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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

(Mark One)

 

 

 

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

For the quarterly period ended September 30, 2018

or

 

 

 

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

 

For the transition period from                      to                     

 

Commission file number 000-50039

 

OLD DOMINION ELECTRIC COOPERATIVE

(Exact name of registrant as specified in its charter)

 

 

 

VIRGINIA

 

23-7048405

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S.  employer

identification no.)

 

4201 Dominion Boulevard, Glen Allen, Virginia

 

23060

(Address of principal executive offices)

 

(Zip code)

 

(804) 747-0592

(Registrant’s telephone number, including area code)

 

 

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.

 

Larger accelerated filer

 

  

Accelerated filer

 

 

 

 

 

 

 

 

Non-accelerated filer

 

  

Smaller reporting company

 

 

 

 

 

 

 

 

Emerging growth company

 

 

 

 

 

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.

 

 


GLOSSARY OF TERMS

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

 

Abbreviation or Acronym

 

Definition

 

 

 

ACES

 

Alliance for Cooperative Energy Services Power Marketing, LLC

 

 

 

Alstom

 

Alstom Power, Inc.

 

 

 

Bear Island

 

Bear Island Paper WB LLC

 

 

 

Clover

 

Clover Power Station

 

 

 

CO2

 

Carbon dioxide

 

 

 

EPRS

 

Essential Power Rock Springs, LLC

 

 

 

EPC

 

Engineering, procurement, and construction

 

 

 

FASB

 

Financial Accounting Standards Board

 

 

 

FERC

 

Federal Energy Regulatory Commission

 

 

 

GAAP

 

Accounting principles generally accepted in the United States

 

 

 

Mitsubishi

 

Mitsubishi Hitachi Power Systems Americas, Inc.

 

 

 

MW

 

Megawatt(s)

 

 

 

MWh

 

Megawatt hour(s)

 

 

 

North Anna

 

North Anna Nuclear Power Station

 

 

 

North Anna Unit 3

 

A potential additional nuclear-powered generating unit at North Anna

 

 

 

ODEC, We, Our, Us

 

Old Dominion Electric Cooperative

 

 

 

PJM

 

PJM Interconnection, LLC

 

 

 

REC

 

Rappahannock Electric Cooperative

 

 

 

RTO

 

Regional transmission organization

 

 

 

TEC

 

TEC Trading, Inc.

 

 

 

Virginia Power

 

Virginia Electric and Power Company

 

 

 

Wildcat Point

 

Wildcat Point Generation Facility

 

 

 

WOPC

 

White Oak Power Constructors

 

 

 

XBRL

 

Extensible Business Reporting Language

 

 

2


OLD DOMINION ELECTRIC COOPERATIVE

INDEX

 

 

 

Page

Number

 

 

 

PART I.  Financial Information

 

 

 

 

 

Item 1.  Financial Statements

 

 

 

 

 

Condensed Consolidated Balance Sheets – September 30, 2018 (unaudited) and December 31, 2017

 

4

 

 

 

Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital (unaudited) – Three and Nine Months Ended September 30, 2018 and 2017

 

5

 

 

 

Condensed Consolidated Statements of Cash Flows (unaudited) – Nine Months Ended September 30, 2018 and 2017

 

6

 

 

 

Notes to Condensed Consolidated Financial Statements

 

7

 

 

 

Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

16

 

 

 

Item 3.  Quantitative and Qualitative Disclosures About Market Risk

 

28

 

 

 

Item 4.  Controls and Procedures

 

28

 

 

 

PART II.  Other Information

 

29

 

 

 

Item 1.  Legal Proceedings

 

29

 

 

 

Item 1A.  Risk Factors

 

30

 

Item 5.  Other Information

 

30

 

 

 

Item 6.  Exhibits

 

31

 

3


OLD DOMINION ELECTRIC COOPERATIVE

PART 1.  FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

September 30,

2018

 

 

December 31,

2017

 

 

 

(in thousands)

 

 

 

(unaudited)

 

 

 

 

 

ASSETS:

 

 

 

 

 

 

 

 

Electric Plant:

 

 

 

 

 

 

 

 

Property, plant, and equipment

 

$

2,447,398

 

 

$

1,754,236

 

Less accumulated depreciation

 

 

(853,599

)

 

 

(891,701

)

Net Property, plant, and equipment

 

 

1,593,799

 

 

 

862,535

 

Nuclear fuel, at amortized cost

 

 

17,911

 

 

 

18,089

 

Construction work in progress

 

 

33,888

 

 

 

822,667

 

Net Electric Plant

 

 

1,645,598

 

 

 

1,703,291

 

Investments:

 

 

 

 

 

 

 

 

Nuclear decommissioning trust

 

 

191,223

 

 

 

183,681

 

Lease deposits

 

 

32,653

 

 

 

106,812

 

Unrestricted investments and other

 

 

7,179

 

 

 

7,009

 

Total Investments

 

 

231,055

 

 

 

297,502

 

Current Assets:

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

 

71,447

 

 

 

4,084

 

Restricted cash and cash equivalents

 

 

14,200

 

 

 

 

Accounts receivable

 

 

11,660

 

 

 

10,379

 

Accounts receivable–members

 

 

84,180

 

 

 

83,133

 

Fuel, materials, and supplies

 

 

45,423

 

 

 

52,766

 

Deferred energy

 

 

21,755

 

 

 

3,669

 

Prepayments and other

 

 

4,835

 

 

 

5,274

 

Total Current Assets

 

 

253,500

 

 

 

159,305

 

Deferred Charges:

 

 

 

 

 

 

 

 

Regulatory assets

 

 

39,331

 

 

 

45,284

 

Other

 

 

4,279

 

 

 

3,780

 

Total Deferred Charges

 

 

43,610

 

 

 

49,064

 

Total Assets

 

$

2,173,763

 

 

$

2,209,162

 

CAPITALIZATION AND LIABILITIES:

 

 

 

 

 

 

 

 

Capitalization:

 

 

 

 

 

 

 

 

Patronage capital

 

$

425,362

 

 

$

415,384

 

Non-controlling interest

 

 

5,756

 

 

 

5,744

 

Total Patronage capital and Non-controlling interest

 

 

431,118

 

 

 

421,128

 

Long-term debt

 

 

1,198,799

 

 

 

1,198,396

 

Revolving credit facility

 

 

 

 

 

43,400

 

Total Long-term debt and Revolving credit facility

 

 

1,198,799

 

 

 

1,241,796

 

Total Capitalization

 

 

1,629,917

 

 

 

1,662,924

 

Current Liabilities:

 

 

 

 

 

 

 

 

Long-term debt due within one year

 

 

40,792

 

 

 

40,792

 

Accounts payable

 

 

111,828

 

 

 

92,259

 

Accounts payable–members

 

 

52,175

 

 

 

59,064

 

Accrued expenses

 

 

25,092

 

 

 

6,391

 

Regulatory liability–revenue deferral

 

 

3,750

 

 

 

15,000

 

Obligations under long-term lease

 

 

32,200

 

 

 

103,683

 

Total Current Liabilities

 

 

265,837

 

 

 

317,189

 

Deferred Credits and Other Liabilities:

 

 

 

 

 

 

 

 

Asset retirement obligations

 

 

129,162

 

 

 

126,470

 

Regulatory liabilities

 

 

148,414

 

 

 

101,237

 

Other

 

 

433

 

 

 

1,342

 

Total Deferred Credits and Other Liabilities

 

 

278,009

 

 

 

229,049

 

Commitments and Contingencies

 

 

 

 

 

 

Total Capitalization and Liabilities

 

$

2,173,763

 

 

$

2,209,162

 

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

4


OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS OF REVENUES,

EXPENSES, AND PATRONAGE CAPITAL (UNAUDITED)

 

 

 

Three Months Ended

September 30,

 

 

Nine Months Ended

September 30,

 

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

 

(in thousands)

 

Operating Revenues

 

$

257,586

 

 

$

193,425

 

