UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

(Mark One)

 

 

 

For the quarterly period ended March 31, 2020

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 every Interactive Data File required to be submitted 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 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  ☒

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

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, 2020, our consolidated results of operations for the three months ended March 31, 2020 and 2019, and cash flows for the three months ended March 31, 2020 and 2019.  The consolidated results of operations for the three months ended March 31, 2020, 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 2019 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 eleven Class A members are 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 $5.9 million and $5.8 million as of March 31, 2020 and December 31, 2019, respectively.  The income taxes reported on our Condensed Consolidated Statements 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 public service commissions of the states in which our member distribution cooperatives operate.  

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.  The impact that the COVID-19 pandemic will have on our consolidated results of operations, financial condition, and cash flows is uncertain.  We continue to actively manage our business to respond to this health crisis and will continue to evaluate the nature and extent of any impact.

We did 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, 2020 and December 31, 2019: 

 

 

 

 

   

 

 

 

 

 

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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 2019 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.

Outstanding derivative instruments, excluding contracts accounted for as normal purchase/normal sale, were as follows:

 

 

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

 

 

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The Effect of Derivative Instruments on the Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital for the Three Months Ended March 31, 2020 and 2019

 

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, 2020 and December 31, 2019:

 

 

 

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Contractual maturities of debt securities as of March 31, 2020, were as follows:

 

 

 

 

 

 

 

Wildcat Point Generation Facility 

 We own Wildcat Point, a 973 MW (net capacity entitlement) natural gas-fueled combined cycle generation facility.  Wildcat Point achieved commercial operation on April 17, 2018.  In 2017, WOPC, a joint venture between PCL Industrial Construction Company and Sargent & Lundy, L.L.C., as EPC contractor, made a claim against Alstom and us for recovery of additional amounts under the EPC contract for Wildcat Point.  Additionally, in 2017, we filed a complaint alleging that WOPC breached the EPC contract.  Subsequently, the United States District Court for the Eastern District of Virginia ordered that the WOPC complaint against Alstom and us, our complaint against WOPC, and a separate complaint filed by WOPC against Mitsubishi, be consolidated.  In December 2019, ODEC and WOPC held formal settlement discussions and we recognized the probable impact of the settlement as of December 31, 2019, resulting in a $29.6 million increase to property, plant, and equipment.  On January 9, 2020, ODEC and WOPC settled their dispute and ODEC was dismissed as a party from the case.  

Revolving Credit Facility

We maintain a 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.  Commitments under this syndicated credit agreement extend until February 28, 2025.  Available funding under this facility totals $500 million through March 3, 2022, and $400 million from March 4, 2022 through February 28, 2025.  As of March 31, 2020, we had outstanding under this facility $250.0 million in borrowings and a $0.5 million letter of credit.  As of December 31, 2019, we had outstanding under this facility $67.2 million in borrowings and a $0.5 million letter of credit.

Cash and Cash Equivalents

For purposes of our Condensed 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.  

The following table provides a reconciliation of cash and cash equivalents and restricted cash and cash equivalents reported within the Condensed Consolidated Balance Sheets that sum to the total of the same amounts shown in the Condensed Consolidated Statements of Cash Flows:

Restricted cash and cash equivalents relates to funds held in escrow for payments related to the construction of Wildcat Point.

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Revenue Recognition

Our operating revenues are derived from sales of power and renewable energy credits to our member distribution cooperatives and non-members.  We supply power requirements (energy and demand) to our eleven member distribution cooperatives subject to substantially identical wholesale power contracts with each of them.  We bill our member distribution cooperatives monthly and each member distribution cooperative is required to pay us monthly for power furnished under its wholesale power contract.  We transfer control of the electricity over time and our member distribution cooperatives simultaneously receive and consume the benefits of the electricity.  The amount we invoice our member distribution cooperatives on a monthly basis corresponds directly to the value to the member distribution cooperatives of our performance, which is determined by our formula rate included in the wholesale power contract.  We sell excess energy and renewable energy credits to non-members at prevailing market prices as control is transferred.

