UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

(Mark One)

 

 

 

For the quarterly period ended March 31, 2017

or

 

 

 

 

For the transition period from                      to                     

 

Commission file number 000-50039

 

OLD DOMINION ELECTRIC COOPERATIVE

(Exact name of registrant as specified in its charter)

 

 

 

 

 

(804) 747-0592

(Registrant’s telephone number, including area code)

 

 

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 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  ☒

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  ☒    No  ☐

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 definitions of “larger accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ☐    No  ☒

The Registrant is a membership corporation and has no authorized or outstanding equity securities.

 

 

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GLOSSARY OF TERMS

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

 

 

 

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OLD DOMINION ELECTRIC COOPERATIVE

INDEX

 

 

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OLD DOMINION ELECTRIC COOPERATIVE

PART 1.  FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

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

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OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS OF REVENUES,

EXPENSES, AND PATRONAGE CAPITAL (UNAUDITED)

 

 

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

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OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

 

 

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

 

 

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OLD DOMINION ELECTRIC COOPERATIVE

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

 

 

 

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X.  In the opinion of management, the accompanying unaudited condensed consolidated financial statements contain all adjustments, which include only normal recurring adjustments, necessary for a fair statement of our consolidated financial position as of March 31, 2017, our consolidated results of operations for the three months ended March 31, 2017 and 2016, and cash flows for the three months ended March 31, 2017 and 2016.  The consolidated results of operations for the three months ended March 31, 2017, are not necessarily indicative of the results to be expected for the entire year.  These financial statements should be read in conjunction with the financial statements and notes thereto included in our 2016 Annual Report on Form 10-K filed with the Securities and Exchange Commission.

The accompanying financial statements reflect the consolidated accounts of Old Dominion Electric Cooperative and TEC.  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 Class A members are eleven customer-owned electric distribution cooperatives engaged in the retail sale of power to member customers located in Virginia, Delaware, and Maryland.  Our sole Class B member is TEC, a taxable corporation 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.  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.  The assets and liabilities and non-controlling interest of TEC are recorded at carrying value and the consolidated assets were $5.7 million at March 31, 2017 and December 31, 2016.  The income taxes reported on our Condensed Consolidated Statement of Revenues, Expenses, and Patronage Capital relate to the tax provision for TEC.  As TEC is wholly-owned by our Class A members, its equity is presented as a non-controlling interest in our consolidated financial statements.

Our rates are set periodically by a formula that was accepted for filing by FERC, but are not regulated by the respective public service commissions of the states in which our member distribution cooperatives operate.  See Note 5—Other—FERC Proceeding Related to Formula Rate below.

We comply with the Uniform System of Accounts as 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 condensed 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 do not have any other comprehensive income for the periods presented.

 

 

 

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 March 31, 2017 and December 31, 2016: 

 

 

 

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.

 

 

 

 

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 of the Notes to Consolidated Financial Statements in our 2016 Annual Report on Form 10-K.

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 Condensed 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:

 

 

 

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

 

 

The Effect of Derivative Instruments on the Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital for the Three Months Ended March 31, 2017 and 2016

 

 

Our hedging activities expose us to credit-related risks.  We use hedging instruments, including forwards, futures, financial transmission rights, and options, to mitigate our power market price risks.  Because we rely substantially on the use of hedging instruments, we are exposed to the risk that counterparties will default in performance of their obligations to us.  Although we assess the creditworthiness of counterparties and other credit issues related to these hedging instruments, and we may require our counterparties to post collateral with us, defaults may still occur.  Defaults may take the form of failure to physically deliver purchased energy or failure to pay.  If a default occurs, we may be forced to enter into alternative contractual arrangements or purchase energy in the forward, short-term, or spot markets at then-current market prices that may exceed the prices previously agreed upon with the defaulting counterparty.

 

 

 

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Investments were as follows as of March 31, 2017 and December 31, 2016:

 

 

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Our investments by classification as of March 31, 2017 and December 31, 2016, were as follows:

 

 

Contractual maturities of debt securities as of March 31, 2017, were as follows:

 

 

 

 

 

 

