuclear decommissioning trust are restricted for the use of funding our share of the asset retirement obligations of the future decommissioning of North Anna. See Note 3—Accounting for Asset Retirement and Environmental Obligations. Unrealized gains and losses related to assets held in the nuclear decommissioning trust are deferred as a regulatory asset or liability, respectively.
(2)  Investments in lease deposits are restricted for the use of funding our future lease obligations. See Note 8—Long-term Lease Transaction.

 

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Our investments by classification at December 31, 2014 and 2013, were as follows:

 

     December 31, 2014      December 31, 2013  

Description

   Cost      Carrying
Value
     Cost      Carrying
Value
 
     (in thousands)  

Available for sale

   $ 110,316      $ 145,822      $ 103,235      $ 134,454  

Held to maturity

     103,832        103,832        119,008        119,008  

Equity

     2,210        2,210        2,349        2,349  

Trading

     151        198        131        173  
  

 

 

    

 

 

    

 

 

    

 

 

 
$ 216,509   $ 252,062   $ 224,723   $ 255,984  
  

 

 

    

 

 

    

 

 

    

 

 

 

Contractual maturities of debt securities at December 31, 2014, were as follows:

 

Description

   Less than
1 year
     1-5 years      5-10 years      More than
10 years
     Total  
     (in thousands)  

Available for sale (1)

   $ —         $ —         $ 45,170      $ —         $ 45,170  

Held to maturity

     519        103,233        80        —           103,832  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
$ 519   $ 103,233   $ 45,250   $ —      $ 149,002  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1)  The contractual maturities of available for sale debt securities are measured using the effective duration of the bond fund within the nuclear decommissioning trust.

 

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NOTE 10—Regulatory Assets and Liabilities

In accordance with Accounting for Regulated Operations, we record regulatory assets and liabilities that result from our ratemaking. Our regulatory assets and liabilities at December 31, 2014 and 2013, were as follows:

 

     December 31,  
     2014      2013  
     (in thousands)  

Regulatory Assets:

     

Unamortized losses on reacquired debt

   $ 15,571      $ 17,435  

Deferred asset retirement costs

     346        363  

NOVEC contract termination fee

     34,256        36,703  

Loan acquisition fee

     671        894  

Interest rate hedge

     2,710        2,879  

North Anna Unit 3

     22,748        22,748  

Voluntary prepayment to NRECA Retirement Security Plan

     6,188        6,961  

Deferred net unrealized losses on derivative instruments

     5,497        —     
  

 

 

    

 

 

 

Total Regulatory Assets

$ 87,987   $ 87,983  
  

 

 

    

 

 

 

Regulatory Assets included in Current Assets:

Deferred energy

$ 19,948   $ —     

Regulatory Liabilities:

North Anna asset retirement obligation deferral

$ 42,733   $ 39,581  

Norfolk Southern settlement

  —        5,136  

North Anna nuclear decommissioning trust unrealized gain

  35,506     31,220  

Unamortized gains on reacquired debt

  525     584  

Deferred net unrealized gains on derivative instruments

  —        419  
  

 

 

    

 

 

 

Total Regulatory Liabilities

$ 78,764   $ 76,940  
  

 

 

    

 

 

 

Regulatory Liabilities included in Current Liabilities:

Deferred energy

$ —      $ 37,193  

The regulatory assets will be recognized as expenses concurrent with their recovery through rates and the regulatory liabilities will be recognized as a reduction to expenses concurrent with their return through rates.

Regulatory assets included in deferred charges are detailed as follows:

 

  Unamortized losses on reacquired debt are the costs we incurred to purchase our outstanding indebtedness prior to its scheduled retirement. These losses are amortized over the life of the original indebtedness and will be fully amortized in 2023.

 

  Deferred asset retirement costs reflect the cumulative effect of a change in accounting principle for the Clover and distributed generation facilities as a result of the adoption of Accounting for Asset Retirement and Environmental Obligations. These costs will be fully amortized in 2034.

 

  NOVEC contract termination fee reflects the amount allocated to the contract value of the payment to NOVEC in 2008 as part of the termination agreement. The wholesale power contract with NOVEC was scheduled to expire in 2028, thus the contract termination fee will be amortized ratably through 2028 through amortization of regulatory asset/(liability), net.

 

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  Loan acquisition fee reflects the one-time fee we paid to the investor to facilitate the acquisition of the $33.0 million loan related to the lease of Clover Unit 1. This fee will be amortized ratably over the remaining life of the lease and will be fully amortized in 2018.

 

  Interest rate hedge. To mitigate a portion of our exposure to fluctuations in long-term interest rates related to the debt we issued in 2011, we entered into an interest rate hedge. This will be amortized over the life of the 2011 debt and will be fully amortized in 2050.

 

  North Anna Unit 3. In February 2011, we made the determination not to participate in North Anna Unit 3 and on December 16, 2011, we finalized our withdrawal as a participant in the project and transferred our interest to Virginia Power. Related to this decision, in 2011 we reclassified the corresponding construction work in progress to a regulatory asset. Reimbursement of costs recorded in the regulatory asset to us by Virginia Power is subject to the VSCC approval. We cannot currently estimate if or when Virginia Power will seek approval from the VSCC. If these costs are not determined to be collectible from Virginia Power, we will begin amortizing our regulatory asset and collect these costs from our member distribution cooperatives through our formula rate.

 

  Voluntary prepayment to NRECA Retirement Security Plan. In April 2013, we elected to make a voluntary prepayment of $7.7 million to the NRECA Retirement Security Plan, a noncontributory, defined benefit multiple employer master pension plan. We recorded this prepayment as a regulatory asset which will be fully amortized in 2022.

 

  Deferred net unrealized losses on derivative instruments will be matched and recognized in the same period the expense is incurred for the hedged item.

Regulatory assets included in current assets are detailed as follows:

 

  Deferred energy balance represents the net accumulation of under-collection of energy costs. We use the deferral method of accounting to recognize differences between our energy expenses and our energy revenues collected from our member distribution cooperatives. Under-collected deferred energy balances are charged to our members in subsequent periods.

Regulatory liabilities included in deferred credits and other liabilities are detailed as follows:

 

  North Anna asset retirement obligation deferral is the cumulative effect of change in accounting principle as a result of the adoption of Accounting for Asset Retirement and Environmental Obligations plus the deferral of subsequent activity primarily related to accretion expense offset by interest income on the nuclear decommissioning trust.

 

  Norfolk Southern settlement reflects the difference in the amount previously accrued and the actual settlement amount. This balance was fully amortized as of the end of May 2014 as a reduction of fuel expense.

 

  North Anna nuclear decommissioning trust unrealized gain reflects the unrealized gain on the investments in the nuclear decommissioning trust.

 

  Unamortized gains on reacquired debt are the gains we recognized when we purchased our outstanding indebtedness prior to its scheduled retirement. These gains are amortized over the life of the original indebtedness and will be fully amortized in 2023.

 

  Deferred net unrealized gains on derivative instruments will be matched and recognized in the same period the expense is incurred for the hedged item.

 

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Regulatory liabilities included in current liabilities are detailed as follows:

 

  Deferred energy balance represents the net accumulation of over-collection of energy costs. We use the deferral method of accounting to recognize differences between our energy expenses and our energy revenues collected from our member distribution cooperatives. Over-collected deferred energy balances are credited to our members in subsequent periods.

NOTE 11—Long-term Debt

Long-term debt consists of the following:

 

     December 31,  
     2014      2013  
     (in thousands)  

$50,000,000 principal amount of First Mortgage Bonds, 2013 Series A due 2043 at an interest rate of 4.21%

   $ 50,000      $ 50,000  

$50,000,000 principal amount of First Mortgage Bonds, 2013 Series B due 2053 at an interest rate of 4.36%

     50,000        50,000  

$90,000,000 principal amount of First Mortgage Bonds, 2011 Series A due 2040 at an interest rate of 4.83%

     78,000        81,000  

$165,000,000 principal amount of First Mortgage Bonds, 2011 Series B due 2040 at an interest rate of 5.54%

     165,000        165,000  

$95,000,000 principal amount of First Mortgage Bonds, 2011 Series C due 2050 at an interest rate of 5.54%

     85,500        87,875  

$250,000,000 principal amount of 2003 Series A Bonds due 2028 at an interest rate of 5.676%

     145,830        156,247  

$300,000,000 principal amount of 2002 Series B Bonds due 2028 at an interest rate of 6.21%

     175,000        187,500  
  

 

 

    

 

 

 
  749,330     777,622  

Current maturities

  (28,292   (28,292
  

 

 

    

 

 

 
$ 721,038   $ 749,330  
  

 

 

    

 

 

 

At December 31, 2014 and 2013, deferred gains and losses on reacquired debt totaled a net loss of approximately $15.0 million and $16.9 million, respectively. Deferred gains and losses on reacquired debt are deferred under regulatory accounting. See Note 10—Regulatory Assets and Liabilities.

