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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 June 30, 2017

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

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

 

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

 

 

 

EPC

 

Engineering, procurement, and construction

 

 

 

FERC

 

Federal Energy Regulatory Commission

 

 

 

GAAP

 

Accounting principles generally accepted in the United States

 

 

 

Mitsubishi

 

Mitsubishi Hitachi Power Systems Americas, Inc.

 

 

 

MPSC

 

Maryland Public Service Commission

 

 

 

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

 

 

 

VSCC

 

Virginia State Corporation Commission

 

 

 

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 – June 30, 2017 (unaudited) and December 31, 2016

 

4

 

 

 

Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital (unaudited) – Three and Six Months Ended June 30, 2017 and 2016

 

5

 

 

 

Condensed Consolidated Statements of Cash Flows (unaudited) – Six Months Ended June 30, 2017 and 2016

 

6

 

 

 

Notes to Condensed Consolidated Financial Statements

 

7

 

 

 

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

 

15

 

 

 

Item 3.  Quantitative and Qualitative Disclosures About Market Risk

 

26

 

 

 

Item 4.  Controls and Procedures

 

26

 

 

 

PART II.  Other Information

 

27

 

 

 

Item 1.  Legal Proceedings

 

27

 

 

 

Item 1A.  Risk Factors

 

27

 

 

 

Item 5.  Other Information

 

27

 

 

 

Item 6.  Exhibits

 

29

 

3


OLD DOMINION ELECTRIC COOPERATIVE

PART 1.  FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

 

June 30,

2017

 

 

December 31,

2016

 

 

 

(in thousands)

 

 

 

(unaudited)

 

 

 

 

 

ASSETS:

 

 

 

 

 

 

 

 

Electric Plant:

 

 

 

 

 

 

 

 

Property, plant, and equipment

 

$

1,749,293

 

 

$

1,746,852

 

Less accumulated depreciation

 

 

(876,767

)

 

 

(855,068

)

Net Property, plant, and equipment

 

 

872,526

 

 

 

891,784

 

Nuclear fuel, at amortized cost

 

 

15,536

 

 

 

22,138

 

Construction work in progress

 

 

810,141

 

 

 

736,996

 

Net Electric Plant

 

 

1,698,203

 

 

 

1,650,918

 

Investments:

 

 

 

 

 

 

 

 

Nuclear decommissioning trust

 

 

170,554

 

 

 

159,155

 

Lease deposits

 

 

105,278

 

 

 

104,514

 

Unrestricted investments and other

 

 

7,117

 

 

 

6,599

 

Total Investments

 

 

282,949

 

 

 

270,268

 

Current Assets:

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

 

1,147

 

 

 

2,946

 

Accounts receivable

 

 

11,022

 

 

 

6,563

 

Accounts receivable–members

 

 

73,688

 

 

 

85,116

 

Fuel, materials, and supplies

 

 

61,880

 

 

 

56,353

 

Prepayments and other

 

 

7,017

 

 

 

4,737

 

Total Current Assets

 

 

154,754

 

 

 

155,715

 

Deferred Charges:

 

 

 

 

 

 

 

 

Regulatory assets

 

 

46,019

 

 

 

49,682

 

Other

 

 

2,267

 

 

 

3,533

 

Total Deferred Charges

 

 

48,286

 

 

 

53,215

 

Total Assets

 

$

2,184,192

 

 

$

2,130,116

 

CAPITALIZATION AND LIABILITIES:

 

 

 

 

 

 

 

 

Capitalization:

 

 

 

 

 

 

 

 

Patronage capital

 

$

408,872

 

 

$

402,857

 

Non-controlling interest

 

 

5,735

 

 

 

5,725

 

Total Patronage capital and Non-controlling interest

 

 

414,607

 

 

 

408,582

 

Long-term debt

 

 

990,257

 

 

 

990,083

 

Revolving credit facility

 

 

239,550

 

 