Wildcat Point Generation Facility

We are currently constructing, and will be the sole owner of, an approximate 1,000 MW natural gas-fueled combined cycle generation facility, named Wildcat Point, in Cecil County, Maryland.  The current construction schedule has Wildcat Point achieving commercial operation mid-2017.  While the contractual completion date has not been revised, our engineering consultant advises us that it expects that commercial operation of the facility is more likely to occur at the end of the third quarter or early in the fourth quarter of 2017.  The EPC contractor advises us that the delay is associated with the incurrence of additional work and other matters, for which it will seek recovery, in whole or in part, from its subcontractors and us.  We disagree that we have additional liability under the contract and therefore have not revised our estimated project cost of $834.3 million.  We do not believe that any such delay in the commencement of commercial operation of the Wildcat Point facility, or any additional amounts associated with the delay, including PJM capacity delay charges, for which we may be ultimately responsible, are reasonably likely to have a material adverse effect on our results of operations or financial condition due to our ability to collect such amounts through rates charged to our member distribution cooperatives.  Even if we are ultimately responsible for additional costs, any such amounts may be offset in part by liquidated damages under the contract associated with the EPC contractor’s delay in achieving substantial completion.

Wildcat Point's major equipment will consist of two Mitsubishi combustion turbines, two Alstom heat recovery steam generators, and one Alstom steam turbine generator.  Through March 31, 2017, we capitalized construction costs related to Wildcat Point totaling $748.5 million, including $51.1 million of capitalized interest.

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FERC Proceeding Related to Formula Rate

On September 30, 2013, we filed with FERC to revise our cost-based formula rate in order 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.  On April 13, 2015, we received an initial decision from the hearing judge.  On January 19, 2017, FERC issued its order on the hearing judge's initial decision.  On February 21, 2017, we submitted our compliance filing, revising the formula rate as directed in the order.  Additionally, on February 21, 2017, Bear Island filed a request for rehearing.  On March 22, 2017, FERC issued an order granting rehearing of its initial order for the limited purpose of FERC's further consideration of the matter.  Our formula rate remains in effect subject to refund pending a final order from FERC.  If a refund is ultimately determined, we believe it will result in a reallocation of costs among our member distribution cooperatives.

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.  On June 9, 2015, FERC denied our petition, on July 9, 2015, we filed a request for rehearing, and on August 10, 2015, FERC issued an order granting rehearing for the limited purpose of FERC's further consideration of the matter.  On March 1, 2016, FERC denied our request for rehearing and on April 11, 2016, we filed a Petition for Review in the U.S. Court of Appeals for the District of Columbia Circuit.  Also related to this matter, on January 5, 2017, we filed a complaint and request for relief in the Circuit Court for the County of Henrico in the Commonwealth of Virginia.  We have not recorded a receivable related to this matter.

Revolving Credit Facility

We maintain a $500.0 million revolving credit facility to cover our short-term and medium-term funding needs that are not met by cash from operations or other available funds.  The syndicated credit agreement associated with the facility was amended and restated on March 3, 2017, and commitments under this agreement extend until March 3, 2022.  As of March 31, 2017, we had outstanding under this facility, $181.8 million in borrowings and $12.2 million in letters of credit.  As of December 31, 2016, we had outstanding under this facility, $152.0 million in borrowings and $5.2 million in letters of credit.

Long-term Debt

We currently anticipate that we will issue long-term debt in the third quarter of 2017 to fund capital expenditures related to Wildcat Point construction costs.

Limited Exception under Wholesale Power Contracts

We have a wholesale power contract with each of our member distribution cooperatives.  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.  One of the limited exceptions permits each of our member distribution cooperatives to receive up to the greater of 5% of its demand and associated energy or 5 MW of demand and associated energy from owned generation or other suppliers.  If all of our member distribution cooperatives elected to utilize the 5% or 5 MW exception, we estimate the current impact would be a reduction of approximately 175 MW of demand and associated energy.  As of March 31, 2016, our member distribution cooperatives collectively received approximately 9 MW under this exception.  Effective May 1, 2016, one of our member distribution cooperatives elected to purchase 51 MW of demand and associated energy from an alternate supplier, bringing the collective removal of load requirements under this exception to approximately 60 MW.  We do not anticipate that utilization of this exception will have a material impact on our financial condition, results of operations, or cash flows.

 

 

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Retail Choice in Virginia

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.  Currently, no customer of our member distribution cooperatives has elected to choose an alternate supplier under this provision.  Retail choice is also available to any customer whose noncoincident peak demand exceeds 90 MW.  Beginning June 1, 2016, Bear Island, an industrial customer of REC and the only customer of any of our member distribution cooperatives that has noncoincident peak demand that exceeds 90 MW, elected to purchase its power requirements from an alternate supplier.  We do not anticipate that this will have a material impact on our financial condition, results of operations, or cash flows.