 

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Maturities of long-term debt for the next five years and thereafter are as follows:

 

Year Ending December 31,

   (in thousands)  

2015

   $ 28,292  

2016

     28,292  

2017

     28,292  

2018

     28,292  

2019

     28,292  

2020 and thereafter

     607,870   
  

 

 

 
$ 749,330   
  

 

 

 

The aggregate fair value of long-term debt was $847.7 million and $846.4 million at December 31, 2014 and 2013, respectively, based on current market prices. For debt issues that are not quoted on an exchange, interest rates currently available to us for issuance of debt with similar terms and remaining maturities are used to estimate fair value.

All of our long-term debt is issued under our Indenture. Substantially all of our real property and tangible personal property and some of our intangible personal property are pledged as collateral under the Indenture. Under the Indenture, we may not make any distribution, including a dividend or payment or retirement of patronage capital, to our members if an event of default exists under the Indenture. Otherwise, we may make a distribution to our members if (1) after the distribution, our patronage capital as of the end of the most recent fiscal quarter would be equal to or greater than 20% of our total long-term debt and patronage capital, or (2) all of our distributions for the year in which the distribution is to be made do not exceed 5% of the patronage capital as of the end of the most recent fiscal year. For this purpose, patronage capital and total long-term debt do not include any earnings retained in any of our subsidiaries or affiliates or the debt of any of our subsidiaries or affiliates.

Our 2002 Series A Bonds, with an aggregate principal amount of $60.2 million outstanding, were subject to optional redemption by ODEC on or after June 1, 2013. We issued a call notice for the 2002 Series A Bonds in the second quarter of 2013 and redeemed these bonds on June 1, 2013. We paid a premium of $0.3 million and had unamortized debt issuance costs of $1.5 million related to these bonds, for a total of $1.8 million. These costs have been deferred as a regulatory asset and will be amortized over the original life of the debt to 2028.

On June 28, 2013, we issued $100.0 million of first mortgage bonds in a private placement transaction. The issuance consisted of $50.0 million of 4.21% First Mortgage Bonds, 2013 Series A due December 1, 2043 and $50.0 million of 4.36% First Mortgage Bonds, 2013 Series B due December 1, 2053.

On January 15, 2015, we issued $332.0 million of first mortgage bonds in a private placement transaction. The issuance consisted of $260.0 million of 4.46% First Mortgage Bonds, 2015 Series A due December 1, 2044 and $72.0 million of 4.56% First Mortgage Bonds, 2015 Series B due December 1, 2053.

Additionally, we maintain a five-year revolving credit facility. See Note 12—Liquidity Resources.

NOTE 12—Liquidity Resources

We currently maintain a $500.0 million, five-year revolving credit facility to cover our short-term and medium-term funding needs. Commitments under this syndicated credit agreement extend until March 5, 2019. At December 31, 2014, we had $86.0 million in borrowings outstanding under this facility at an interest rate of 1.5%. Additionally, at December 31, 2014, we had a letter of credit in the amount of $10.0 million outstanding. We did not have any borrowings or letters of credit outstanding under this facility at December 31, 2013; however, the interest rate on any borrowings would have been 1.1%.

 

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In February 2015, we utilized funds from the January 2015 private placement transaction to repay amounts outstanding under our revolving credit facility. As of March 10, 2015, we did not have any outstanding borrowings under the revolving credit facility; however, we anticipate that we will borrow under this facility in the future.

On March 12, 2014, we amended and extended our $500.0 million, five-year revolving credit agreement with CoBank, ACB, Wells Fargo Securities, LLC, Merrill Lynch, Pierce Fenner & Smith Incorporated, J.P. Morgan Securities LLC, and PNC Capital Markets LLC as joint lead arrangers; CoBank, ACB, as syndication agent; Wells Fargo Bank, National Association, as administrative agent and swingline lender; and Bank of America, N.A., JPMorgan Chase Bank, N.A., and PNC Bank, N.A. as documentation agents. Commitments under the credit agreement now extend until March 5, 2019, unless earlier terminated in accordance with the agreement.

Borrowings under the credit agreement that are based on Eurodollar rates bear interest at LIBOR plus a margin ranging from 0.90% to 1.5%, depending on our credit ratings. Borrowings not based on Eurodollar rates, including swingline borrowings, bear interest at the highest of (1) the federal funds effective rate plus 0.5%, (2) the prime commercial lending rate of the administrative agent, and (3) the daily LIBOR for a one-month interest period plus 1.0%, plus in each case a margin ranging from 0.0% to 0.5%. Additionally, we are also responsible for customary unused commitment fees, an administrative agent fee and letter of credit fees.

The credit agreement contains customary conditions to borrowing or the issuance of letters of credit, representations and warranties, and covenants. The credit agreement obligates us to maintain a debt to capitalization ratio of no more than 0.85 to 1.00 and to maintain a margins for interest ratio of no less than 1.10 times interest charges (calculated in accordance with our secured indenture as currently in effect). We are in compliance with the credit agreement. Obligations under the credit agreement may be accelerated following, among other things, (1) the failure to pay outstanding principal when due or other amounts, including interest, within five days after the due date, (2) a material misrepresentation, (3) a cross-payment default or cross-acceleration under specified indebtedness, (4) failure by us to perform any obligation relating to the credit agreement following, in some cases, specified cure periods, (5) bankruptcy or insolvency events, (6) invalidity of the credit agreement and related loan documentation or our assertion of invalidity, and (7) a failure by our member distribution cooperatives to pay amounts in excess of an agreed threshold owing to us beyond a specified cure period.

We maintain a policy which allows our member distribution cooperatives to prepay or extend payment on their monthly power bills. Under this policy, we pay interest on prepayment balances at a blended investment and short-term borrowing rate, and we charge interest on extended payment balances at a blended prepayment and short-term borrowing rate. Amounts prepaid by our member distribution cooperatives are included in accounts payable-members and totaled $35.2 million and $15.2 million at December 31, 2014 and 2013, respectively. Amounts extended by our member distribution cooperatives are included in accounts receivable-members and were zero at December 31, 2014, and totaled $10.8 million at December 31, 2013.

NOTE 13—Employee Benefits

Substantially all of our employees participate in the NRECA Retirement Security Plan, a noncontributory, defined benefit multiple employer master pension plan. The legal name of the plan is the NRECA Retirement Security Plan; the employer identification number is 53–0116145, and the plan number is 333. Plan information is available publicly through the annual Form 5500, including attachments. The plan year is January 1 through December 31. In total, the NRECA Retirement Security Plan was over 80% funded on January 1, 2014 and 2013, based on the PPA funding target and PPA actuarial value of assets on those dates. The cost of the plan is funded annually by payments to NRECA to ensure that annuities in amounts established by the plan will be available to individual participants upon their retirement. We also participate in a pension restoration plan, which is intended to provide a supplemental benefit for employees who would have a reduction in their pension benefit from the Retirement Security Plan because of the IRC limitations. Our required contribution to the NRECA Retirement Security Plan and the pension restoration plan totaled $2.9 million in each of the years 2014, 2013, and 2012, respectively. In each of these years, our contributions represented less than 5% of the total contributions made to the plan by all participating employers. In 2013, we elected to make a voluntary prepayment of $7.7 million to the

 

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NRECA Retirement Security Plan and recorded this payment as a regulatory asset which will be fully amortized in 2022. There has been no funding improvement plan or rehabilitation plan implemented nor is one pending, and we did not pay a surcharge to the plan for 2014. Pension expense, inclusive of administrative fees, was $3.3 million, $3.0 million, and $3.0 million for 2014, 2013, and 2012, respectively. Pension expense for 2014 and 2013 includes $0.8 million related to the amortization of the voluntary prepayment regulatory asset.

We have also elected to participate in a defined contribution 401(k) retirement plan administered by TransAmerica Retirement Solutions. We match up to the first 2% of each participant’s base salary. Our matching contributions were $224,000, $206,000, and $204,000, in 2014, 2013, and 2012, respectively.

NOTE 14—Other

Recovery of Costs from PJM

On June 23, 2014, we filed a petition at FERC seeking recovery from PJM of approximately $14.9 million of unreimbursed costs, which were incurred during the first quarter of 2014 related to the dispatch of our combustion turbine generating facilities. The results of our petition cannot currently be determined and we have not recorded a receivable related to this matter.