 

$

712,247

 

 

$

540,111

 

Operating Expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fuel

 

 

65,134

 

 

 

32,309

 

 

 

147,573

 

 

 

70,490

 

Purchased power

 

 

71,059

 

 

 

90,185

 

 

 

299,645

 

 

 

293,030

 

Transmission

 

 

39,916

 

 

 

24,280

 

 

 

105,145

 

 

 

72,001

 

Deferred energy

 

 

17,482

 

 

 

(2,408

)

 

 

(18,086

)

 

 

(28,651

)

Operations and maintenance

 

 

15,236

 

 

 

12,753

 

 

 

48,236

 

 

 

37,325

 

Administrative and general

 

 

11,593

 

 

 

10,769

 

 

 

34,848

 

 

 

33,208

 

Depreciation and amortization

 

 

17,057

 

 

 

11,357

 

 

 

45,818

 

 

 

34,040

 

Amortization of regulatory asset/liability, net

 

 

(2,816

)

 

 

1,021

 

 

 

(7,457

)

 

 

1,001

 

Accretion of asset retirement obligations

 

 

1,330

 

 

 

1,257

 

 

 

3,991

 

 

 

3,769

 

Taxes, other than income taxes

 

 

2,597

 

 

 

2,089

 

 

 

7,315

 

 

 

6,280

 

Total Operating Expenses

 

 

238,588

 

 

 

183,612

 

 

 

667,028

 

 

 

522,493

 

Operating Margin

 

 

18,998

 

 

 

9,813

 

 

 

45,219

 

 

 

17,618

 

Other expense, net

 

 

(689

)

 

 

(934

)

 

 

(2,962

)

 

 

(2,838

)

Investment income

 

 

1,949

 

 

 

1,731

 

 

 

6,470

 

 

 

10,000

 

Interest income on North Anna Unit 3 cost recovery

 

 

 

 

 

85

 

 

 

141

 

 

 

4,512

 

Interest charges, net

 

 

(16,862

)

 

 

(7,434

)

 

 

(38,874

)

 

 

(20,005

)

Income taxes

 

 

 

 

 

(1

)

 

 

(4

)

 

 

(3

)

Net Margin including Non-controlling interest

 

 

3,396

 

 

 

3,260

 

 

 

9,990

 

 

 

9,284

 

Non-controlling interest

 

 

 

 

 

(2

)

 

 

(12

)

 

 

(11

)

Net Margin attributable to ODEC

 

 

3,396

 

 

 

3,258

 

 

 

9,978

 

 

 

9,273

 

Patronage Capital - Beginning of Period

 

 

421,966

 

 

 

408,872

 

 

 

415,384

 

 

 

402,857

 

Patronage Capital - End of Period

 

$

425,362

 

 

$

412,130

 

 

$

425,362

 

 

$

412,130

 

 

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

5


OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

 

 

 

Nine Months Ended September 30,

 

 

 

2018

 

 

2017

 

 

 

(in thousands)

 

Operating Activities:

 

 

 

 

 

 

 

 

Net Margin including Non-controlling interest

 

$

9,990

 

 

$

9,284

 

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

 

 

 

 

 

 

 

 

Depreciation and amortization

 

 

45,818

 

 

 

34,040

 

Other non-cash charges

 

 

13,820

 

 

 

14,153

 

Amortization of lease obligations

 

 

4,468

 

 

 

5,064

 

Interest on lease deposits

 

 

(1,671

)

 

 

(2,274

)

Change in current assets

 

 

4,613

 

 

 

10,752

 

Change in deferred energy

 

 

(18,086

)

 

 

(28,651

)

Change in current liabilities

 

 

10,638

 

 

 

23,457

 

Change in regulatory assets and liabilities

 

 

(2,364

)

 

 

4,973

 

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

 

 

(2,285

)

 

 

262

 

Net Cash Provided by Operating Activities

 

 

64,941

 

 

 

71,060

 

Investing Activities:

 

 

 

 

 

 

 

 

Purchases of held to maturity securities

 

 

(362

)

 

 

(2,763

)

Proceeds from sale of held to maturity securities

 

 

76,137

 

 

 

3,064

 

Increase in other investments

 

 

(6,116

)

 

 

(9,822

)

Electric plant additions

 

 

(48,431

)

 

 

(120,939

)

Proceeds from sale of asset

 

 

115,000

 

 

 

 

Net Cash Provided by/(Used for) Investing Activities

 

 

136,228

 

 

 

(130,460

)

Financing Activities:

 

 

 

 

 

 

 

 

Issuance of long-term debt

 

 

 

 

 

250,000

 

Debt issuance costs

 

 

(255

)

 

 

(1,386

)

Payment of obligation under long-term lease

 

 

(75,951

)

 

 

 

Draws on revolving credit facility

 

 

372,950

 

 

 

312,500

 

Repayments on revolving credit facility

 

 

(416,350

)

 

 

(464,500

)

Net Cash (Used for)/Provided by Financing Activities

 

 

(119,606

)

 

 

96,614

 

Net Change in Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

 

 

81,563

 

 

 

37,214

 

Cash and Cash Equivalents and Restricted Cash and Cash Equivalents - Beginning of Period

 

 

4,084

 

 

 

2,946

 

Cash and Cash Equivalents and Restricted Cash and Cash Equivalents - End of Period

 

$

85,647

 

 

$

40,160

 

 

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

 

 

6


OLD DOMINION ELECTRIC COOPERATIVE

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

 

 

 

1.

General

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 September 30, 2018, our consolidated results of operations for the three and nine months ended September 30, 2018 and 2017, and cash flows for the nine months ended September 30, 2018 and 2017.  The consolidated results of operations for the three and nine months ended September 30, 2018, 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 2017 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 $5.8 million as of September 30, 2018, and $5.7 million as of December 31, 2017.  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 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.

 

 

 

2.

Fair Value Measurements

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

7


The following table summarizes our financial assets and liabilities measured at fair value on a recurring basis as of September 30, 2018 and December 31, 2017: 

 

 

 

 

 

 

Quoted Prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

in Active

 

 

Significant

 

 

 

 

 

 

 

 

 

 

Markets for

 

 

Other

 

 

Significant

 

 

 

 

 

 

Identical

 

 

Observable

 

 

Unobservable

 

 

September 30,

 

 

Assets

 

 

Inputs

 

 

Inputs

 

 

2018

 

 

(Level 1)

 

 

(Level 2)

 

 

(Level 3)

 

 

(in thousands)

 

Nuclear decommissioning trust (1)

$

58,725

 

 

$

58,725

 

 

$

 

 

$

 

Nuclear decommissioning trust - net asset value (1)(2)

 

132,498

 

 

 

 

 

 

 

 

 

 

Unrestricted investments and other (3)

 

423

 

 

 

 

 

 

423

 

 

 

 

Derivatives - gas and power (4)

 

986

 

 

 

168

 

 

 

818

 

 

 

 

Total Financial Assets

$

192,632

 

 

$

58,893

 

 

$

1,241

 

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Quoted Prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

in Active

 

 

Significant

 

 

 

 

 

 

 

 

 

 

Markets for

 

 

Other

 

 

Significant

 

 

 

 

 

 

Identical

 

 

Observable

 

 

Unobservable

 

 

December 31,

 

 

Assets

 

 

Inputs

 

 

Inputs

 

 

2017

 

 

(Level 1)

 

 

(Level 2)

 

 

(Level 3)

 

 

(in thousands)

 

Nuclear decommissioning trust (1)

$

59,723

 

 

$

59,723

 

 

$

 

 

$

 

Nuclear decommissioning trust - net asset value (1)(2)

 

123,958

 

 

 

 

 

 

 

 

 

 

Unrestricted investments and other (3)

 

308

 

 

 

 

 

 

308

 

 

 

 

Total Financial Assets

$

183,989

 

 

$

59,723

 

 

$

308

 

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivatives - gas and power (4)

$

1,034

 

 

$

975

 

 

$

59

 

 

$

 

Total Financial Liabilities

$

1,034

 

 

$

975

 

 

$

59

 

 

$

 

 

 

(1)

For additional information about our nuclear decommissioning trust see Note 4—Investments below.