 

152,000

 

Total long-term debt and revolving credit facility

 

 

1,229,807

 

 

 

1,142,083

 

Total Capitalization

 

 

1,644,414

 

 

 

1,550,665

 

Current Liabilities:

 

 

 

 

 

 

 

 

Long-term debt due within one year

 

 

28,292

 

 

 

28,292

 

Accounts payable

 

 

102,114

 

 

 

131,581

 

Accounts payable–members

 

 

72,994

 

 

 

66,380

 

Accrued expenses

 

 

7,436

 

 

 

5,806

 

Deferred energy

 

 

13,786

 

 

 

40,029

 

Total Current Liabilities

 

 

224,622

 

 

 

272,088

 

Deferred Credits and Other Liabilities:

 

 

 

 

 

 

 

 

Asset retirement obligations

 

 

122,539

 

 

 

120,083

 

Obligations under long-term lease

 

 

100,304

 

 

 

96,930

 

Regulatory liabilities

 

 

91,418

 

 

 

89,020

 

Other

 

 

895

 

 

 

1,330

 

Total Deferred Credits and Other Liabilities

 

 

315,156

 

 

 

307,363

 

Commitments and Contingencies

 

 

 

 

 

 

Total Capitalization and Liabilities

 

$

2,184,192

 

 

$

2,130,116

 

 

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

June 30,

 

 

Six Months Ended

June 30,

 

 

 

2017

 

 

2016

 

 

2017

 

 

2016

 

 

 

(in thousands)

 

 

(in thousands)

 

Operating Revenues

 

$

156,907

 

 

$

199,149

 

 

$

346,686

 

 

$

455,608

 

Operating Expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fuel

 

 

20,498

 

 

 

30,266

 

 

 

38,181

 

 

 

64,588

 

Purchased power

 

 

80,729

 

 

 

80,999

 

 

 

202,845

 

 

 

220,281

 

Transmission

 

 

23,979

 

 

 

30,772

 

 

 

47,721

 

 

 

62,360

 

Deferred energy

 

 

(4,705

)

 

 

8,869

 

 

 

(26,243

)

 

 

10,414

 

Operations and maintenance

 

 

12,099

 

 

 

12,618

 

 

 

24,572

 

 

 

25,177

 

Administrative and general

 

 

11,309

 

 

 

10,156

 

 

 

22,439

 

 

 

20,795

 

Depreciation and amortization

 

 

11,340

 

 

 

11,630

 

 

 

22,683

 

 

 

23,168

 

Amortization of regulatory asset/(liability), net

 

 

(850

)

 

 

646

 

 

 

(20

)

 

 

77

 

Accretion of asset retirement obligations

 

 

1,257

 

 

 

1,211

 

 

 

2,512

 

 

 

2,421

 

Taxes, other than income taxes

 

 

2,087

 

 

 

2,098

 

 

 

4,191

 

 

 

4,219

 

Total Operating Expenses

 

 

157,743

 

 

 

189,265

 

 

 

338,881

 

 

 

433,500

 

Operating Margin

 

 

(836

)

 

 

9,884

 

 

 

7,805

 

 

 

22,108

 

Other expense, net

 

 

(955

)

 

 

(905

)

 

 

(1,904

)

 

 

(1,949

)

Investment income

 

 

6,748

 

 

 

1,327

 

 

 

8,269

 

 

 

1,465

 

Interest income on North Anna Unit 3 cost recovery

 

 

4,427

 

 

 

 

 

 

4,427

 

 

 

 

Interest charges, net

 

 

(6,327

)

 

 

(7,341

)

 

 

(12,571

)

 

 

(15,706

)

Income taxes

 

 

(2

)

 

 

(2

)

 

 

(2

)

 

 

(3

)

Net Margin including Non-controlling interest

 

 

3,055

 

 

 

2,963

 

 

 

6,024

 

 

 

5,915

 

Non-controlling interest

 