Clean Power Plan

On June 2, 2014, the EPA proposed emission guidelines for CO2 from existing electric utility generating units under 111(d) of the CAA. This proposal, referred to as the Clean Power Plan, requires that each state develop, submit, and implement a plan to achieve the interim and final state-specific goals detailed in the rulemaking. The EPA proposal has defined the following four areas of focus which the states are to utilize to meet the proposed goals:

 

    increase efficiency of existing fossil-fuel plants;

 

    increase dispatch of existing natural gas combined-cycle units;

 

    utilize and expand the use of zero-emitting generation (additional renewables and nuclear); and

 

    increase demand-side energy efficiency.

Public hearings on the CPP were held by the EPA on July 29 – August 1, 2014, and the EPA expects to finalize the rule in the summer of 2015. There are a number of legal challenges related to the CPP, including whether or not the EPA can finalize standards for existing plants under Section 111(d) until standards are finalized for new plants under Section 111(b). We will continue to follow this rulemaking in order to determine potential impacts related to our existing facilities. Due to the general nature of the guidelines and the lack of specifics regarding state implementation, we cannot predict whether the final rules relating to the guidelines will have a material impact on our results of operations or financial condition.

NOTE 15—Supplemental Cash Flows Information

Cash paid for interest, net of amounts capitalized, in 2014, 2013, and 2012, was $43.1 million, $44.3 million, and $45.4 million, respectively. Cash paid for income taxes was immaterial in 2014, 2013, and 2012.

 

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NOTE 16—Commitments and Contingencies

Environmental

We are subject to federal, state, and local laws and regulations and permits designed to both protect human health and the environment and to regulate the emission, discharge, or release of pollutants into the environment. We believe we are in material compliance with all current requirements of such environmental laws and regulations and permits. However, as with all electric utilities, the operation of our generating units could be affected by future environmental regulations. Capital expenditures and increased operating costs required to comply with any future regulations could be significant.

Insurance

The Price-Anderson Amendments Act of 1988 provides the public up to $13.6 billion of liability protection per nuclear incident, via obligations required of owners of nuclear power plants, and allows for an inflationary provision adjustment every five years. Owners of nuclear facilities could be assessed up to $127 million for each of their licensed reactors not to exceed $19 million per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed. Virginia Power, the co-owner of North Anna, is responsible for operating North Anna. Under several of the nuclear insurance policies procured by Virginia Power to which we are a party, we are subject to retrospective premium assessments in any policy year in which losses exceed the funds available to the insurance companies.

As a joint owner of North Anna, we are a party to the insurance policies that Virginia Power procures to limit the risk of loss associated with a possible nuclear incident at the station, as well as policies regarding general liability and property coverage. All policies are administered by Virginia Power, which charges us for our proportionate share of the costs.

Our share of the maximum retrospective premium assessments for the coverage assessments described above is estimated to be a maximum of $32.6 million at December 31, 2014.

NOTE 17—Selected Quarterly Financial Data (Unaudited)

A summary of the quarterly results of operations for the years 2014 and 2013 follows. Amounts reflect all adjustments, consisting of only normal recurring accruals, necessary in the opinion of management for a fair statement of the results for the interim periods. Results for the interim periods may fluctuate as a result of weather conditions, changes in rates, and other factors.

 

     First
Quarter
     Second
Quarter
     Third
Quarter
     Fourth
Quarter
     Total  
     (in thousands)  

Statement of Operations Data

              

2014

              

Operating Revenues

   $ 265,096      $ 217,331      $ 233,904      $ 235,245      $ 951,576  

Operating Margin

     12,194        13,121        13,015        12,195        50,525  

Net Margin attributable to ODEC

     2,310        2,330        2,349        2,111        9,100  

2013

              

Operating Revenues

   $ 220,713      $ 187,623      $ 220,393      $ 213,340      $ 842,069  

Operating Margin

     14,302        13,130        14,010        11,148        52,590  

Net Margin attributable to ODEC

     2,386        2,346        2,448        2,393        9,573  

 

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Effectiveness of Disclosure Controls and Procedures

As of the end of the period covered by this report, our management, including the President and CEO, and Senior Vice President and CFO conducted an evaluation of the effectiveness of our disclosure controls and procedures. Based upon that evaluation, the President and CEO, and Senior Vice President and CFO concluded that our disclosure controls and procedures are effective in ensuring that all material information required to be filed in this report has been made known to them in a timely matter. We have established a Disclosure Assessment Committee comprised of members from senior and middle management to assist in this evaluation. In the third quarter of 2014, we implemented a new fixed asset system. Other than the new fixed asset system, there have been no significant changes in our internal controls over financial reporting or in other factors that could significantly affect such controls during the previous fiscal year.

Management’s Annual Report on Internal Control over Financial Reporting

Our management has assessed our internal control over financial reporting as of December 31, 2014, based on criteria for effective internal control over financial reporting described in “2013 Internal Control – Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management believes that as of December 31, 2014, our system of internal control over financial reporting was properly designed and operating effectively based upon the specified criteria. We have not identified any material weaknesses in our internal control over financial reporting.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is comprised of policies, procedures, and reports designed to provide reasonable assurance to our management and board of directors that the financial reporting and the

 

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preparation of the financial statements for external reporting purposes has been handled in accordance with accounting principles generally accepted in the United States. Internal control over financial reporting includes those policies and procedures that (1) govern records to accurately and fairly reflect the transactions and dispositions of assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (3) provide reasonable safeguards against or timely detection of material unauthorized acquisition, use or disposition of our assets.

Changes in Internal Control over Financial Reporting

In the third quarter of 2014, we implemented a new fixed asset system. Other than the new fixed asset system, there have been no material changes in our internal controls over financial reporting or in other factors that could significantly affect such controls during the past fiscal year.

Inherent Limitations on Internal Control

There are inherent limitations to the effectiveness of any system of internal control over financial reporting. No control system can provide absolute assurance that all control issues and instances of error or fraud, if any, have been detected. Even the best designed system can only provide reasonable assurance that the objectives of the control system have been met. Because of these inherent limitations, our internal control over financial reporting may not prevent or detect all misstatements. Additionally, projections as to the effectiveness of internal control in future periods are subject to the risk that internal control may not continue to operate at its current effectiveness levels due to changes in personnel or in our operating environment.

ITEM 9B. OTHER INFORMATION

SunTrust Bank, (formerly Crestar Bank), succeeded Bankers Trust Company as trustee under the nuclear decommissioning trust pursuant to the Nuclear Decommissioning Trust Agreement. The agreement is attached as Exhibit 10.8 to this Annual Report on Form 10-K.

 

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Directors

We are governed by a board of 23 directors, consisting of two representatives from each of our member distribution cooperatives and one representative from TEC. Pursuant to our bylaws, each of our eleven member distribution cooperatives, in good standing, may recommend candidates to the nominating committee of our board of directors. At the annual meeting each year, the nominating committee nominates candidates for election to our board of directors. At least one candidate from each member distribution cooperative must be a director of that member distribution cooperative. Currently and historically, the other candidate from each member distribution cooperative is the chief executive officer of that member distribution cooperative. The candidates for director are elected to our board of directors by a majority of the voting delegates from our members. Each member has one voting delegate. We do not control who the member distribution cooperative recommends to the nominating committee. As a result, our board of directors has not developed criteria, such as diversity, for use in identifying nominees to our board of directors. One director currently serves as a director on behalf of a member distribution cooperative and TEC. Each elected candidate is authorized to represent that member for a renewable term of one year at our annual meeting. Our board of directors sets policy and provides direction to our President and CEO. Our board of directors meets approximately 11 times each year.

Information concerning those serving on our board of directors as of December 31, 2014, including principal occupation and employment during the past five years, qualifications, and directorships in public corporations, if any, is listed below.

J. William Andrew, Jr. (61). President and CEO of Delaware Electric Cooperative, Inc. since 2005. Mr. Andrew has held executive positions in the utility industry for over a decade and has been a director of ODEC since 2005.

M Dale Bradshaw (61). President Emeritus of Prince George Electric Cooperative since December 2014. Mr. Bradshaw was CEO of Prince George Electric Cooperative from 1995 to December 2014. Mr. Bradshaw has held executive positions in the utility industry for over three decades and was a director of ODEC from 1995 to January 22, 2015.

Paul H. Brown (69). Retired, formerly Vice President of Commercial Lending of Bank of Southside Virginia where he served from 1995 to 2012. Mr. Brown has been a director of ODEC since 2013 and a director of Prince George Electric Cooperative since 2007.

Darlene H. Carpenter (68). Realtor of Century 21 New Millennium since 2013. Ms. Carpenter was a Realtor of Montague, Miller & Company Realtors, Inc. from 2006 to 2013. Ms. Carpenter has been a director of ODEC since 2009 and a director of Rappahannock Electric Cooperative since 1984.

Earl C. Currin, Jr. (71). Retired, formerly Provost at Southside Community College where he served from 1970 to 2007. Dr. Currin taught both accounting and economics at the college level. Dr. Currin has been a director of ODEC since 2008 and a director of Southside Electric Cooperative since 1986.