New Accounting Pronouncements

In May 2014, the FASB issued Accounting Standards Update 2014-09 Revenue from Contracts with Customers.  This update requires entities to recognize revenue when the transfer of promised goods or services to customers occurs in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  We are currently evaluating the impact of this pronouncement.  We plan to adopt this standard for the fiscal year beginning January 1, 2018.

 

In February 2016, the FASB issued Accounting Standards Update 2016-02 Leases (Subtopic 835-30).  This update revised accounting guidance for the recognition, measurement, presentation and disclosure of leasing arrangements.  The update requires the recognition of lease assets and liabilities for those leases currently classified as operating leases while also refining the definition of a lease.  In addition, lessees will be required to disclose key information about the amount, timing, and uncertainty of cash flows arising from leasing arrangements.  We are currently evaluating the impact of this pronouncement.  We plan to adopt this standard for the fiscal year beginning January 1, 2019.

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OLD DOMINION ELECTRIC COOPERATIVE

ITEM 2.  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.

Critical Accounting Policies

As of March 31, 2017, there have been no significant changes in our critical accounting policies as disclosed in our 2016 Annual Report on Form 10-K.  These policies include the accounting for regulated operations, deferred energy, margin stabilization, accounting for asset retirement and environmental obligations, and accounting for derivatives and hedging.

Basis of Presentation

The accompanying financial statements reflect the consolidated accounts of ODEC and TEC.  See Note 1—Notes to Condensed Consolidated Financial Statements in Part 1, Item 1.

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 purchases.  We also supply the transmission services necessary to deliver this power to our member distribution cooperatives.

Our results for the three months ended March 31, 2017, were primarily impacted by decreases in our total energy rate, changes in our member distribution cooperatives’ requirements for power, the dispatch of our generating facilities, and our continued investment in Wildcat Point.  

 

 

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Wildcat Point Generation Facility

We are currently constructing, and will be the sole owner of, an approximate 1,000 MW natural gas-fueled combined cycle generation facility, named Wildcat Point, in Cecil County, Maryland.  The current construction schedule has Wildcat Point achieving commercial operation mid-2017.  While the contractual completion date has not been revised, our engineering consultant advises us that it expects that commercial operation of the facility is more likely to occur at the end of the third quarter or early in the fourth quarter of 2017.  The EPC contractor advises us that the delay is associated with the incurrence of additional work and other matters, for which it will seek recovery, in whole or in part, from its subcontractors and us.  We disagree that we have additional liability under the contract and therefore have not revised our estimated project cost of $834.3 million.  We do not believe that any such delay in the commencement of commercial operation of the Wildcat Point facility, or any additional amounts associated with the delay, including PJM capacity delay charges, for which we may be ultimately responsible, are reasonably likely to have a material adverse effect on our results of operations or financial condition due to our ability to collect such amounts through rates charged to our member distribution cooperatives.  Even if we are ultimately responsible for additional costs, any such amounts may be offset in part by liquidated damages under the contract associated with the EPC contractor’s delay in achieving substantial completion.

Wildcat Point's major equipment will consist of two Mitsubishi combustion turbines, two Alstom heat recovery steam generators, and one Alstom steam turbine generator.  Through March 31, 2017, we capitalized construction costs related to Wildcat Point totaling $748.5 million, including $51.1 million of capitalized interest.

Limited Exception under Wholesale Power Contracts

We have a wholesale power contract with each of our member distribution cooperatives.  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.  One of the limited exceptions permits each of our member distribution cooperatives to receive up to the greater of 5% of its demand and associated energy or 5 MW of demand and associated energy from owned generation or other suppliers.  If all of our member distribution cooperatives elected to utilize the 5% or 5 MW exception, we estimate the current impact would be a reduction of approximately 175 MW of demand and associated energy.  As of March 31, 2016, our member distribution cooperatives collectively received approximately 9 MW under this exception.  Effective May 1, 2016, one of our member distribution cooperatives elected to purchase 51 MW of demand and associated energy from an alternate supplier, bringing the collective removal of load requirements under this exception to approximately 60 MW.  We do not anticipate that utilization of this exception will have a material impact on our financial condition, results of operations, or cash flows.  For further discussion on Wholesale Power Contracts, see “Business—Members—Member Distribution Cooperatives—Wholesale Power Contracts” in Item 1 of our 2016 Annual Report on Form 10-K.  