 

(2)

Nuclear decommissioning trust includes investments measured at net asset value per share (or its equivalent) as a practical expedient and these investments have not been categorized in the fair value hierarchy.  The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the Condensed Consolidated Balance Sheet.

 

(3)

Unrestricted investments and other includes investments that are related to equity securities.

 

(4)

Derivatives - gas and power represent natural gas futures contracts.  Level 1 are indexed against NYMEX.  Level 2 are valued by ACES using observable market inputs for similar transactions.  For additional information about our derivative financial instruments, see Note 1 of the Notes to Consolidated Financial Statements in our 2017 Annual Report on Form 10-K.

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.

 

 

 

 

3.

Derivatives and Hedging

We are exposed to market price risk by purchasing power to supply the power requirements of our member distribution cooperatives that are not met by our owned generation.  In addition, the purchase of fuel to operate our generating facilities also exposes us to market price risk.  To manage this exposure, we utilize derivative instruments.  See Note 1 of the Notes to Consolidated Financial Statements in our 2017 Annual Report on Form 10-K.

8


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:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Quantity

 

 

 

 

 

As of

September 30,

 

 

As of

December 31,

 

Commodity

 

Unit of Measure

 

2018

 

 

2017

 

Natural gas

 

MMBTU

 

 

33,500,000

 

 

 

23,700,000

 

 

 

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

 

 

 

 

 

Fair Value

 

 

 

 

 

As of

September 30,

 

 

As of

December 31,

 

 

 

Balance Sheet Location

 

2018

 

 

2017

 

 

 

 

 

(in thousands)

 

Derivatives in an asset position:

 

 

 

 

 

 

 

 

 

 

Natural gas futures contracts

 

Deferred charges-other

 

$

986

 

 

$

 

Total derivatives in an asset position

 

 

 

$

986

 

 

$

 

 

 

 

 

 

 

 

 

 

 

 

Derivatives in a liability position:

 

 

 

 

 

 

 

 

 

 

Natural gas futures contracts

 

Deferred credits and other liabilities-other

 

$

 

 

$

1,034

 

Total derivatives in a liability position

 

 

 

$

 

 

$

1,034

 

 

The Effect of Derivative Instruments on the Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital for the Three and Nine Months Ended September 30, 2018 and 2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Amount of Gain

 

 

Amount of Gain

 

 

 

Amount of Gain

 

 

Location of

 

(Loss) Reclassified

 

 

(Loss) Reclassified

 

 

 

(Loss) Recognized

 

 

Gain (Loss)

 

from Regulatory

 

 

from Regulatory

 

 

 

in Regulatory

 

 

Reclassified

 

Asset/Liability

 

 

Asset/Liability

 

Derivatives

 

Asset/Liability for

 

 

from Regulatory

 

into Income for

 

 

into Income for

 

Accounted for Utilizing

 

Derivatives as of

 

 

Asset/Liability

 

the Three Months

 

 

the Nine Months

 

Regulatory Accounting

 

September 30,

 

 

into Income

 

Ended September 30,

 

 

Ended September 30,

 

 

 

2018

 

 

2017

 

 

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

 

(in thousands)

 

 

 

 

(in thousands)

 

Natural gas futures contracts

 

$

1,032

 

 

$

1,123

 

 

Fuel

 

$

980

 

 

$

(129

)

 

$

(130

)

 

$

870

 

Total

 

$

1,032

 

 

$

1,123

 

 

 

 

$

980

 

 

$

(129

)

 

$

(130

)

 

$

870

 

 

9


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.

 

 

 

10


4.

Investments

Investments were as follows as of September 30, 2018 and December 31, 2017:

 

 

 

 

 

 

 

Gross

 

 

Gross

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Unrealized

 

 

Unrealized

 

 

Fair

 

 

Carrying

 

Description

 

Cost

 

 

Gains

 

 

Losses

 

 

Value

 

 

Value

 

 

 

(in thousands)

 

September 30, 2018

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Nuclear decommissioning trust (1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Debt securities

 

$

55,607

 

 

$

2,950

 

 

$

 

 

$

58,557

 

 

$

58,557

 

Equity securities

 

 

82,778

 

 

 

51,058

 

 

 

(1,338

)

 

 

132,498

 

 

 

132,498

 

Cash and other

 

 

168

 

 

 

 

 

 

 

 

 

168

 

 

 

168

 

Total Nuclear Decommissioning Trust

 

$

138,553

 

 

$

54,008

 

 

$

(1,338

)

 

$

191,223

 

 

$

191,223

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease Deposits (2)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Government obligations

 

$

32,653

 

 

$

37

 

 

$

 

 

$

32,690

 

 

$

32,653

 

Total Lease Deposits

 

$

32,653

 

 

$

37

 

 

$

 

 

$

32,690

 

 

$

32,653

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Unrestricted investments

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Government obligations

 

$

2,350

 

 

$

 

 

$

(3

)

 

$

2,347

 

 

$

2,350

 

Debt securities

 

 

2,272

 

 

 

 

 

 

(2

)

 

 

2,270

 

 

 

2,272

 

Total Unrestricted Investments

 

$

4,622

 

 

$

 

 

$

(5

)

 

$

4,617

 

 

$

4,622

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity securities

 

$

318

 

 

$

105

 

 

$

 

 

$

423

 

 

$

423

 

Non-marketable equity investments

 

 

2,134

 

 

 

2,156

 

 

 

 

 

 

4,290

 

 

 

2,134

 

Total Other

 

$

2,452

 

 

$

2,261

 

 

$

 

 

$

4,713

 

 

$

2,557

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$

231,055

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Nuclear decommissioning trust (1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Debt securities

 

$

54,375

 

 

$

5,029

 

 

$

 

 

$

59,404

 

 

$

59,404

 

Equity securities

 

 

77,838

 

 

 

46,474

 

 

 

(354

)

 

 

123,958

 

 

 

123,958

 

Cash and other

 

 

319

 

 

 

 

 

 

 

 

 

319

 

 

 

319

 

Total Nuclear Decommissioning Trust

 

$

132,532

 

 

$

51,503

 

 

$

(354

)

 

$

183,681

 

 

$

183,681

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease Deposits (2)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Government obligations

 

$

106,812

 

 

$

776

 

 

$

 

 

$

107,588

 

 

$

106,812

 

Total Lease Deposits

 

$

106,812

 

 

$

776

 

 

$

 

 

$

107,588

 

 

$

106,812

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Unrestricted investments

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Government obligations

 

$

2,344

 

 

$

 

 

$

(13

)

 

$

2,331

 

 

$

2,344

 

Debt securities

 

 

2,217

 

 

 

 

 

 

(3

)

 

 

2,214

 

 

 

2,217

 

Total Unrestricted Investments

 

$

4,561

 

 

$

 

 

$

(16

)

 

$

4,545

 

 

$

4,561

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity securities

 

$

223

 

 

$

85

 

 

$

 

 

$

308

 

 

$

308

 

Non-marketable equity investments

 

 

2,140

 

 

 

2,066

 

 

 

 

 

 

4,206

 

 

 

2,140

 

Total Other

 

$

2,363

 

 

$

2,151

 

 

$

 

 

$

4,514

 

 

$

2,448

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$

297,502

 

 

 

(1)

Investments in the nuclear decommissioning trust are restricted for the use of funding our share of the asset retirement obligations of the future decommissioning of North Anna.  See Note 3 of the Notes to Consolidated Financial Statements in our 2017 Annual Report on Form 10-K.  Unrealized gains and losses on investments held in the nuclear decommissioning trust are deferred as a regulatory liability or regulatory asset, respectively.

 

(2)

Investments in lease deposits are restricted for the use of funding our future lease obligations.  See Note 8 of the Notes to Consolidated Financial Statements in our 2017 Annual Report on Form 10-K.