E. Garrison Drummond (63). Insurance agent of Drummond Insurance Agency, Inc. since 1984. Mr. Drummond has been a director of ODEC since 2012 and a director of A&N Electric Cooperative since 2002.

Jeffrey S. Edwards (51). President and CEO of Southside Electric Cooperative since 2007. Mr. Edwards has held executive positions in the utility industry for over a decade and has been a director of ODEC since 2007.

 

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Kent D. Farmer (57). President and CEO of Rappahannock Electric Cooperative since 2004. Mr. Farmer has held executive positions in the utility industry for over two decades and has been a director of ODEC since 2004.

Fred C. Garber (70). Retired, formerly President of Mt. Jackson Farm Service from 1973 to 2003. Mr. Garber has been a director of ODEC since 2005 and a director of Shenandoah Valley Electric Cooperative since 1984.

Hunter R. Greenlaw, Jr. (69). President of G.L.M.G. General Contractors, a real estate development and general contracting company since 1974. Mr. Greenlaw has been a director of ODEC since 1991 and a director of Northern Neck Electric Cooperative since 1979.

Steven A. Harmon (53). President and CEO of Community Electric Cooperative since 2013. Mr. Harmon was President and CEO of H-2 Business Solutions, LLC, from 2012 to 2013 and was Executive Vice President and General Manager of Pioneer Electric Cooperative from 2006 to 2011. Mr. Harmon has held executive positions in the utility industry for over a decade and has been a director of ODEC since 2013.

Bruce A. Henry (69). Owner and Secretary/Treasurer of Delmarva Builders, Inc. since 1981. Mr. Henry has been a director of ODEC since 1993 and a director of Delaware Electric Cooperative, Inc. since 1978.

David J. Jones (66). Owner/operator of Big Fork Farms since 1970 and Vice President of Exchange Warehouse, Inc. from 1996 to 2006. Mr. Jones has been a director of ODEC since 1986 and a director of Mecklenburg Electric Cooperative since 1982.

Michael J. Keyser (38). CEO and General Manager of BARC Electric Cooperative since 2010. Mr. Keyser was CEO and General Counsel for American Samoa Power Authority from 2006 to 2010. Mr. Keyser has held executive positions in the utility industry since 2006 and has been a director of ODEC since 2010.

John C. Lee, Jr. (54). President and CEO of Mecklenburg Electric Cooperative since 2008. Mr. Lee has held executive positions in the utility industry for over a decade and has been a director of ODEC since 2008.

R. Dodd Obenshain (57). President and CEO of A&N Electric Cooperative since 2013. Mr. Obenshain was CFO of A&N Electric Cooperative from 1981 to 2013. Mr. Obenshain has held executive positions in the utility industry for over three decades and has been a director of ODEC since 2013.

Paul E. Owen (64). Retired, formerly Director of Business Management with Smithfield Deli Group from 1974 to 2010. Mr. Owen has been a director of ODEC since 2006 and a director of Community Electric Cooperative since 2000.

Myron D. Rummel (62). President and CEO of Shenandoah Valley Electric Cooperative since 2005. Mr. Rummel has held executive positions in the utility industry for over two decades and has been a director of ODEC since 2005.

Keith L. Swisher (60). Owner/operator of Swisher Valley Farms, LLC since 1976. Mr. Swisher has been a director of ODEC since 2008 and a director of BARC Electric Cooperative since 1981.

Michael I. Wheatley (59). President and CEO of Choptank Electric Cooperative, Inc. since 2011. Mr. Wheatley was Senior Vice President Corporate Services of Choptank Electric Cooperative, Inc. from 2002 to 2011. Mr. Wheatley has held executive positions in the utility industry for over two decades and has been a director of ODEC since 2011.

 

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Gregory W. White (62). President and CEO of Northern Neck Electric Cooperative since 2005. Mr. White has held executive positions in the utility industry for over two decades and has been a director of ODEC since 2005.

Carl R. Widdowson (76). Self-employed farmer since 1956. Mr. Widdowson has been a director of ODEC since 1987 and a director of Choptank Electric Cooperative, Inc. since 1980.

Audit Committee Financial Expert

We do not have an audit committee financial expert because of our cooperative governance structure and the resulting experience all of our directors have with matters affecting electric cooperatives in their roles as a chief executive officer or director of one of our member distribution cooperatives. In addition, the audit committee employs the services of accounting and financial consultants as it deems necessary.

Executive Officers

Our President and CEO administers our day-to-day business and affairs. Our executive officers at December 31, 2014, their respective ages, positions and relevant business experience are listed below.

Jackson E. Reasor (62). President and CEO of ODEC and the VMDAEC, an electric cooperative association which provides services to its members and certain other electric cooperatives, since 1998.

Robert L. Kees (62). Senior Vice President and CFO since 2006. Mr. Kees joined ODEC in 1991 and has held various accounting positions including Vice President and Controller.

D. Richard Beam (57). Senior Vice President of Power Supply since November 2013. Mr. Beam joined ODEC in 1987 and has held various power supply positions including Vice President of Power Supply and Transmission Planning from July 2004 to March 2013 and Vice President of Power Supply from April 2013 to November 2013.

Elissa M. Ecker (55). Vice President of Human Resources since 2004.

Code of Ethics

We have a code of ethics which applies to all of our employees, including our President and CEO, Senior Vice President and CFO, and Vice President and Controller. A copy of our code of ethics is available without charge by sending a written request to ODEC, Attention Mr. Bryan S. Rogers, Vice President and Controller, 4201 Dominion Boulevard, Glen Allen, VA 23060.

 

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ITEM 11. EXECUTIVE COMPENSATION

COMPENSATION DISCUSSION AND ANALYSIS

General Philosophy

Our compensation philosophy has four objectives:

 

    attract and retain a qualified, diverse workforce through a competitive compensation program;

 

    provide equitable and fair compensation;

 

    support our business strategy; and

 

    ensure compliance with applicable laws and regulations.

Total Compensation Package

We compensate our CEO and other executive officers through the use of a total compensation package which includes base salary, competitive benefits, and the potential of a bonus. Our CEO’s base salary is derived from salary data provided by third parties through national compensation surveys. The national compensation survey data includes data from the labor market for positions of similar responsibilities.

Targeted Overall Compensation

Our compensation program utilizes detailed job descriptions for all of our employees including executive officers, with the exception of the CEO, as an instrument to establish benchmarked positions. The market compensation information for each position is derived from salary data provided by third parties through national compensation surveys and includes salary data for positions within the determined competitive labor market. Our job descriptions are reviewed annually and include job responsibilities, required knowledge, skills and abilities, and formal education and experience necessary to accomplish the requirements of the position which in turn helps us achieve operational goals. Utilizing this information, our human resources department determines a market-based salary for each position based upon salary survey data provided by third parties. A third-party consultant, Burton-Fuller Management, reviews the market-based salary data we compiled for reasonableness annually. We have defined market-based salary as approximately the 50th percentile of the market. Intandem LLC has been engaged to create a performance appraisal instrument for the CEO position as well as to design, distribute, and compile market valuation models and reports for the executive officers.

Process

We have a committee of our board of directors, the executive committee, which recommends all compensation for our CEO to the entire board of directors and the entire board of directors approves the compensation. Our board of directors has delegated to our CEO the authority to establish and adjust compensation for all employees other than himself. The compensation for all other employees, including executive officers other than the CEO, is approved by our CEO based upon market-based salary data. On an annual basis our board of directors reviews the performance and compensation of our CEO, and our CEO reviews the performance and compensation of the remaining executive officers.

Our CEO is also the CEO of the VMDAEC, and their board of directors also approves his compensation.

Base Salaries

We are an electric cooperative and do not have any stock and as a result, we do not have equity-based compensation programs. For this reason, substantially all of our compensation to our executive officers is provided in the form of base salary. We want to provide our executive officers with a level of assured cash compensation in the form of base salary that is commensurate with the duties and responsibilities of their positions. These salaries are determined based on market data for positions with similar responsibilities.

 

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Bonuses

Our practice has been to, on infrequent occasions, award cash bonuses related to a specific event, such as the consummation of a significant transaction. On an annual basis, our board of directors determines the bonus criteria for, and may award a bonus to, our CEO. On an annual basis, our CEO determines bonus criteria for, and may award a bonus to, the other executive officers.

Severance Benefits

We believe that companies should provide reasonable severance benefits to the CEO. With respect to our CEO, these severance benefits reflect the fact that it may be difficult to find comparable employment within a short period of time. Our CEO’s contractual rights to amounts following severance are set forth in his employment agreement. None of our other executive officers have any contractual severance benefits.