We sell excess purchased and generated energy to PJM, TEC, or third parties.  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.  For the three months ended March 31, 2020 and 2019, we had no sales to TEC and TEC had no sales to third parties.    

Our operating revenues for the three months ended March 31, 2020 and 2019, were as follows:

 

Subsequent Event

On April 12, 2020, the governor of Virginia signed legislation that requires that all investor-owned utility generating facilities that emit CO₂ as a by-product of combustion close by December 31, 2045.  This includes the Clover generation facility, which we co-own with Virginia Power, an investor-owned utility.  However, if the reliability or security of providing electric service to customers is threatened, a petition may be made by Virginia Power to the Virginia State Corporation Commission requesting relief from the closure requirement.  Clover’s current depreciation rates are based on a useful life through 2050 and we are currently evaluating the impact of the change in Clover’s useful life.  We do not anticipate that this change will have a material impact on our financial statements.  For further discussion of Virginia CO₂ Regulation, see “Regulation—Virginia CO₂ Regulation” in Part 1, Item 1 Business of our 2019 Annual Report on Form 10-K. 

 

 

 

In June 2016, the FASB issued ASU 2016-13 Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses in Financial Instruments.  FASB issued subsequent amendments to the initial guidance in November 2018 with ASU No. 2018-19, in April 2019 with ASU No. 2019-04, and in May 2019 with ASU No. 2019-05. The ASU amends the guidance on the impairment of financial instruments and adds an impairment model, known as the current

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expected credit loss (“CECL”) model.  The CECL model requires an entity to recognize its current estimate of all expected credit losses, rather than incurred losses, and applies to trade receivables and other receivables.  The CECL model is designed to capture expected credit losses through the establishment of an allowance account, which will be presented as an offset to the amortized cost basis of the related financial asset.  The new guidance is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, and is applied using the modified-retrospective approach.  We adopted this standard for the fiscal year beginning January 1, 2020, and it did not have a material impact on our financial statements.

 

In March 2020, the FASB issued ASU 2020-04 Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting.  The guidance provides temporary optional expedients and exceptions related to contract modifications and hedge accounting to ease entities’ financial reporting burdens as the market transitions from the London Interbank Offered Rate and other interbank offered rates to alternative reference rates.  The new guidance allows entities to elect not to apply certain modification accounting requirements, if certain criteria are met, to contracts affected by what the guidance calls reference rate reform.  An entity that makes this election would consider changes in reference rates and other contract modifications related to reference rate reform to be events that do not require contract remeasurement at the modification date or reassessment of a previous accounting determination.  The ASU notes that changes in contract terms that are made to effect the reference rate reform transition are considered related to the replacement of a reference rate if they are not the result of a business decision that is separate from or in addition to changes to the terms of a contract to effect that transition. The guidance is effective upon issuance and generally can be applied as of March 12, 2020 through December 31, 2022.  We are currently evaluating the impact of this standard on our financial statements.

 

 

 

 

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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.  The impact that the COVID-19 pandemic will have on our consolidated results of operations, financial condition, and cash flows is uncertain.  We continue to actively manage our business to respond to this health crisis and will continue to evaluate the nature and extent of any impact.

Critical Accounting Policies

As of March 31, 2020, there have been no significant changes in our critical accounting policies as disclosed in our 2019 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 from operations for the three months ended March 31, 2020, were primarily impacted by the decrease in our total energy rate, PJM’s economic dispatch of our generating facilities, and milder weather.  

 

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Our results for the three months ended March 31, 2020, were not materially impacted by the outbreak in the United States of the COVID-19 pandemic.  We increased our cash balance as of March 31, 2020, by borrowing funds under our revolving credit facility due to uncertainties associated with the COVID-19 pandemic.  Our cash balance also increased as a result of our member distribution cooperatives increased prepayments related to their wholesale power invoices from us.   We continue to closely monitor how the outbreak will affect our operations, results of operations, financial condition, and cash flows.  