 

11


Contractual maturities of debt securities as of September 30, 2018, were as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Description

 

Less than

1 year

 

 

1-5 years

 

 

5-10 years

 

 

More than

10 years

 

 

Total

 

 

 

(in thousands)

 

Other (1)

 

$

 

 

$

 

 

$

58,557

 

 

$

 

 

$

58,557

 

Held to maturity

 

 

37,035

 

 

 

240

 

 

 

 

 

 

 

 

 

37,275

 

Total

 

$

37,035

 

 

$

240

 

 

$

58,557

 

 

$

 

 

$

95,832

 

 

 

 

(1)

The contractual maturities of other debt securities are measured using the effective duration of the bond fund within the nuclear decommissioning trust.

 

 

 

 

5.

Other

Wildcat Point Generation Facility 

On April 17, 2018, Wildcat Point, an approximate 1,000 MW natural gas-fueled combined cycle generation facility, achieved commercial operation and was available for dispatch by PJM.

The facility originally was scheduled to become operational in mid-2017.  WOPC, a joint venture between PCL Industrial Construction Company and Sargent & Lundy, L.L.C., as the EPC contractor, claims the delay was associated with the incurrence of additional work and other matters, including alleged misrepresentation in the EPC contract, for which it will seek recovery, in whole or in part, from its subcontractors and us.  On May 24, 2017, WOPC filed a complaint against Alstom and us, in the United States District Court for the District of Maryland.  An amended complaint was filed on July 21, 2017.  On August 21, 2017, motions were filed by Alstom and us to transfer venue from the United States District Court for the District of Maryland to the United States District Court for the Eastern District of Virginia, and on November 7, 2017, these motions were granted.  We have reviewed the asserted claims of WOPC against us and believe they are without merit.  We have not recorded any liability related to these claims as we do not believe any liability is estimable or probable.  We intend to vigorously defend against these claims.

Additionally, on September 29, 2017, we filed a complaint in the United States District Court for the Eastern District of Virginia against WOPC, alleging that WOPC breached the EPC contract.  On November 16, 2017, 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 on May 9, 2017, be consolidated into one case.  On June 27, 2018, an order was issued establishing January 9, 2019 as the date to check the status of discovery, set summary judgement deadlines, and set a trial date.

If it is ultimately determined that we owe any such amounts to WOPC, the amounts are not expected to have a material impact on our financial position or results of operations due to our ability to collect such amounts through rates to our member distribution cooperatives.

Through September 30, 2018, we capitalized construction costs related to Wildcat Point totaling $842.4 million, which includes $88.4 million of capitalized interest and is offset by $53.2 million of liquidated damages. 

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 we previously suggested and FERC directed in the January 19, 2017 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.  On March 22, 2018, FERC issued an order denying Bear Island's request for rehearing and accepted our February 21, 2017 compliance filing that revised the formula rate as directed by FERC's January 19, 2017 order.  We filed

12


a refund report with FERC on April 23, 2018, that calculated the difference between rates charged under our rate schedule since January 1, 2014, and rates that would have been charged under the revised rate schedule submitted in our February 21, 2017 compliance filing.  On July 24, 2018, FERC accepted the refund report, which resulted in a reallocation of costs among our member distribution cooperatives and did not result in any change to our total operating revenues.

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 March 3, 2023.  Available funding under this facility totals $500 million through March 3, 2022, and $400 million from March 4, 2022 through March 3, 2023.  As of September 30, 2018, we had no borrowings and $2.5 million in letters of credit outstanding under this facility.  As of December 31, 2017, we had $43.4 million in borrowings and $12.0 million in letters of credit outstanding under this facility.  

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, with 180 days prior written notice, to receive up to the greater of 5% of its demand and associated energy or 5 MW and associated energy from its owned generation or from 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 May 1, 2018, there are approximately 66 MW remaining that can be utilized under this exception.  The following table summarizes the cumulative removal of load requirements under this exception since January 1, 2016.  

Date

 

MW

 

January 1, 2016

 

 

9

 

May 1, 2016

 

 

60

 

June 1, 2017

 

 

65

 

May 1, 2018

 

 

109

 

We do not anticipate that either the current or potential full utilization of this exception by our member distribution cooperatives will have a material impact on our financial condition, results of operations, or cash flows.

Cash and 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 Sheet that sum to the total of the same amounts shown in the Condensed Consolidated Statement of Cash Flows:

 

 

As of September 30,

 

 

 

2018

 

 

2017

 

 

 

(in thousands)

 

Cash and cash equivalents

 

$

71,447

 

 

$

40,160

 

Restricted cash and cash equivalents

 

 

14,200

 

 

 

 

 

 

$

85,647

 

 

$

40,160

 

Restricted cash and cash equivalents relates to funds held in escrow for payments to Mitsubishi for Wildcat Point.

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 to be amortized over future periods.   

13


 

6.

New Accounting Pronouncements

In May 2014, the FASB issued Accounting Standards Update 2014-09 Revenue from Contracts with Customers (Topic 606).  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 supply power requirements (energy and demand) to our eleven member distribution cooperatives subject to substantially identical wholesale power contracts with each of them.  The revenues from these wholesale power contracts constituted at least 95% of our total revenues for the past three years.  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 also sell excess energy and renewable energy credits to non-members at prevailing market prices as control is transferred.  We have completed our contract review of our wholesale power and other contracts within the scope of Topic 606, and have finalized our analysis.  We have not identified any material impact to our recognition of revenue from the sale of power to our member distribution cooperatives or non-members.  We adopted this standard effective January 1, 2018, using the modified retrospective approach.  There was no material impact to our recognition of revenue from the sale of power to our member distribution cooperatives or non-members, and there has been no cumulative effect adjustment recognized.

Our operating revenues for the three and nine months ended September 30, 2018, were as follows:

 

 

 

Three Months

Ended

September 30,

 

 

Nine Months

Ended

September 30,

 

 

 

2018

 

 

2018

 

 

 

(in thousands)

 

Member distribution cooperatives

 

 

 

 

 

 

 

 

Sales to member distribution cooperatives, excluding renewable energy credit sales

 

$

230,408

 

 

$

657,521

 

Renewable energy credit sales to member distribution cooperatives

 

 

2

 

 

 

14

 

Total sales to member distribution cooperatives

 

$

230,410

 

 

$

657,535

 

 

 

 

 

 

 

 

 

 

Non-members

 

 

 

 

 

 

 

 

Sales to non-members, excluding renewable energy credit sales

 

$

24,791

 

 

$

51,762

 

Renewable energy credit sales to non-members

 

 

2,385

 

 

 

2,950

 

Total sales to non-members

 

$

27,176

 

 

$

54,712

 

 

 

 

 

 

 

 

 

 

Total operating revenues

 

$

257,586

 

 

$

712,247

 

In January 2016, the FASB issued Accounting Standards Update 2016-01 Recognition and Measurement of Financial Assets and Financial Liabilities. This update retained the current framework for accounting for financial instruments in GAAP but made targeted improvements to address certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. We adopted this update during 2018. The update requires us to measure equity investments at fair value and recognize any changes in fair value in net margin.  We account for certain revenues and expenses as a rate-regulated entity in accordance with Accounting for Regulated Operations.  With approval from our board of directors, changes in fair value of certain equity investments are recognized as a change in our regulatory liability account on our Condensed Consolidated Balance Sheet.  See Note 4—Investments above.

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,

14


timing, and uncertainty of cash flows arising from leasing arrangements.  In July 2018, the FASB issued Accounting Standards Update 2018-11 Leases (Topic 842): Targeted Improvements, which provides an adoption method that would allow companies to apply the new guidance to the financial statements in the period of adoption and thereafter, and not apply the new guidance to comparative periods presented.  We are in the process of finalizing our review of the impact of the new accounting guidance related to leases on our financial statements and related disclosure, as well as determining which practical expedients we plan to utilize.  We plan to adopt this standard for the fiscal year beginning January 1, 2019.