Plans

Retirement Plans

We participate in the NRECA Retirement Security Plan, a noncontributory, defined benefit multiple employer master pension plan which is available to all employees, with limited exceptions, who work at least 1,000 hours per year. This plan is a qualified pension plan under IRC Section 401(a). Benefits, which accrue under the plan, are based upon the employee’s base annual salary as of November of the previous year.

We also have a 401(k) plan which is available to all employees in regular positions. Under the 401(k) plan for 2014, employees may have elected to have up to 100% or $17,500, whichever is less, of their salary withheld on a pre-tax basis, subject to Internal Revenue Service limitations, and invested on their behalf. We match up to the first 2% of each participant’s base salary. Also, a catch-up contribution is available for participants in the plan once they attain age 50. The maximum catch-up contribution for 2014 was $5,500.

In addition, we have a non-qualified executive deferred compensation plan (the “Deferred Compensation Plan”). Our board of directors, at its discretion, determines who may participate in the plan as well as an annual contribution, if any, up to the maximum amount allowed by regulations. Currently, our board of directors has determined that our CEO is the only participant in this plan. We have made a $15,000 contribution to the plan each year for his benefit since the inception of the plan in 2006.

Pension Restoration Plan

We participate in a pension restoration plan, which is intended to provide a supplemental benefit for employees who would have a reduction in their pension benefit because of IRC limitations. Our CEO, CFO, and Senior Vice President of Power Supply are the only current participants in this plan.

Perquisites and Other Benefits

Our board of directors reviews the perquisites that our CEO receives during contract discussions with our CEO. The perquisite for Mr. Reasor is expenses for personal use of a company automobile which amounted to $2,251 in 2014 and $2,684 in 2013.

The executive officers participate in our other benefit plans on the same terms as other employees. These plans include the defined benefit pension plan, the 401(k) plan, medical insurance, life insurance and accidental death and dismemberment, long-term disability, medical reimbursement and dependent care flexible spending accounts, health savings account, health club membership, vacation, holiday, and sick leave. Relocation benefits are reimbursed for all employees who transfer to another location at the request or convenience of ODEC in accordance with our relocation policy. We believe these benefits are customary for similar employers.

 

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Change in Control

There is no provision in our CEO’s employment agreement or any other arrangements with any other executive officers that increases or decreases any amounts payable to him or her as a result of a change in control.

Summary Compensation Table

The following table sets forth information concerning compensation awarded to, earned by or paid to our executive officers for services rendered to us in all capacities during each of the last three fiscal years. The table also identifies the principal capacity in which each of these executives serves.

SUMMARY COMPENSATION

 

Name and Principal Position

   Year     Salary      Bonus      Change in Pension
Value and Non-
Qualified  Deferred
Compensation
Earnings(1)(2)
    All Other
Compensation(2)
     Total  

Jackson E. Reasor

     2014      $ 511,905       $ —         $ (27,731 )(3)    $ 25,356       $ 509,530   

President and CEO

     2013        487,136         —           348,081        25,343         860,560   
     2012        468,708         —           363,537        27,421         859,666   

Robert L. Kees

     2014        286,353         —           (6,734 )(3)      6,841         286,460   

Senior Vice President and CFO

     2013        278,013         —           245,777        6,455         530,245   
     2012 (4)      271,645         —           307,796        6,407         585,848   

D. Richard Beam (5)

     2014        278,426         —           20,747        6,652         305,825   

Senior Vice President of Power Supply

     2013        228,824         —           169,437        5,667         403,928   

Elissa M. Ecker

     2014 (6)      201,656         —           11,897        5,068         218,621   

Vice President of Human Resources

     2013        195,783         —           89,934        5,016         290,733   
     2012 (6)      195,403         —           74,613        4,888         274,904   

 

(1)  The values disclosed here represent the changes in the NRECA Retirement Security Plan value and the pension restoration plan.
(2)  The items included in All Other Compensation are identified in the All Other Compensation table below. In prior years, All Other Compensation had included an allocated portion of premiums paid by us with respect to our obligation to fund our defined benefit plan, the NRECA Retirement Security Plan. The Change in Pension Value and Non-Qualified Deferred Compensation Earnings column above and the Present Value of Accumulated Benefit in the Pension Benefits table below disclose the NRECA Retirement Security Plan and the pension restoration plan benefits for each named executive officer.
(3)  For 2014, the change in pension value was $(817,432) for Mr. Reasor and includes the impact of a pension restoration payment of $789,701 and a loss in value of $(27,731). For 2014, the change in pension value was $(99,113) for Mr. Kees and includes the impact of pension restoration plan payments of $92,379 and a loss in value of $(6,734).
(4)  For 2012, salary includes a lump sum salary adjustment of $1,729. Lump sum salary adjustments are not included in the calculation of pension benefits.
(5)  On November 5, 2013, we appointed Mr. D. Richard Beam as Senior Vice President of Power Supply effective November 16, 2013.
(6)  For 2014 and 2012, salary includes a lump sum salary adjustment of $5,873 and $5,322, respectively. Lump sum salary adjustments are not included in the calculation of pension benefits.

Employment Agreement

We have an employment agreement with our CEO. We do not have an employment agreement with any of our other executive officers or our controller.

On May 23, 2012, ODEC entered into an employment agreement with Jackson E. Reasor, our CEO. The agreement is for the term of three years, with an automatic one-year extension unless Mr. Reasor or ODEC and the VMDAEC (collectively, the “Employer”) give written notice 30 days prior to the expiration of the agreement. The agreement provides that he will receive annual compensation of $493,500, effective June 1, 2012, subject to annual adjustment by the boards of directors of the Employer. The annual compensation includes amounts paid to the

 

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deferred compensation plan, which totaled $15,000 in 2014. The boards of directors of the Employer also may grant Mr. Reasor an annual bonus at their discretion. Mr. Reasor will also be entitled to participate in all benefit plans available to the employees of the Employer. The VMDAEC contributed $45,000 of Mr. Reasor’s salary in 2014 and is expected to contribute the same amount in 2015.

Under the agreement, if Mr. Reasor voluntarily terminates his employment following material breach by the Employer or the Employer terminates him without specified cause, the Employer will pay Mr. Reasor a salary at the rate in effect on the date of termination for one year, plus medical insurance benefits, with limited exceptions. If the agreement is not continued at the end of the stated term, the Employer will pay Mr. Reasor a salary at the rate in effect on the date of termination for six months.

Where the termination is “without cause” or Mr. Reasor terminates employment for “good reason” the employment agreement provides for benefits equal to one year of base salary and medical insurance. However, if he becomes employed in any capacity during the one year period immediately following the date of termination, the Employer’s obligation to pay the base salary shall be reduced by the amount of his salary at the new employer. Also, the medical insurance benefit will cease if he becomes eligible for medical insurance coverage by virtue of his employment with another company. In addition, a terminated CEO is entitled to receive any benefits that he otherwise would have been entitled to receive under our 401(k) plan, pension plan and supplemental retirement plans, although those benefits are not increased or accelerated.

Based upon a hypothetical termination date of December 31, 2014, the severance benefits Mr. Reasor would have been entitled to would be as follows:

 

Annual compensation

$ 525,191   

Targeted bonus

  —     

Medical insurance

  14,126   
  

 

 

 

Total

$ 539,317   
  

 

 

 

Under our employment contract with Mr. Reasor, “cause” is defined as (1) gross incompetence, insubordination, gross negligence, willful misconduct in office or breach of a material fiduciary duty, which includes a breach of confidentiality; (2) conviction of a felony, a crime of moral turpitude or commission of an act of embezzlement or fraud against ODEC or the VMDAEC or any subsidiary or affiliate thereof; (3) the CEO’s material failure to perform a substantial portion of his duties and responsibilities under the employment contract, but only after the Employer provides the CEO written notice of such failure and gives him 30 days to remedy the situation; or (4) deliberate dishonesty of the CEO with respect to ODEC or the VMDAEC or any of its subsidiaries or affiliates.

The CEO may terminate his employment with or without good reason by written notice to the boards of directors effective 60 days after receipt of such notice by the boards of directors. If the CEO terminates his employment for good reason, then the CEO is entitled to the salary specified above in the “without cause” paragraph. The CEO will not be required to render any further services. Upon termination of employment by the CEO without good reason, the CEO is not entitled to further compensation. Under our employment contract with Mr. Reasor, “good reason” is defined as the Employer’s failure to maintain compensation and benefits or the Employer’s material breach of any provision of the employment contract, which failure or breach continued for more than 30 days after the date on which our boards of directors received such notice.

Defined Benefit Plans

The following table lists the estimated values under the NRECA Retirement Security Plan and the pension restoration plan as of December 31, 2014. As a result of changes in Internal Revenue Service regulations, the base annual salary used in determining benefits is limited to $265,000 effective January 1, 2015.