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 natural gas, nuclear, and coal 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 (collectively referred to as the total energy 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.  We can revise the energy adjustment rate during the year if it becomes apparent that the total energy rate is over-collecting or under-collecting our actual and anticipated energy costs.  Any revision to the energy adjustment rate requires board approval and that the resulting change to the total energy rate is at least 2%.  

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Demand costs, which are primarily fixed costs, such as capacity costs under power purchase contracts with third parties, transmission expense, administrative and general expense, depreciation expense, interest expense, margin requirement, 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 nuclear decommissioning expense, 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:

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.  The formula rate permits us to adjust revenues from the member distribution cooperatives to equal our actual total 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.  We make these adjustments utilizing Margin Stabilization.  

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.  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.

As detailed in the table below, we utilized Margin Stabilization to reduce revenues for the three months ended March 31, 2020 and 2019.

 

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 2019 Annual Report on Form 10-K.  

COVID-19 Pandemic

Our operating revenues are derived from sales of power and renewable energy credits to our member distribution cooperatives and non-members.  We supply power requirements (energy and demand) to our eleven member distribution cooperatives subject to substantially identical wholesale power contracts with each of them.  We sell excess energy and renewable energy credits to non-members at prevailing market prices as control is transferred.

Any decline in our member distribution cooperatives’ power requirements related to the COVID-19 pandemic would result in excess energy which we would sell to PJM, TEC, or third parties; or would result in a reduction of our spot market energy purchases.   

The formula rate provides for the recovery of costs, margin requirement, and any additional equity contributions approved by our board of directors, from our member distribution cooperatives (see “—Formula Rate” above).  We

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operate on a cost plus specified margin basis; therefore, our net margin is not a function of total revenues.  Our margin requirement is equal to 20% of actual interest charges, plus additional equity contributions approved by our board of directors.  We bill our member distribution cooperatives monthly, and each member distribution cooperative is required to pay us monthly for power furnished under its wholesale power contract.  Our member distribution cooperatives’ ability to pay their invoices to us may be impacted by certain factors including high unemployment rates, government actions protecting customers from the disconnection of utilities, and increased commercial or industrial closures/bankruptcies.  Our member distribution cooperatives have the option to prepay their invoices to us or to extend payment of their invoices for 60 days.  As of March 31, 2020, prepayments totaled $81.6 million and extensions totaled $6.4 million.  

For the three months ended March 31, 2020, we did not see a material impact attributable to the COVID-19 pandemic; however, we are continuing to evaluate ways in which the pandemic could affect our operations, financial condition, results of operations, and cash flows.  The extent to which the COVID-19 pandemic will impact us is uncertain and will depend on numerous evolving factors that we may not be able to accurately predict, including the duration and scope of the pandemic and the actions taken in response.  For other risks associated with the COVID-19 pandemic, see “Part II Other Information—Item 1A. Risk Factors.”

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 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.  Heating degree days are calculated as the number of degrees below 60 degrees in a single day.  Cooling degree days are calculated as the number of degrees above 65 degrees in a single day.  In a single calendar day, it is possible to have multiple heating degree and cooling degree days.  

The heating and cooling degree days for the three months ended March 31, 2020, were as follows:

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Power Supply Resources

We provide power to our members through a combination of our interests in Wildcat Point, a natural gas-fired combined cycle generation facility; North Anna, a nuclear power station; Clover, a coal-fired generation facility; two natural gas-fired combustion turbine facilities (Louisa and Marsh Run); 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, 2020 and 2019, 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.  For further discussion of PJM, see “Business—Power Supply Resources—PJM” in Item 1 of our 2019 Annual Report on Form 10-K.  