In November 2016, the FASB issued Accounting Standards Update 2016-18 Statement of Cash Flows (Topic 230): Restricted Cash.  This update revised accounting guidance for the classification and presentation of restricted cash in the statement of cash flows.  We adopted this update effective January 1, 2018, and it requires a reconciliation of cash and cash equivalents and restricted cash and cash equivalents within the Condensed Consolidated Balance Sheet and the amounts shown in the Condensed Consolidated Statement of Cash Flows.  See “Cash and Cash Equivalents” above.

 

 

15


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 September 30, 2018, there have been no significant changes in our critical accounting policies as disclosed in our 2017 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 and nine months ended September 30, 2018, were primarily impacted by the commercial operation of Wildcat Point, and weather that resulted in increases in our member distribution cooperatives’ requirements for power and the dispatch of our generating facilities.  Additionally, in 2018 we increased our total energy rate and completed the sale of our Rock Springs combustion turbine facility.  

 

 

Wildcat Point, which achieved commercial operation and was available for dispatch by PJM on April 17, 2018, generated over 1,331,000 MWh in the third quarter of 2018 and over 2,286,000 MWh for the nine months ended September 30, 2018, resulting in increased fuel expense.  Once commercial operation was achieved, we began recognizing expenses related to operations and maintenance, administrative and general, depreciation, and interest charges.  

 

16


 

Generation from our combustion turbine facilities increased 22.1% and 89.8%, respectively, for the three and nine months ended September 30, 2018, as compared to the same periods in 2017, due to PJM’s economic dispatch of these facilities, which resulted in increased fuel expense.

 

Due to the increased generation from our owned generating facilities, our non-member sales increased for the three and nine months ended September 30, 2018, as compared to the same periods in 2017, and our purchased power costs decreased for the three months ended September 30, 2018, as compared to the same period in 2017.

 

Our revenues from sales to our member distribution cooperatives increased 25.3% and 25.9 %, respectively, for the three and nine months ended September 30, 2018, as compared to the same periods in 2017.  Demand revenues increased 35.7% and 31.6%, respectively, primarily due to the increase in transmission expense and recognition of Wildcat Point-related expenses.  Energy revenues increased 18.1% and 21.8%, respectively, due to the increase in the average cost of energy sold to our member distribution cooperatives and an increase in energy sales in MWh to our member distribution cooperatives.  The average cost of energy sold to our member distribution cooperatives increased 15.3% and 13.7%, respectively, due to the total energy rate increases implemented in 2018.  Energy sales in MWh to our member distribution cooperatives increased 2.5% and 7.1%, respectively.  Absent the impact of the removal of load under the limited exception under wholesale power contracts as described below, beginning May 1, 2018, our energy sales in MWh would have increased 5.5% and 8.9%, respectively.  

 

As a result of higher costs, we under-collected energy costs by $52.3 million in the first quarter of 2018.  As of March 31, 2018, our deferred energy balance was $55.9 million under-collected.  To address the under-collection, we increased our total energy rate 3.7% effective April 1, 2018.  As of September 30, 2018, our deferred energy balance was $21.8 million under-collected.

 

On June 14, 2018, we entered into an asset purchase agreement for EPRS’ purchase of our interest in Rock Springs and related assets for $115 million, and this transaction closed on September 14, 2018.  We utilized a portion of the funds to repay outstanding borrowings under our revolving credit facility.  The sale of Rock Springs resulted in a gain of $42.7 million, which our board of directors approved to defer as a regulatory liability.  See “Factors Affecting Results—Generating Facilities—Sale of Rock Springs Combustion Turbine Facility.”

Wildcat Point Generation Facility

On April 17, 2018, Wildcat Point, an approximate 1,000 MW natural gas-fueled combined cycle generation facility, achieved commercial operation and was available for dispatch by PJM.

The facility originally was scheduled to become operational in mid-2017.  WOPC, the EPC contractor, claims the delay was associated with the incurrence of additional work and other matters, including alleged misrepresentation under the EPC contract, for which it will seek recovery, in whole or in part, from its subcontractors and us.  See “Wildcat Point” in “Legal Proceedings” in Part II, Item 1.  If it is ultimately determined that we owe any such amounts to WOPC, the amounts are not expected to have a material impact on our financial position or results of operations due to our ability to collect such amounts through rates to our member distribution cooperatives.

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, with 180 days prior written notice, to receive up to the greater of 5% of its demand and associated energy or 5 MW and associated energy from its owned generation or from 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 May 1, 2018, there are approximately 66 MW remaining that can be utilized under this exception.  The following table summarizes the cumulative removal of load requirements under this exception since January 1, 2016.  

17


Date

 

MW

 

January 1, 2016

 

 

9

 

May 1, 2016

 

 

60

 

June 1, 2017

 

 

65

 

May 1, 2018

 

 

109

 

We do not anticipate that either the current or potential full utilization of this exception by our member distribution cooperatives will have a material impact on our financial condition, results of operations, or cash flows.  For further discussion of Wholesale Power Contracts, see “Business—Members—Member Distribution Cooperatives—Wholesale Power Contracts” in Item 1 of our 2017 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.  On December 2, 2013, FERC accepted our formula rate effective January 1, 2014, subject to refund, and established hearing and settlement procedures.  On January 19, 2017, FERC directed us to submit a compliance filing making certain revisions to the formula rate.  These revisions to the formula rate did not change our overall revenue requirements.  On March 22, 2018, FERC accepted our compliance filing and required us to file a refund report to calculate the difference between rates charged under our rate schedule since January 1, 2014, and rates that would have been charged under the revised rate schedule submitted in our compliance filing.  On July 24, 2018, FERC accepted the refund report, which resulted in a reallocation of costs among our member distribution cooperatives and did not result in any change to our operating revenues.  See “FERC Proceeding Related to Formula Rate” in “Legal Proceedings” in Part II, Item 1.

Our formula rate is intended to permit collection of revenues which will equal the sum of:

 

 

all of our costs and expenses;

 

20% of our total interest charges; and

 

additional equity contributions approved by our board of directors.

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

Energy costs, which are primarily variable costs, such as nuclear, coal, and natural gas fuel costs, and the energy costs under our power purchase contracts with third parties, are recovered through two separate rates, the base energy rate and the energy adjustment rate (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%.  

18


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:

 

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

 

RTO capacity service rate – designed to collect capacity costs in PJM that PJM allocates to ODEC and all other PJM members; and

 

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

As stated above, our margin requirements, and additional equity contributions approved by our board of directors are recovered through our demand rates.  We establish our demand rates to produce a net margin attributable to ODEC equal to 20% of our budgeted total interest charges, plus additional equity contributions approved by our board of directors.  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.  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 increase revenues for the three months ended September 30, 2018, and to decrease revenues for the three months ended September 30, 2017 and the nine months ended September 30, 2018 and 2017.

 

 

Three Months

Ended

September 30,

 

 

Nine Months

Ended

September 30,

 

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

 

(in thousands)

 

Margin Stabilization adjustment

 

$

(3,130

)

 

$

12,871

 

 

$

11,941

 

 

$

49,892

 

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 2017 Annual Report on Form 10-K.  

On November 7, 2017, our board of directors approved an additional equity contribution of $14.1 million and declared a patronage capital retirement of $14.1 million, which was paid on April 2, 2018.