 

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PENSION BENEFITS

 

Name

  

Plan Name

   Number of
Years Credited
Service
     Present Value
of Accumulated
Benefit
    Payments
During
Last Year
 

Jackson E. Reasor

  

NRECA Retirement

Security Plan

     15.08       $ 1,090,268      $ —     
  

Pension Restoration Plan

     15.08         106,699 (1)      789,701   

Robert L. Kees

  

NRECA Retirement

Security Plan

     22.00         1,590,225        —     
  

Pension Restoration Plan

     22.00         —          92,379   

D. Richard Beam

  

NRECA Retirement

Security Plan

     27.33         1,235,235        —     

Elissa M. Ecker

  

NRECA Retirement

Security Plan

     9.08         340,725        —     

 

(1)  Beginning in 1998 thru December 31, 2006, Mr. Reasor participated in a pension restoration severance pay plan and was the only participant in the plan. Mr. Reasor’s accrued benefits under this plan were frozen and will be paid to Mr. Reasor upon termination of employment.

The pension benefits indicated above are the estimated amounts payable by the plan, and they are not subject to any deduction for social security or other offset amounts. The participant’s annual pension at his or her normal retirement date, currently age 62, is equal to the product of his or her years of benefit service times final average salary times the multiplier in effect during years of benefit service. The multiplier was 1.7% commencing January 1, 1992. The number of years of credited service is as of the end of the current year for each of the named executives. The present value of accumulated benefit is calculated assuming that the executive retires at the normal retirement age per the plan, but using current number of years of credited service, and that he or she receives a lump sum. The lump sum amounts are calculated using the 30-year Treasury rate (3.80% for 2014, and 2.80% for 2013) and the PPA three segment yield rates (1.19%, 4.53%, and 5.66% for 2014, and 0.97%, 3.50%, and 4.60% for 2013) and the required Internal Revenue Service mortality table for lump sum payments (1994 GAS, projected to 2002, blended 50%/50% for unisex mortality in combination with the 30-year Treasury rates and PPA RP 2000 at 2014 combined unisex 50%/50% mortality in combination with the PPA rates.) Lump sums at normal retirement age are then discounted to the last day of the appropriate year using these same assumptions shown for the respective stated interest rates.

During 2014, Mr. Reasor and Mr. Kees reached normal retirement age, 62, under the pension restoration plan. In 2014, in accordance with the pension restoration plan, Mr. Reasor and Mr. Kees each received payment of their respective pension restoration plan benefits as of December 31, 2014. Mr. Reasor and Mr. Kees will continue to earn benefit credit for as long as they each continue to work after December 31, 2014.

Prior to the pension restoration plan, from 1998 through December 31, 2006, Mr. Reasor participated in a pension restoration severance pay plan, which was also intended to provide a supplemental benefit for employees who would have a reduction in their pension benefit because of IRC limitations. Mr. Reasor was the only participant in the plan. Mr. Reasor’s accrued benefits under this plan were frozen at December 31, 2004 and July 1, 2006. The amounts frozen are $45,852 and $60,817, respectively, for a total of $106,669. These amounts will be paid to Mr. Reasor upon termination of employment.

Also during 2014, Mr. Reasor and Mr. Kees reached normal retirement age, 62, under the NRECA Retirement Security Plan, and the plan provides for quasi-retirement. Quasi-retirement refers to a one-time election option under the plan that permits a participant to receive the benefit at any time after reaching normal retirement age, even if the participant continues to work for an employer that participates in the plan. Mr. Reasor elected quasi-retirement

 

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effective February 28, 2015 and Mr. Kees elected quasi-retirement effective January 31, 2015. Both Mr. Reasor and Mr. Kees continue to work for ODEC. The quasi-retirement benefit for Mr. Reasor was a lump sum cash distribution of $1,176,790 and was calculated based on a February 27, 2015 quasi-retirement date. The quasi-retirement benefit for Mr. Kees was a lump sum cash distribution of $1,720,052, and was calculated based on a January 15, 2015 quasi-retirement date. Mr. Reasor and Mr. Kees will continue to earn benefit credit for as long as they each continue to work after the quasi-retirement date. Once Mr. Reasor and Mr. Kees retire, they will receive a benefit for the time worked after the quasi-retirement date.

Deferred Compensation Plan

In 2006, in connection with the execution of the employment agreement with Mr. Reasor, we adopted the Deferred Compensation Plan, which is a non-qualified plan, for the purpose of providing supplemental deferred compensation to Mr. Reasor in an amount within the statutory maximums permitted under IRC Section 457. The Deferred Compensation Plan is restricted to those executive employees designated by our board of directors who are generally responsible for ongoing operations, responsible for and have general supervision over the overall financial condition, responsible for setting and executing overall corporate policies and practices, and responsible for supervising large numbers of employees and who elect to participate in the Deferred Compensation Plan by agreeing to a deferral of a portion of their current compensation. Currently, Mr. Reasor is the only participant in the Deferred Compensation Plan. Under the Deferred Compensation Plan, annual deferrals cannot exceed the lesser of 100% of Mr. Reasor’s annual compensation or $17,500 for 2014 and $18,000 for 2015, adjusted by and subject to specified tax laws (the “deferral limit”), during any year in which we are exempt from federal income taxation. During the last three years before Mr. Reasor attains the normal retirement age under our defined benefit pension plan, the deferral limit is increased to the lesser of two times the deferral limit or the deferral limit plus the amount Mr. Reasor was eligible to but did not defer under the Deferred Compensation Plan. Mr. Reasor attained normal retirement age during 2014. Amounts credited to him under the Deferred Compensation Plan will be credited with earnings or losses equal to those made by an investment in one or more funds of a specified regulated investment company designated by him. Distributions under the Deferred Compensation Plan generally commence upon severance of employment, whether upon termination, retirement or death.

The following table sets forth the non-qualified deferred compensation paid to our executive officers in 2014:

NON-QUALIFIED DEFERRED COMPENSATION

 

Name

   Executive
Contributions
in Last Fiscal
Year
     Registrant
Contributions
in Last Fiscal
Year
     Aggregate
Gains in
Last Fiscal
Year
     Aggregate
Withdrawals/
Distributions
     Aggregate
Balance at
Last Fiscal
Year End
 

Jackson E. Reasor

   $ —         $ 15,000       $ 10,387       $ —         $ 197,937   

Robert L. Kees

     n/a         n/a         n/a         n/a         n/a   

D. Richard Beam

     n/a         n/a         n/a         n/a         n/a   

Elissa M. Ecker

     n/a         n/a         n/a         n/a         n/a   

 

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The following table sets forth information concerning all other compensation awarded to, earned by, or paid to these executives during the last completed fiscal year.

ALL OTHER COMPENSATION

 

Name

   Perquisites
and Other
Personal
Benefits(1)(2)
     Company-
paid Life
Insurance
     All Other
Compensation
 

Jackson E. Reasor

   $ 22,451       $ 2,905       $ 25,356   

Robert L. Kees

     5,200         1,641         6,841   

D. Richard Beam

     5,200         1,452         6,652   

Elissa M. Ecker

     3,916         1,152         5,068   

 

(1)  Includes contributions made by ODEC to the 401(k) plan.
(2)  For Mr. Reasor, also includes $15,000 company contribution to the non-qualified deferred compensation plan and $2,251 for personal use of a company automobile.

Board of Directors Compensation

It is our policy to compensate the members of our board of directors who are not employed by one of our member distribution cooperatives (“outside directors”). Our outside directors were compensated by a monthly retainer of $2,500 for the first two months of 2014 and were compensated by a monthly retainer of $3,000 for the remainder of 2014. They were also paid for meetings and other official activities at a rate of $400 per day and $200 per partial day and for teleconferences, if such meetings or other official activities occurred outside the normal board of directors meeting dates for the first two months of 2014. For the remainder of 2014, our outside directors were also paid for meetings and other official activities at a rate of $500 per day and $250 per partial day and for teleconferences, if such meetings or other official activities occurred outside the normal board of directors meeting dates. All directors are entitled to be reimbursed for out-of-pocket expenses incurred in attending meetings. Our directors receive no other compensation from us. We do not provide our directors pension benefits, non-equity incentive plan compensation, or other perquisites and because we are a cooperative, we do not have stock or other equity options. The following table sets forth the compensation we paid to our directors in 2014:

DIRECTOR COMPENSATION

 

Name

   Fees Earned or
Paid in Cash
 

Paul H. Brown

   $ 37,500   

Darlene H. Carpenter

     38,950   

Earl C. Currin, Jr.

     37,000   

E. Garrison Drummond

     36,250   

Fred C. Garber

     36,750   

Hunter R. Greenlaw, Jr.