Operational Availability

The operational availability of our owned generating resources for the three months ended March 31, 2020 and 2019, was as follows:

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Capacity Factor

The output of Wildcat Point, North Anna, and Clover for the three months ended March 31, 2020 and 2019, as a percentage of maximum dependable capacity rating of the facilities, was as follows:

 

Sale of Rock Springs Combustion Turbine Facility

On September 14, 2018, we sold our interest in Rock Springs and related assets to EPRS for $115 million.  Prior to the sale, we and EPRS had each individually owned two natural gas-fired combustion turbine units and a 50% undivided interest in related common facilities at Rock Springs.  The transaction resulted in a gain of $42.7 million, which our board of directors approved to defer as a regulatory liability.  We amortized $5.0 million of the gain in 2018 and the remaining $37.7 million was amortized ratably in 2019.

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.  See “Factors Affecting Results—Formula Rate” above.

Sales to Non-members

Revenues from 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.  

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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 and energy sales in MWh by type of purchaser for the three months ended March 31, 2020 and 2019, were as follows:

 

 

Member Distribution Cooperatives

For the three months ended March 31, 2020, total revenues from sales to our member distribution cooperatives were 12.9% lower, as compared to the same period in 2019, primarily due to the decrease in energy revenues.  Energy revenues decreased $31.3 million, or 24.0%, due to the 16.2% decrease in the average cost of energy and the 9.3% decrease in energy sales in MWh to our member distribution cooperatives.  

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:

 

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Operating Expenses

The following is a summary of the components of our operating expenses for the three months ended March 31, 2020 and 2019:

 

 

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 fuel expense, the energy portion of our purchased power expense, and the variable portion of operations and maintenance expense.  Our demand costs generally are fixed and include the capacity portion of our purchased power expense, transmission 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 investment income and interest charges, net, are components of our demand costs.  See “Factors Affecting Results—Formula Rate” above.

Total operating expenses decreased $32.4 million, or 14.6%, for the three months ended March 31, 2020, as compared to the same period in 2019, primarily as a result of decreases in fuel expense, deferred energy expense, and transmission expense, partially offset by increases in amortization of regulatory asset/(liability), net and purchased power expense.  

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Other Items

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, 2020 and 2019, were as follows:

 

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, 2020, as compared to the same period in 2019.

Financial Condition

The principal changes in our financial condition from December 31, 2019 to March 31, 2020, were caused by increases in revolving credit facility, accounts payable–members, and deferred energy, and decreases in accounts payable, accounts receivable–members, regulatory liabilities, and nuclear decommissioning trust.

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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

During the first three months of 2020 and 2019, our operating activities provided cash flows of $92.8 million and $35.3 million, respectively.  Operating activities in 2020 were primarily impacted by the $53.3 million change in current liabilities, the $37.3 million change in current assets, and the $25.1 million change in deferred energy.

Revolving Credit Facility

We maintain a 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.  Commitments under this syndicated credit agreement extend through February 28, 2025.  Available funding under this facility totals $500 million through March 3, 2022, and $400 million from March 4, 2022 through February 28, 2025.  As of March 31, 2020, we had outstanding under this facility $250.0 million in borrowings and a $0.5 million letter of credit.  As of December 31, 2019, we had outstanding under this facility $67.2 million in borrowings and a $0.5 million letter of credit.  We increased our cash balance as of March 31, 2020, by borrowing funds under our revolving credit facility due to uncertainties associated with the COVID-19 pandemic.  

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.

Uses

Our uses of liquidity and capital relate to funding our working capital needs, investment activities, and financing activities.  Substantially all our investment activities relate to capital expenditures in connection with our generating facilities.  We expect that cash flows 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.

ITEM 3.  QUANTITATIVE AND QUALITATIVE

DISCLOSURES ABOUT MARKET RISK

No material changes occurred in our exposure to market risk during the first quarter of 2020.