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Retail Choice in Virginia

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.  Currently, no customer of our member distribution cooperatives has elected to choose an alternate supplier under this provision.  Retail choice is also available to any customer whose noncoincident peak demand exceeds 90 MW.  Beginning June 1, 2016, Bear Island, an industrial customer of REC and the only customer of any of our member distribution cooperatives that has noncoincident peak demand that exceeds 90 MW, elected to purchase its power requirements from an alternate supplier.  We do not anticipate that this will have a material impact on our financial condition, results of operations, or cash flows.  For further discussion on Retail Choice in Virginia, see “Business—Members—Member Distribution Cooperatives—Competition” in Item 1 of our 2016 Annual Report on Form 10-K.  

Factors Affecting Results

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:

 

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.  The base energy rate 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 base energy rate is reset in accordance with our budget and the energy adjustment rate is reset to 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 II, Item 1.

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.  We collect our total demand costs through the following three separate rates:

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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.  

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.  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.

For the three months ended March 31, 2017 and 2016, we recorded a reduction in operating revenues of $18.0 million and $3.2 million, respectively, utilizing Margin Stabilization to produce a net margin equal to 20% of our actual total interest charges.  For further discussion of Margin Stabilization, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies—Margin Stabilization” in Item 7 of our 2016 Annual Report on Form 10-K.

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.  Heating and cooling degree days are measurement tools used to quantify the need to utilize heating or cooling, respectively, for a building.  The heating and cooling degree days for the three months ended March 31, 2017 and 2016, were as follows:

 

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Power Supply Resources

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; diesel-fired distributed generation facilities; and physically-delivered forward power purchase contracts and spot market energy purchases.  Our energy supply resources for the three months ended March 31, 2017 and 2016, were as follows:

 

 

Generating Facilities

Our operating expenses, and consequently our rates to our member distribution cooperatives, are significantly affected by the operations of our generating facilities, which are under dispatch control of PJM.  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.  For further discussion on PJM, see “Business—Power Supply Resources—PJM” in Item 1 of our 2016 Annual Report on Form 10-K.  

Operational Availability

The operational availability of our owned generating resources for the three months ended March 31, 2017 and 2016, was as follows:

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Capacity

The output of Clover and North Anna, our baseload facilities, for the three months ended March 31, 2017 and 2016, as a percentage of maximum dependable capacity rating of the facilities, was as follows:

 

Due to economic dispatch by PJM and outages, neither unit at Clover was dispatched for a significant portion of first quarter 2017.  

Outages

The scheduled and unscheduled outages for Clover and North Anna for the three months ended March 31, 2017 and 2016, were as follows:

 

The outage days above for Clover and North Anna reflect the total number of outage days for the two units at Clover and the two units at North Anna.

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 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 under its rates for providing energy imbalance service.  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.

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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 and our energy sales in MWh for the three months ended March 31, 2017 and 2016, were as follows:

 

Member Distribution Cooperatives

For the three months ended March 31, 2017, total revenues from sales to our member distribution cooperatives were 23.8% lower as compared to the same period in 2016, due to the decrease in energy and demand revenues.  Energy revenues decreased $41.0 million, or 27.4%, due to the 19.0% decrease in the average cost of energy sold to our member distribution cooperatives and the 10.3% decrease in energy sales in MWh to our member distribution cooperatives.  The average cost of energy sold to our member distribution cooperatives was impacted by the rate decreases we implemented in 2016 and 2017 (see table below).  The decrease in the volume of energy sales was primarily a result of the reduction in our load requirements related to retail choice in Virginia and a limited exception provision in our wholesale power contract.  See “Retail Choice in Virginia” and “Limited Exception under Wholesale Power Contracts” above.  These two events resulted in a 266,084 MWh load reduction in 2017 as compared to 2016.  Additionally, we experienced milder weather in 2017 as compared to 2016.  Demand revenues decreased $17.0 million, or 18.2%, primarily due to the $7.8 million decrease in transmission charges, the $6.8 million decrease in purchased power charges related to capacity, and the $2.1 million decrease in interest charges, net.

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

 

Non-members

Revenues from sales to non-members for the three months ended March 31, 2017, decreased $8.7 million, or 65.9%, as compared to the same period in 2016, due to a $5.5 million decrease in revenue from sales of renewable energy credits and a $3.2 million decrease in revenue from sales of excess energy.  The decrease in revenue from sales of excess energy was primarily due to a 52.7% decrease in the volume of excess energy sales.  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.

Operating Expenses

The following is a summary of the components of our operating expenses for the three months ended March 31, 2017 and 2016:

 

 

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, fuel expense, and the variable portion of operations and maintenance expense.  Our demand costs generally are fixed and include transmission expense, the capacity portion of our purchased power expense, the fixed portion of operations and maintenance expense, administrative and general expense, and depreciation and amortization 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 decreased $63.1 million, or 25.8%, for the three months ended March 31, 2017, as compared to the same period in 2016.  The decrease was primarily due to decreases in deferred energy expense, purchased power expense, and fuel expense.  