     38,200   

Bruce A. Henry

     37,450   

David J. Jones

     37,450   

Paul E. Owen

     37,150   

Keith L. Swisher

     36,750   

Carl R. Widdowson

     39,050   
  

 

 

 
$ 412,500   
  

 

 

 

 

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Compensation Committee Interlocks and Insider Participation

As described above, the executive committee of our board of directors establishes and the full board of directors approves all compensation and awards to the CEO. Our board of directors has delegated to our CEO the authority to establish and adjust compensation for all employees other than himself. Other than the two exceptions noted below, no member of our board of directors is or previously was an officer or employee of ODEC or is or has engaged in transactions with ODEC. Mr. Gregory W. White was an employee of ODEC from 1990 to 1996 and from 1999 to 2005 when he left his position as Senior Vice President of Power Supply to become the President and Chief Executive Officer of Northern Neck Electric Cooperative, one of our member distribution cooperatives. Mr. John C. Lee, Jr. was an employee of ODEC from 1992 to 2007 when he left his position as Vice President of Member and External Relations to become the President and Chief Executive Officer of Mecklenburg Electric Cooperative, one of our member distribution cooperatives. All of our directors are employees or directors of our member distribution cooperatives.

Under our executive committee charter, the executive committee’s duties and responsibilities include (1) recommending all compensation for ODEC’s CEO to the entire board of directors for its approval and (2) serving as the compensation committee of the board of directors to review and discuss with management the contents of the Compensation Discussion and Analysis section of the Annual Report on Form 10-K and to recommend to the board of directors inclusion of the Compensation Discussion and Analysis section in the Annual Report on Form 10-K each year.

Compensation Committee Report

The executive committee serves as the compensation committee of the board of directors and has reviewed and discussed with the management of ODEC the contents of the Compensation Discussion and Analysis section and, based on such review and discussion, has recommended to the board of directors its inclusion in this Annual Report on Form 10-K.

Myron D. Rummel, Chairman

J. William Andrew, Jr.

E. Garrison Drummond

Kent D. Farmer

Hunter R. Greenlaw, Jr.

David J. Jones

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Not Applicable.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

AND DIRECTOR INDEPENDENCE

Because we are a cooperative, all of our directors are representatives of our members. Our members include our member distribution cooperatives, which are our principal customers, and TEC. Due to the extent of the payments by each member distribution cooperative to us, our directors are not independent based on the definition of “independence” of the New York Stock Exchange.

 

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The following table presents fees for services provided by Ernst & Young LLP for the two most recent fiscal years. All Audit, Audit-Related, and Tax Fees shown below were pre-approved by the Audit Committee in accordance with its established procedures.

 

     2014      2013  

Audit Fees (1)

   $ 300,000       $ 285,000   

Audit-Related Fees (2)

     —           92,203   

Tax Fees (3)

     16,626         5,950   
  

 

 

    

 

 

 

Total

$ 316,626    $ 383,153   
  

 

 

    

 

 

 

 

(1)  Fees for professional services provided for the audit of ODEC’s annual financial statements as well as reviews of ODEC’s quarterly financial statements, accounting consultations on matters addressed during the audit or interim reviews, and SEC filings and offering memorandums including comfort letters, consents, and comment letters.
(2)  Fees for professional services which principally include accounting consultations and due diligence services.
(3)  Fees for professional services for tax-related advice and compliance.

For fiscal years 2014 and 2013, other than those fees listed above, we did not pay Ernst & Young LLP any fees for any other products or services.

Audit Committee Preapproval Process for the Engagement of Auditors

All audit, tax, and other services to be performed by Ernst & Young LLP for us must be pre-approved by the Audit Committee. The Audit Committee reviews the description of the services and an estimate of the anticipated costs of performing those services. Pre-approval is granted usually at regularly scheduled meetings. During 2014 and 2013, all services performed by Ernst & Young LLP were pre-approved by the Audit Committee in accordance with this policy.

 

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PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

 

  a) The following documents are filed as part of this Form 10-K.

 

  1. Financial Statements

See Index on page 51.

 

  2. Financial Statement Schedules

Not applicable.

 

  3. Exhibits

Exhibits

*3.1 Amended and Restated Articles of Incorporation of Old Dominion Electric Cooperative (filed as exhibit 3.1 to the Registrant’s Form 10-Q, File No. 33-46795, filed on August 11, 2000).

*3.2 Bylaws of Old Dominion Electric Cooperative, Amended and Restated as of December 31, 2008, as amended on November 11, 2008 (filed as exhibit 3 to the Registrant’s Form 8-K, File No. 000-50039, filed on November 14, 2008).

*4.1 Second Amended and Restated Indenture of Mortgage and Deed of Trust, dated as of January 1, 2011, between Old Dominion Electric Cooperative and Branch Banking and Trust Company, as Trustee (filed as exhibit 4.1 to the Registrant’s Form 10-K for the year ended December 31, 2010, File No. 000-50039, on March 16, 2011).

*4.2 First Supplemental Indenture, dated as of April 1, 2011, to the Second Amended and Restated Indenture of Mortgage and Deed of Trust, dated as of January 1, 2011, between Old Dominion Electric Cooperative and Branch Banking and Trust Company, as Trustee, including the form of the 2011 Series A, B, and C Bonds (filed as exhibit 4.1 to the Registrant’s Form 8-K dated April 7, 2011, File No. 000-50039, on April 8, 2011).

*4.3 Second Supplemental Indenture, dated as of June 1, 2013, to the Second Amended and Restated Indenture of Mortgage and Deed of Trust, dated as of January 1, 2011, between Old Dominion Electric Cooperative and Branch Banking and Trust Company, as Trustee, including the form of the 2013 Series A and B Bond (filed as exhibit 4.1 to the Registrant’s Form 8-K dated June 28, 2013, File No. 000-50039, on July 2, 2013).

*4.4 Third Supplemental Indenture, dated as of November 1, 2014, to the Second Amended and Restated Indenture of Mortgage and Deed of Trust, dated as of January 1, 2011, between Old Dominion Electric Cooperative and Branch Banking and Trust Company, as Trustee, including the form of the 2015 Series A and B Bond (filed as exhibit 4.1 to the Registrant’s Form 8-K dated January 15, 2014, File No. 000-50039, on January 16, 2015).

*4.5 Fifteenth Supplemental Indenture, dated as of May 1, 2003, to the Indenture of Mortgage and Deed of Trust dated as of May 1, 1992, between Old Dominion Electric Cooperative and SunTrust Bank (formerly Crestar Bank), as Trustee (filed as Exhibit 4.A to the Registrant’s Form 10-K for the year ended December 31, 2003, File No. 000-50039, on March 22, 2004).

*4.7 Seventeenth Supplemental Indenture, dated as of January 1, 2004, to the Indenture of Mortgage and Deed of Trust dated as of May 1, 1992, between Old Dominion Electric Cooperative and SunTrust Bank (formerly Crestar Bank), as Trustee (filed as Exhibit 4.B to the Registrant’s Form 10-K for the year ended December 31, 2003, File No 000-50039, on March 22, 2004).

 

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*10.1 Nuclear Fuel Agreement between Virginia Electric and Power Company and Old Dominion Electric Cooperative, dated as of December 28, 1982, amended and restated October 17, 1983 (filed as exhibit 10.1 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on March 27, 1992).

*10.2 Purchase, Construction and Ownership Agreement between Virginia Electric and Power Company and Old Dominion Electric Cooperative, dated as of December 28, 1982, amended and restated October 17, 1983 (filed as exhibit 10.2 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on March 27, 1992).

*10.3 Clover Purchase, Construction and Ownership Agreement between Old Dominion Electric Cooperative and Virginia Electric and Power Company, dated as of May 31, 1990 (filed as exhibit 10.4 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on March 27, 1992).

*10.4 Amendment No. 1 to the Clover Purchase, Construction and Ownership Agreement between Old Dominion Electric Cooperative and Virginia Electric and Power Company, effective March 12, 1993 (filed as exhibit 10.34 to the Registrant’s Form S-1 Registration Statement, File No. 33-61326, filed on April 19, 1993).

*10.5 Clover Operating Agreement between Virginia Electric and Power Company and Old Dominion Electric Cooperative, dated as of May 31, 1990 (filed as exhibit 10.6 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on March 27, 1992).

*10.6 Amendment to the Clover Operating Agreement between Virginia Electric and Power Company and Old Dominion Electric Cooperative, effective January 17, 1995 (filed as exhibit 10.8 to the Registrant’s Form 10-K for the year ended December 31, 1994, File No. 33-46795, on March 15, 1995).

*10.7 Lease Agreement between Old Dominion Electric Cooperative and Regional Headquarters, Inc., dated July 29, 1986 (filed as exhibit 10.27 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on March 27, 1992).

10.8 Nuclear Decommissioning Trust Agreement between Old Dominion Electric Cooperative and SunTrust Bank, (formerly Crestar Bank), dated June 1, 1999.