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

Recovery of Costs from PJM

In 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 facilities. In 2015, FERC denied our petition, we filed a request for rehearing, and FERC issued an order granting rehearing for the limited purpose of FERC's further consideration of the matter.  In 2016, FERC denied our request for rehearing and, on June 15, 2018, the United States Court of Appeals for the District of Columbia Circuit denied our Petition for Review.  PJM removed the matter to United States District Court for the Eastern District of Virginia in July of 2019 and filed a motion to dismiss.  In 2019, we filed a motion to remand the matter to state court.  On March 31, 2020, the United States District Court for the Eastern District of Virginia granted PJM’s motion to dismiss and denied our motion to remand.  We are evaluating our options to appeal to the United States Court of Appeals for the Fourth Circuit on jurisdictional grounds.  We continue to pursue recovery as a separate breach of an oral contract claim in the Circuit Court for the County of Henrico in the Commonwealth of Virginia.  We have not recorded a receivable related to this matter.

Other Matters

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 1A.  RISK FACTORS

Our business and operations, and the operations of our member distribution cooperatives and suppliers, have been and will be impacted by the COVID-19 pandemic and could be similarly impacted by like events in the future.

The recent outbreak of COVID-19 has been declared by the World Health Organization to be a pandemic and has spread across the world, including the United States.  Because the severity, magnitude and duration of the COVID-19 pandemic and its economic consequences are uncertain, rapidly changing and difficult to predict, the impact on our operations and financial performance cannot be determined at this time.  We expect that the longer the period of economic and global supply chain disruptions continue, the greater the risk that there could be a material adverse impact on our operations, financial condition, results of operations, and cash flows.

ODEC is considered an essential service provider and due to this pandemic we have adjusted the schedules of our workforce at our owned generating facilities that we operate, specifically Wildcat Point, Louisa, and Marsh Run.  We have also developed a contingency plan for staffing at these facilities.  We have ownership interests in North Anna and Clover that are operated by Virginia Power, which has taken similar measures.  Beginning in mid-March 2020, our headquarters personnel began telecommuting with no disruption in business operations and will continue telecommuting for a period of time in the future.

Economic conditions, including a significant increase in unemployment and state government orders prohibiting disconnection of utilities during a state of emergency, as a result of the COVID-19 pandemic may make it difficult for some customers of our member distribution cooperatives to pay their power bills.  These economic conditions could ultimately affect the timeliness of our member distribution cooperatives’ cash flows and potentially the timing of their payments to us.  Our member distribution cooperatives’ ability to collect their costs from their members may have an impact on our financial condition and cash flows.  

As the impact of the COVID-19 pandemic on our operations and the economy evolves, we will continue to assess our liquidity needs.  A continued worldwide disruption in the availability of credit could materially affect future access to our sources of liquidity.  Adverse changes in our credit ratings may require us to provide credit support for some of our obligations and could negatively impact our liquidity and our ability to access capital. Conditions in the financial and

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credit markets also may limit the availability of funding or increase the cost of funding, which could adversely affect our operations, financial condition, results of operations, and cash flows.  

Sustained deterioration in the financial markets could adversely affect the value of our nuclear decommissioning trust and the NRECA Retirement Security Plan, a noncontributory, defined benefit pension plan qualified under Section 401, in which our employees participate.  The decline in the value of these funds could ultimately necessitate significant additional contributions by us.

In addition to the risk factor above and other information set forth in this report, you should carefully consider the factors discussed in “Risk Factors” in Part I, Item 1A of our 2019 Annual Report on Form 10-K, which could affect our business, financial condition, results of operations, and cash flows.  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, results of operations, and cash flows.  

ITEM 5.  OTHER INFORMATION

On May 11, 2020, our board of directors elected Mr. Gregory S. Rogers as a member of the board of directors and he will serve on the Bylaws and Policy Committee and the Power Supply and Resources Committee.  Mr. Rogers was recommended to the Nominating Committee by Shenandoah Valley Electric Cooperative to replace Mr. Michael W. Hastings, who resigned from our board of directors April 8, 2020.

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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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