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Other Items

Investment Income

Investment income increased $1.4 million for the three months ended March 31, 2017, as compared to the same period in 2016, primarily due to increased earnings 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 three months ended March 31, 2017 and 2016, were as follows:

 

Interest charges, net decreased $2.1 million, or 25.4%, for the three months ended March 31, 2017, as compared to the same period in 2016, due to the increase in allowance for borrowed funds used during construction (capitalized interest) related to Wildcat Point.  

Net Margin Attributable to ODEC

Net margin attributable to ODEC, which is a function of our total interest charges plus any additional equity contributions approved by our board of directors, was relatively flat for the three months ended March 31, 2017, as compared to the same period in 2016.

Financial Condition

The principal changes in our financial condition from December 31, 2016 to March 31, 2017, were caused by the increases in construction work in progress, revolving credit facility, and accrued expenses, and decreases in accounts payable, deferred energy, and accounts receivable–members.

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Liquidity and Capital Resources

Sources

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

Operations

During the first three months of 2017 and 2016, our operating activities provided cash flows of $21.2 million and $43.9 million, respectively.  Operating activities in 2017 were primarily impacted by the following:

Revolving Credit Facility

We maintain a $500.0 million revolving credit facility to cover our short-term and medium-term funding needs that are not met by cash from operations or other available funds.  The syndicated credit agreement associated with the facility was amended and restated on March 3, 2017, and commitments under this agreement extend until March 3, 2022.  As of March 31, 2017, we had outstanding under this facility, $181.8 million in borrowings and $12.2 million in letters of credit.  As of December 31, 2016, we had outstanding under this facility, $152.0 million in borrowings and $5.2 million in letters of credit.

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.

We currently anticipate that we will issue long-term debt in the third quarter of 2017 to fund capital expenditures related to Wildcat Point construction costs.

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 revolving 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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ITEM 3.  QUANTITATIVE AND QUALITATIVE

DISCLOSURES ABOUT MARKET RISK

No material changes occurred in our exposure to market risk during the first quarter of 2017.

ITEM 4.  CONTROLS AND PROCEDURES

As of the end of the period covered by this report, our management, including the President and Chief Executive Officer, and Senior Vice President and Chief Financial Officer conducted an evaluation of the effectiveness of our disclosure controls and procedures.  Based upon that evaluation, the President and Chief Executive Officer, and Senior Vice President and Chief Financial Officer 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.  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 quarter.

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OLD DOMINION ELECTRIC COOPERATIVE

PART II.  OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS

FERC Proceeding Related to Formula Rate

On September 30, 2013, we filed with FERC to revise our cost-based formula rate in order 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.  On April 13, 2015, we received an initial decision from the hearing judge.  On January 19, 2017, FERC issued its order on the hearing judge's initial decision.  On February 21, 2017, we submitted our compliance filing, revising the formula rate as directed in the order.  Additionally, on February 21, 2017, Bear Island filed a request for rehearing.  On March 22, 2017, FERC issued an order granting rehearing of its initial order for the limited purpose of FERC's further consideration of the matter.  Our formula rate remains in effect subject to refund pending a final order from FERC.  If a refund is ultimately determined, we believe it will result in a reallocation of costs among our member distribution cooperatives.

Other Matters

Other than legal proceedings arising out of the ordinary course of business, which 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 1A.  RISK FACTORS

In addition to the other information set forth in this report, you should carefully consider the factors discussed in “Risk Factors” in Part I, Item 1A of our 2016 Annual Report on Form 10-K, which could affect our business, financial condition or future results.  The risks described in our Annual Report on Form 10-K are not the only risks facing us.  Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.

ITEM 5.  OTHER INFORMATION

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.  On June 9, 2015, FERC denied our petition, on July 9, 2015, we filed a request for rehearing, and on August 10, 2015, FERC issued an order granting rehearing for the limited purpose of FERC's further consideration of the matter.  On March 1, 2016, FERC denied our request for rehearing and on April 11, 2016, we filed a Petition for Review in the U.S. Court of Appeals for the District of Columbia Circuit.  Also related to this matter, on January 5, 2017, we filed a complaint and request for relief in the Circuit Court for the County of Henrico in the Commonwealth of Virginia.  We have not recorded a receivable related to this matter.  

 

 

 

 

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ITEM 6.  EXHIBITS

 

 

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

 

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EXHIBIT INDEX

 

 

 

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