*10.9 Form of Salary Continuation Plan (filed as exhibit 10.31 to the Registrant’s Form S-1 Registration Statement, File No. 33-46795, filed on March 27, 1992).

*, ***10.10 Second Amended and Restated Wholesale Power Contract between Old Dominion Electric Cooperative and A&N Electric Cooperative, dated January 1, 2009 (filed as exhibit 10.2 and 10.3 to the Registrant’s Form 10-Q for the quarterly period ended September 30, 2008, File No. 33-46795, filed on November 11, 2008).

*10.11 Interconnection Agreement between Delmarva Power & Light Company and Old Dominion Electric Cooperative, dated November 30, 1999 (filed as exhibit 10.33 to the Registrant’s Form 10-K for the year ended December 31, 2000, File No. 33-46795, on March 19, 2001).

*,**10.12 Participation Agreement, dated as of February 29, 1996, among Old Dominion Electric Cooperative, State Street Bank and Trust Company, the Owner Participant named therein and Utrecht America Finance Co (filed as exhibit 10.35 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

*,**10.13 Clover Unit 1 Equipment Interest Lease Agreement, dated as of February 29, 1996, between Old Dominion Electric Cooperative, as Equipment Head Lessor, and State Street Bank and Trust Company, as Equipment Head Lessee (filed as exhibit 10.36 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

 

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*,**10.14 Equipment Operating Lease Agreement, dated as of February 29, 1996, between State Street Bank and Trust Company, as Lessor, and Old Dominion Electric Cooperative, as Lessee (filed as exhibit 10.37 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

*,**10.15 Corrected Option Agreement to Lease, dated as of February 29, 1996, among Old Dominion Electric Cooperative and State Street Bank and Trust Company (filed as exhibit 10.38 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

*,**10.16 Clover Agreements Assignment and Assumption Agreement, dated as of February 29, 1996, between Old Dominion Electric Cooperative, as Assignor, and State Street Bank and Trust Company, as Assignee (filed as exhibit 10.39 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

*,**10.17 Payment Undertaking Agreement, dated as of February 29, 1996, between Old Dominion Electric Cooperative and Cooperative Centrale Raiffeisen Boerenleenbank B.A., “Rabobank Nederland”, New York Branch (filed as exhibit 10.42 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

*,**10.18 Payment Undertaking Pledge Agreement, dated as of February 29, 1996, between Old Dominion Electric Cooperative, as Payment Undertaking Pledgor, and State Street Bank and Trust Company, as Payment Undertaking Pledgee (filed as exhibit 10.43 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

*,**10.19 Pledge Agreement, dated as of February 29, 1996, between Old Dominion Electric Cooperative, as Pledgor, and State Street Bank and Trust Company, as Pledgee (filed as exhibit 10.44 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

*,**10.20 Tax Indemnity Agreement, dated as of February 29, 1996, among Old Dominion Electric Cooperative, State Street Bank and Trust Company, the Owner Participant named therein and Utrecht America Finance Co. (filed as exhibit 10.45 to the Registrant’s Form 10-K for the year ended December 31, 1996, File No. 33-46795, on March 20, 1997).

*,**10.21 Amendment No. 3 to Participation Agreement (filed as Exhibit 10.1 to the Registrant’s Form 10-Q for the quarter ended March 31, 2006, File No. 000-50039, on May 12, 2006).

*,**10.22 Amendment No. 2 to Equipment Operating Lease Agreement (filed as Exhibit 10.2 to the Registrant’s Form 10-Q for the quarter ended March 31, 2006, File No. 000-50039, on May 12, 2006).

*,**10.23 Amendment No. 2 to Corrected Foundation Operating Lease Agreement (filed as Exhibit 10.3 to the Registrant’s Form 10-Q for the quarter ended March 31, 2006, File No. 000-50039, on May 12, 2006).

*,**10.24 Investment Agreement (filed as Exhibit 10.4 to the Registrant’s Form 10-Q for the quarter ended March 31, 2006, File No. 000-50039, on May 12, 2006).

*,**10.25 Investment Pledge Agreement (filed as Exhibit 10.5 to the Registrant’s Form 10-Q for the quarter ended March 31, 2006, File No. 000-50039, on May 12, 2006).

*,**10.26 Amendment No. 3 to Payment Undertaking Agreement (filed as Exhibit 10.6 to the Registrant’s Form 10-Q for the quarter ended March 31, 2006, File No. 000-50039, on May 12, 2006).

 

 

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*,**10.27 Amendment No. 2 to Tax Indemnity Agreement (filed as Exhibit 10.7 to the Registrant’s Form 10-Q for the quarter ended March 31, 2006, File No. 000-50039, on May 12, 2006).

*10.28 Employment Agreement, dated June 1, 2012, between Old Dominion Electric Cooperative and Jackson E. Reasor and accepted by Jackson E. Reasor on May 23, 2012 (filed as Exhibit 10.1 to the Registrant’s Form 8-K, File No. 000-50039, on May 25, 2012).

*10.29 Executive Deferred Compensation Plan, dated June 30, 2006, adopted on December 18, 2006 (filed as Exhibit 10.2 to the Registrant’s Form 8-K File No. 000-50039, on December 21, 2006).

*10.30 Employment letter, dated November 28, 2005, of Old Dominion Electric Cooperative and agreed and accepted by Robert L. Kees (filed as exhibit 10.1 to the Registrant’s Form 8-K, No. 000-50039, on November 28, 2005).

*,**10.31 Amendment No. 1 to Participation Agreement, dated as of December 19, 2002, among Old Dominion Electric Cooperative, State Street Bank and Trust Company, the Owner Participant named therein, Utrecht America Finance Co and Cedar Hill International Corp.

*,**10.32 Amendment No. 1 to Equipment Operating Lease Agreement, dated as of December 19, 2002, between State Street Bank and Trust Company, as Lessor, and Old Dominion Electric Cooperative, as Lessee.

*,**10.33 Amendment No. 1. to Corrected Foundation Operating Lease Agreement, dated as of December 19, 2002, between State Street Bank and Trust Company, as Foundation Lessor and Old Dominion Electric Cooperative, as Foundation Lessee.

*,**10.34 Amendment No. 2 to Payment Undertaking Agreement, dated as of December 19, 2002 between Old Dominion Electric Cooperative and Cooperatieve Centrale Raiffeisen Boerenleenbank B.A., “Rabobank Nederland”, New York Branch.

*,**10.35 Amendment No. 1 to Tax Indemnity Agreement, dated as of December 19, 2002, between Old Dominion Electric Cooperative and the Owner Participant named therein.

*,**10.36 Amendment No. 2 to Participation Agreement, dated as of December 31, 2004, between and among Old Dominion Electric Cooperative, U.S. Bank National Association, Wachovia Bank, National Association, Utrecht-America Finance Co., and Cedar Hill International Corp. (filed as exhibit 10.1 to the Registrant’s Form 8-K, File No. 000-50039, on January 13, 2005).

*10.37 Mutual Operating Agreement, dated as of May 18, 2005, between Virginia Electric and Power Company and Old Dominion Electric Cooperative.

*10.38 Employment letter, dated March 30, 2007, of Old Dominion Electric Cooperative and agreed and accepted by Bryan S. Rogers (filed as exhibit 10.1 to the Registrant’s Form 8-K, No. 000-50039, on April 2, 2008).

*10.39 Credit Agreement, dated as of November 21, 2011, among Old Dominion Electric Cooperative, the lenders, party thereto, the Issuing Lenders party thereto, and Wells Fargo Bank, National Association, as Administrative Agent and Swingline Lender. (filed as exhibit 10.39 to the Registrant’s Form 10-K for the year ended December 31, 2011, File No. 000-50039, on March 14, 2012).

*10.40 First amendment to Credit Agreement, dated as of March 12, 2014, among Old Dominion Electric Cooperative, the lenders, party thereto, the Issuing Lenders party thereto, and Wells Fargo Bank, National Association, as Administrative Agent and Swingline Lender. (filed as exhibit 10.1 to the Registrant’s Form 10-Q for the quarterly period ended March 31, 2014, File No. 000-50039, on May 9, 2014).

 

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10.41 Amended and Restated Severance Pay Pension Restoration Plan effective January 1, 2015.

10.42 Amended and Restated Deferred Compensation Pension Restoration Plan effective January 1, 2015.

21 Subsidiaries of Old Dominion Electric Cooperative (not included because Old Dominion Electric Cooperative’s subsidiaries, considered in the aggregate as a single subsidiary, would not constitute a “significant subsidiary” under Rule 102(w) of Regulation S-X).

23.1 Consent of Ernst & Young LLP

31.1 Certification of the Principal Executive Officer pursuant to Rule 13a-14(a)

31.2 Certification of the Principal Financial Officer pursuant to Rule 13a-14(a)