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.  The heating and cooling degree days for the three and nine months ended September 30, 2018, were as follows:

19


 

 

Three Months

Ended

September 30,

 

 

Nine Months

Ended

September 30,

 

 

 

2018

 

 

2017

 

 

Change

 

 

2018

 

 

2017

 

 

Change

 

Heating degree days

 

 

 

 

 

 

 

 

%

 

 

1,993

 

 

 

1,637

 

 

 

21.7

%

Cooling degree days

 

 

1,058

 

 

 

897

 

 

 

17.9

 

 

 

1,492

 

 

 

1,182

 

 

 

26.2

 

 

Power Supply Resources

We provide power to our members through a combination of our interests in Wildcat Point, a combined cycle generation facility; Clover, a coal-fired generation facility; North Anna, a nuclear power station; our three combustion turbine facilities – Louisa, Marsh Run, and prior to September 14, 2018, 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 and nine months ended September 30, 2018 and 2017, were as follows:

 

 

 

Three Months

Ended

September 30,

 

Nine Months

Ended

September 30,

 

 

 

2018

 

2017

 

2018

 

2017

 

 

 

(in MWh and percentages)

 

Generated:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Wildcat Point

 

1,331,437

 

36.1

%

 

%

2,286,185

 

21.9

%

 

%

Clover

 

482,001

 

13.1

 

543,468

 

17.0

 

1,244,644

 

11.9

 

1,302,298

 

14.6

 

North Anna

 

480,845

 

13.1

 

431,770

 

13.5

 

1,356,366

 

13.0

 

1,408,412

 

15.9

 

Louisa

 

202,072

 

5.5

 

79,779

 

2.5

 

449,539

 

4.3

 

169,908

 

1.9

 

Marsh Run

 

159,608

 

4.3

 

221,867

 

7.0

 

518,867

 

5.0

 

309,053

 

3.5

 

Rock Springs

 

125,414

 

3.4

 

97,285

 

3.1

 

212,957

 

2.0

 

143,571

 

1.6

 

Distributed Generation

 

802

 

 

350

 

 

1,410

 

 

538

 

 

Total Generated

 

2,782,179

 

75.5

 

1,374,519

 

43.1

 

6,069,968

 

58.1

 

3,333,780

 

37.5

 

Purchased:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other than renewable:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term and short-term

 

485,977

 

13.2

 

1,354,004

 

42.4

 

2,425,013

 

23.2

 

3,966,274

 

44.7

 

Spot market

 

286,016

 

7.7

 

357,639

 

11.2

 

1,381,633

 

13.3

 

1,043,338

 

11.7

 

Total Other than renewable

 

771,993

 

20.9

 

1,711,643

 

53.6

 

3,806,646

 

36.5

 

5,009,612

 

56.4

 

Renewable (1)

 

131,173

 

3.6

 

105,533

 

3.3

 

567,507

 

5.4

 

537,604

 

6.1

 

Total Purchased

 

903,166

 

24.5

 

1,817,176

 

56.9

 

4,374,153

 

41.9

 

5,547,216

 

62.5

 

Total Available Energy

 

3,685,345

 

100.0

%

3,191,695

 

100.0

%

10,444,121

 

100.0

%

8,880,996

 

100.0

%

 

 

(1)

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

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 2017 Annual Report on Form 10-K.  

20


Operational Availability

The operational availability of our owned generating resources for the three and nine months ended September 30, 2018 and 2017, was as follows:

 

 

Three Months

Ended

September 30,

 

 

Nine Months

Ended

September 30,

 

 

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

Wildcat Point (1)

 

 

93.4

%

 

 

%

 

 

87.0

%

 

 

%

 

Clover

 

 

92.1

 

 

 

90.0

 

 

 

80.7

 

 

 

77.9

 

 

North Anna

 

 

99.4

 

 

 

88.6

 

 

 

93.2

 

 

 

95.9

 

 

Louisa

 

 

100.0

 

 

 

87.7

 

 

 

96.8

 

 

 

92.8

 

 

Marsh Run

 

 

100.0

 

 

 

99.7

 

 

 

96.3

 

 

 

99.6

 

 

Rock Springs (2)

 

 

100.0

 

 

 

100.0

 

 

 

92.0

 

 

 

96.6

 

 

 

(1)

Wildcat Point achieved commercial operation on April 17, 2018, and was off-line from May 11, 2018 to May 28, 2018, for a scheduled outage.

 

(2)

Through September 14, 2018, the date our interest in Rock Springs and related assets was sold to EPRS.

Capacity Factor

The output of Wildcat Point, Clover, and North Anna for the three and nine months ended September 30, 2018 and 2017, as a percentage of maximum dependable capacity rating of the facilities, was as follows:

 

 

 

Three Months

Ended

September 30,

 

 

Nine Months

Ended

September 30,

 

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

Wildcat Point (1)

 

 

63.0

%

 

 

%

 

 

59.5

%

 

 

%

Clover

 

 

51.5

 

 

 

57.5

 

 

 

44.7

 

 

 

46.7

 

North Anna

 

 

99.2

 

 

 

89.1

 

 

 

94.4

 

 

 

98.0

 

 

(1)

Wildcat Point achieved commercial operation on April 17, 2018, and was off-line from May 11, 2018 to May 28, 2018, for a scheduled outage.

Outages

The scheduled and unscheduled outages for Clover and North Anna for the three and nine months ended September 30, 2018 and 2017, were as follows:

 

 

 

Clover

 

 

North Anna

 

 

 

Three Months

Ended

September 30,

 

 

Nine Months

Ended

September 30,

 

 

Three Months

Ended

September 30,

 

 

Nine Months

Ended

September 30,

 

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

 

(in days)

 

 

(in days)

 

Scheduled

 

 

 

 

 

 

 

 

64.7

 

 

 

77.5

 

 

 

 

 

 

21.0

 

 

 

36.2

 

 

 

21.0

 

Unscheduled

 

 

14.6

 

 

 

18.3

 

 

 

41.1

 

 

 

43.0

 

 

 

1.2

 

 

 

 

 

 

1.2

 

 

 

1.4

 

Total

 

 

14.6

 

 

 

18.3

 

 

 

105.8

 

 

 

120.5

 

 

 

1.2

 

 

 

21.0

 

 

 

37.4

 

 

 

22.4

 

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.

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

21


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 and amortize over future periods.

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

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 power supply resources, differences between actual and forecasted needs, and changes in market conditions.  

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 and nine months ended September 30, 2018 and 2017, were as follows:

 

 

Three Months

Ended

September 30,

 

 

Nine Months

Ended

September 30,

 

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

 

(in thousands)

 

Revenues from sales to:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Member distribution cooperatives

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Energy revenues

 

$

128,102

 

 

$

108,462

 

 

$

372,332

 

 

$

305,735

 

Demand revenues

 

 

102,308

 

 

 

75,416

 

 

 

285,203

 

 

 

216,690

 

Total revenues from sales to member distribution cooperatives

 

 

230,410

 

 

 

183,878

 

 

 

657,535

 

 

 

522,425

 

Non-members

 

 

27,176

 

 

 

9,547

 

 

 

54,712

 

 

 

17,686

 

Total operating revenues

 

$

257,586

 

 

$

193,425

 

 

$

712,247

 

 

$

540,111

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Energy sales to:

 

(in MWh)

 

Member distribution cooperatives

 

 

3,077,665

 

 

 

3,003,796

 

 

 

9,069,385

 

 

 

8,466,871

 

Non-members

 

 

580,761

 

 

 

173,018

 

 

 

1,324,291

 

 

 

385,295

 

Total energy sales

 

 

3,658,426

 

 

 

3,176,814

 

 

 

10,393,676

 

 

 

8,852,166

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

$

41.62

 

 

$

36.11

 

 

$

41.05

 

 

$

36.11

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average total cost to member distribution cooperatives (per MWh)

 

$

74.87

 

 

$

61.22

 

 

$

72.50

 

 

$

61.70

 

 

 

22


Sales of power and renewable energy credits for the three and nine months ended September 30, 2018 and 2017, were as follows:

 

 

 

Three Months

Ended

September 30,

 

 

Nine Months

Ended

September 30,

 

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

 

(in thousands)

 

Member distribution cooperatives

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales to member distribution cooperatives, excluding renewable energy credit sales

 

$

230,408

 

 

$

183,876

 

 

$

657,521

 

 

$

522,407

 

Renewable energy credit sales to member distribution cooperatives

 

 

2

 

 

 

2

 

 

 

14

 

 

 

18

 

Total sales to member distribution cooperatives

 

$

230,410

 

 

$

183,878

 

 

$

657,535

 

 

$

522,425

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Non-members

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sales to non-members, excluding renewable energy credit sales

 

$

24,791

 

 

$

7,332

 

 

$

51,762

 

 

$

13,980

 

Renewable energy credit sales to non-members

 

 

2,385

 

 

 

2,215

 

 

 

2,950

 

 

 

3,706

 

Total sales to non-members

 

$

27,176

 

 

$

9,547

 

 

$

54,712

 

 

$

17,686

 

Member Distribution Cooperatives

For the three and nine months ended September 30, 2018, total revenues from sales to our member distribution cooperatives were 25.3% higher and 25.9% higher, respectively, as compared to the same periods in 2017, due to increases in demand and energy revenues.  Demand revenues increased $26.9 million, or 35.7%, and $68.5 million, or 31.6%, respectively, primarily due to the increase in transmission expense and recognition of Wildcat Point expenses related to operations and maintenance, administrative and general, depreciation, and interest charges.  Energy revenues increased $19.6 million, or 18.1%, and $66.6 million, or 21.8%, respectively, due to the increase in the average cost of energy sold to our member distribution cooperatives and an increase in energy sales in MWh to our member distribution cooperatives.  The average cost of energy sold to our member distribution cooperatives increased 15.3% and 13.7%, respectively, due to the 11.1% and 3.7% total energy rate increases we implemented January 1, 2018 and April 1, 2018, respectively.  The energy sales in MWh to our member distribution cooperatives increased 2.5% and 7.1%, respectively.  Absent the impact of the removal of load under the limited exception under wholesale power contracts beginning May 1, 2018, our energy sales in MWh would have increased 5.5% and 8.9%, respectively.  

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:

 

Date

 

% Change

 

January 1, 2017

 

 

(6.7

)

January 1, 2018

 

 

11.1

 

April 1, 2018

 

3.7

 

Non-members

For the three and nine months ended September 30, 2018, revenues from sales to non-members increased $17.6 million and $37.0 million, respectively, as compared to the same periods in 2017.  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 power supply resources, differences between actual and forecasted needs, and changes in market conditions.

23


Operating Expenses

The following is a summary of the components of our operating expenses for the three and nine months ended September 30, 2018 and 2017:

 

 

 

Three Months

Ended

September 30,

 

 

Nine Months

Ended

September 30,

 

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

 

(in thousands)

 

Fuel

 

$

65,134

 

 

$

32,309

 

 

$

147,573

 

 

$

70,490

 

Purchased power

 

 

71,059

 

 

 

90,185

 

 

 

299,645

 

 

 

293,030

 

Transmission

 

 

39,916

 

 

 

24,280

 

 

 

105,145

 

 

 

72,001

 

Deferred energy

 

 

17,482

 

 

 

(2,408

)

 

 

(18,086

)

 

 

(28,651

)

Operations and maintenance

 

 

15,236

 

 

 

12,753

 

 

 

48,236

 

 

 

37,325

 

Administrative and general

 

 

11,593

 

 

 

10,769

 

 

 

34,848

 

 

 

33,208

 

Depreciation and amortization

 

 

17,057

 

 

 

11,357

 

 

 

45,818

 

 

 

34,040

 

Amortization of regulatory asset/liability, net

 

 

(2,816

)

 

 

1,021

 

 

 

(7,457

)

 

 

1,001

 

Accretion of asset retirement obligations

 

 

1,330

 

 

 

1,257

 

 

 

3,991

 

 

 

3,769

 

Taxes, other than income taxes

 

 

2,597

 

 

 

2,089

 

 

 

7,315

 

 

 

6,280

 

Total Operating Expenses

 

$

238,588

 

 

$

183,612

 

 

$

667,028

 

 

$

522,493

 

 

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 increased $55.0 million, or 29.9%, and $144.5 million, or 27.7%, respectively, for the three and nine months ended September 30, 2018, respectively, as compared to the same periods in 2017.  The increase for the three months ended September 30, 2018, was primarily due to increases in fuel, deferred energy, transmission, and depreciation and amortization, partially offset by the decrease in purchased power.  The increase for the nine months ended September 30, 2018, was primarily due to increases in fuel, transmission, depreciation and amortization, deferred energy, and operations and maintenance.  

 

Fuel expense increased $32.8 million, or 101.6%, and $77.1 million, or 109.4%, respectively, for the three and nine months ended September 30, 2018, as compared to the same periods in 2017.  Wildcat Point achieved commercial operation on April 17, 2018, and generated 1,331,437 MWh in the third quarter of 2018 and 2,286,185 MWh year-to-date.  Additionally, generation from our combustion turbine facilities increased 22.1% and 89.8%, respectively, due to PJM’s economic dispatch of these facilities.  

 

Transmission expense increased $15.6 million, or 64.4%, and $33.1 million, or 46.0%, respectively, for the three and nine months ended September 30, 2018, as compared to the same periods in 2017, primarily due to increases in PJM charges for network transmission services.

 

Depreciation and amortization increased $5.7 million, or 50.2%, and $11.8 million, or 34.6%, respectively, for the three and nine months ended September 30, 2018, as compared to the same periods in 2017, primarily due to depreciation expense related to Wildcat Point.

24


 

Deferred energy expense increased $19.9 million and $10.6 million for the three and nine months ended September 30, 2018, as compared to the same periods in 2017.  For the three months ended September 30, 2018 and 2017, we over-collected $17.5 million and under-collected $2.4 million, respectively.  For the nine months ended September 30, 2018 and 2017, we under-collected $18.1 million, and $28.7 million, respectively.  Deferred energy expense represents the difference between energy revenues and energy expenses.  For further discussion on deferred energy, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies—Deferred Energy” in Item 7 of our 2017 Annual Report on Form 10-K.

 

Operations and maintenance expense increased $10.9 million, or 29.2%, for the nine months ended September 30, 2018, as compared to the same period in 2017, primarily due to Wildcat Point-related expenses.

 

Purchased power expense, which includes the cost of purchased energy and capacity, decreased $19.1 million, or 21.2%, for the three months ended September 30, 2018, as compared to the same period in 2017, due to the 50.3% decrease in the volume of purchased energy partially offset by the 60.8% increase in the average cost of purchased energy.  

Other Items

Investment Income

Investment income decreased $3.5 million for the nine months ended September 30, 2018, as compared to the same period in 2017, primarily due to decreased earnings on our nuclear decommissioning trust.

Interest Income on North Anna Unit 3 Cost Recovery

Interest income on North Anna Unit 3 cost recovery represents interest received from Virginia Power related to the recovery of a portion of our North Anna Unit 3 regulatory asset.  See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Other Items—Interest Income on North Anna Unit 3 Cost Recovery” in Item 7 of our 2017 Annual Report on Form 10-K.

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 and nine months ended September 30, 2018 and 2017, were as follows:

 

 

 

Three Months

Ended

September 30,

 

 

Nine Months

Ended

September 30,

 

 

 

 

2018

 

 

2017

 

 

2018

 

 

2017

 

 

 

 

(in thousands)

 

 

Interest on long-term debt

 

$

(15,553

)

 

$

(15,781

)

 

$

(46,656

)

 

$

(43,353

)

 

Interest on revolving credit facility

 

 

(693

)

 

 

(324

)

 

 

(1,948

)

 

 

(2,404

)

 

Other interest

 

 

(738

)

 

 

(189

)

 

 

(1,286

)

 

 

(608

)

 

Total interest charges

 

 

(16,984

)

 

 

(16,294

)

 

 

(49,890

)

 

 

(46,365

)

 

Allowance for borrowed funds used during construction

 

 

122

 

 

 

8,860

 

 

 

11,016

 

 

 

26,360

 

 

Interest charges, net

 

$

(16,862

)

 

$

(7,434

)

 

$

(38,874

)

 

$

(20,005

)

 

Interest charges, net increased $9.4 million, and $18.9 million, respectively, for the three and nine months ended September 30, 2018, as compared to the same periods in 2017, substantially due to the decrease 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 and nine months ended September 30, 2018, as compared to the same periods in 2017.

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Financial Condition

The principal changes in our financial condition from December 31, 2017 to September 30, 2018, were caused by increases in property, plant, and equipment, regulatory liabilities, accounts payable, accrued expenses, and deferred energy, and decreases in construction work in progress, lease deposits, obligations under long-term lease, and revolving credit facility.

 

Property, plant, and equipment increased $693.2 million, primarily due to the reclassification of Wildcat Point from construction work in progress, partially offset by the decrease related to the sale of our interest in Rock Springs and related assets.  

 

Regulatory liabilities increased $47.2 million primarily due to the deferral of the gain on the sale of our interest in Rock Springs and related assets.

 

Accounts payable increased $19.6 million primarily due to increased construction-related payables.

 

Accrued expenses increased $18.7 million due to accrued interest on long-term debt and accrued property taxes.

 

Deferred energy increased $18.1 million as a result of the under-collection of our energy costs in 2018.  The deferred energy balance was an under-collection of $3.7 million and $21.8 million at December 31, 2017, and September 30, 2018, respectively.  

 

Construction work in progress decreased $788.8 million primarily due to the reclassification of Wildcat Point to property, plant, and equipment.

 

Lease deposits and obligations under long-term lease decreased $74.2 million and $71.5 million, respectively, due to the payments related to the Clover lease.  For further discussion of the Clover lease, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Significant Contingent Obligations—Clover Lease” in Item 7 of our 2017 Annual Report on Form 10-K.  

 

Revolving credit facility decreased $43.4 million due to the repayment of outstanding borrowings under this facility using a portion of the proceeds from the sale of our interest in Rock Springs and related assets.

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.  Additionally, in 2018, we had cash provided by the sale of an asset.

Operations

During the first nine months of 2018 and 2017, our operating activities provided cash flows of $64.9 million and $71.1 million, respectively.  

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 March 3, 2023.  Available funding under this facility totals $500 million through March 3, 2022, and $400 million from March 4, 2022 through March 3, 2023.  As of September 30, 2018, we had no borrowings and $2.5 million in letters of credit outstanding under this facility.  As of December 31, 2017, we had $43.4 million in borrowings and $12.0 million in letters of credit outstanding under this facility.

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.

26


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.

27


ITEM 3.  QUANTITATIVE AND QUALITATIVE

DISCLOSURES ABOUT MARKET RISK

No material changes occurred in our exposure to market risk during the third quarter of 2018.

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.

 

 

 

 

 

 

 

 

 

 

 

 

 

28


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 we previously suggested and FERC directed in the January 19, 2017 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.  On March 22, 2018, FERC issued an order denying Bear Island's request for rehearing and accepted our February 21, 2017 compliance filing that revised the formula rate as directed by FERC's January 19, 2017 order.  We filed a refund report with FERC on April 23, 2018, that calculated the difference between rates charged under our rate schedule since January 1, 2014, and rates that would have been charged under the revised rate schedule submitted in our February 21, 2017 compliance filing.  On July 24, 2018, FERC accepted the refund report which resulted in a reallocation of costs among our member distribution cooperatives and did not result in any change to our total operating revenues.

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, on April 11, 2016, we filed a Petition for Review in the United States Court of Appeals for the District of Columbia Circuit, and on October 24, 2017, the court heard oral arguments.  On June 15, 2018, the court denied our Petition for Review.  Additionally, we have followed the legal process to preserve our right to pursue this matter in the Commonwealth of Virginia.  We have not recorded a receivable related to this matter.

Wildcat Point

On April 17, 2018, Wildcat Point, an approximate 1,000 MW natural gas-fueled combined cycle generation facility, achieved commercial operation and was available for dispatch by PJM.

The facility originally was scheduled to become operational in mid-2017.  WOPC, a joint venture between PCL Industrial Construction Company and Sargent & Lundy, L.L.C., as the EPC contractor, claims the delay was associated with the incurrence of additional work and other matters, including alleged misrepresentation in the EPC contract, for which it will seek recovery, in whole or in part, from its subcontractors and us.  On May 24, 2017, WOPC filed a complaint against Alstom and us, in the United States District Court for the District of Maryland.  An amended complaint was filed on July 21, 2017.  On August 21, 2017, motions were filed by Alstom and us to transfer venue from the United States District Court for the District of Maryland to the United States District Court for the Eastern District of Virginia, and on November 7, 2017, these motions were granted.  We have reviewed the asserted claims of WOPC against us and believe they are without merit.  We have not recorded any liability related to these claims as we do not believe any liability is estimable or probable.  We intend to vigorously defend against these claims.

Additionally, on September 29, 2017, we filed a complaint in the United States District Court for the Eastern District of Virginia against WOPC, alleging that WOPC breached the EPC contract.  On November 16, 2017, 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 on May 9, 2017, be consolidated into one

29


case.  On June 27, 2018, an order was issued establishing January 9, 2019 as the date to check the status of discovery, set summary judgement deadlines, and set a trial date.

If it is ultimately determined that we owe any such amounts to WOPC, the amounts are not expected to have a material impact on our financial position or results of operations due to our ability to collect such amounts through rates to 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 2017 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

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

On October 16, 2017, the EPA proposed a rule to repeal the Clean Power Plan, and on August 21, 2018, a replacement rule for the Clean Power Plan referred to as the Affordable Clean Energy rule was proposed.  We continue to monitor the rulemaking, and are utilizing stakeholder processes to provide comments.  We currently cannot predict the impact of the proposed Affordable Clean Energy rule on our existing facilities due to the uncertainties and complexities of the regulations and the unclear status of efforts to repeal the plan.  For further discussion of the Clean Power Plan, see “Regulation—Environmental—CO2 Emissions Guidelines for Existing EGUs (“Clean Power Plan”)” in Part I, Item 1 of our 2017 Annual Report on Form 10-K.  We will continue to follow the process closely.

Virginia CO2 Regulation

The governor of the Commonwealth of Virginia issued an executive directive on May 16, 2017, directing the Virginia Department of Environmental Quality to develop a proposed regulation by the end of 2017 to abate, control, or limit CO2 emissions from electric power facilities.  The proposed rule was presented to the Virginia Air Pollution Control Board for approval and was subsequently published in the Virginia Register of Regulations on January 8, 2018, with a 90-day public comment period.  After the comment period, a re-proposal of the regulation was made to the Virginia Air Pollution Control Board and on October 29, 2018, they approved the publication of the re-proposal in the Virginia Register of Regulations. Once the re-proposal is published, there will be a 30-day comment period.  For further discussion of the Virginia CO2 Regulation, see “Regulation—Environmental—Virginia CO2 Regulation” in Part I, Item 1 of our 2017 Annual Report on Form 10-K.  We will continue to follow the process closely.

 

30


ITEM 6.  EXHIBITS

 

 

 

 

  31.1

 

Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a)

  31.2

 

Certification of the Chief Financial Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a)

  32.1

 

Certification of the Chief Executive Officer pursuant to 18 U.S.C.  § 1350

  32.2

 

Certification of the Chief Financial Officer pursuant to 18 U.S.C.  § 1350

101.INS

 

XBRL Instance Document

101.SCH

 

XBRL Taxonomy Extension Schema Document

101.CAL

 

XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB

 

XBRL Taxonomy Extension Label Linkbase Document

101.PRE

 

XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF

 

XBRL Taxonomy Extension Definition Linkbase Document

 

31


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.

 

 

OLD DOMINION ELECTRIC COOPERATIVE

 

 

Registrant

 

 

 

Date: November 13, 2018

 

/s/ BRYAN  S. ROGERS

 

 

Bryan S. Rogers

 

 

Senior Vice President and Chief Financial Officer

 

 

(Principal financial officer)

 

 

 

32