 

(8

)

 

 

(8

)

 

 

(9

)

 

 

(7

)

Net Margin attributable to ODEC

 

 

3,047

 

 

 

2,955

 

 

 

6,015

 

 

 

5,908

 

Patronage Capital - Beginning of Period

 

 

405,825

 

 

 

393,929

 

 

 

402,857

 

 

 

390,976

 

Patronage Capital - End of Period

 

$

408,872

 

 

$

396,884

 

 

$

408,872

 

 

$

396,884

 

 

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)

 

 

 

Six Months Ended June 30,

 

 

 

 

2017

 

 

2016

 

 

 

 

(in thousands)

 

 

Operating Activities:

 

 

 

 

 

 

 

 

 

Net Margin including Non-controlling interest

 

$

6,024

 

 

$

5,915

 

 

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

 

 

 

 

 

 

 

 

 

Depreciation and amortization

 

 

22,683

 

 

 

23,168

 

 

Other non-cash charges

 

 

9,625

 

 

 

9,216

 

 

Amortization of lease obligations

 

 

3,374

 

 

 

3,152

 

 

Interest on lease deposits

 

 

(1,511

)

 

 

(1,479

)

 

Change in current assets

 

 

(838

)

 

 

16,640

 

 

Change in deferred energy

 

 

(26,243

)

 

 

10,414

 

 

Change in current liabilities

 

 

(12,592

)

 

 

(49,221

)

 

Change in regulatory assets and liabilities

 

 

2,800

 

 

 

8,339

 

 

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

 

 

1,301

 

 

 

104

 

 

Net Cash Provided by Operating Activities

 

 

4,623

 

 

 

26,248

 

 

Investing Activities:

 

 

 

 

 

 

 

 

 

Purchases of held to maturity securities

 

 

(2,523

)

 

 

 

 

Proceeds from sale of held to maturity securities

 

 

2,824

 

 

 

 

 

Increase in other investments

 

 

(8,193

)

 

 

(1,270

)

 

Electric plant additions

 

 

(86,080

)

 

 

(148,038

)

 

Net Cash Used for Investing Activities

 

 

(93,972

)

 

 

(149,308

)

 

Financing Activities:

 

 

 

 

 

 

 

 

 

Draws on revolving credit facility

 

 

303,250

 

 

 

92,100

 

 

Repayments on revolving credit facility

 

 

(215,700

)

 

 

(25,500

)

 

Net Cash Provided by Financing Activities

 

 

87,550

 

 

 

66,600

 

 

Net Change in Cash and Cash Equivalents

 

 

(1,799

)

 

 

(56,460

)

 

Cash and Cash Equivalents - Beginning of Period

 

 

2,946

 

 

 

58,383

 

 

Cash and Cash Equivalents - End of Period

 

$

1,147

 

 

$

1,923

 

 

 

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 June 30, 2017, our consolidated results of operations for the three and six months ended June 30, 2017 and 2016, and cash flows for the six months ended June 30, 2017 and 2016.  The consolidated results of operations for the three and six months ended June 30, 2017, are not necessarily indicative of the results to be expected for the entire year.  These financial statements should be read in conjunction with the financial statements and notes thereto included in our 2016 Annual Report on Form 10-K filed with the Securities and Exchange Commission.

The accompanying financial statements reflect the consolidated accounts of Old Dominion Electric Cooperative and TEC.  We are a not-for-profit wholesale power supply cooperative, incorporated under the laws of the Commonwealth of Virginia in 1948.  We have two classes of members.  Our Class A members are eleven customer-owned electric distribution cooperatives engaged in the retail sale of power to member customers located in Virginia, Delaware, and Maryland.  Our sole Class B member is TEC, a taxable corporation owned by our member distribution cooperatives.  Our board of directors is composed of two representatives from each of the member distribution cooperatives and one representative from TEC.  In accordance with Consolidation Accounting, TEC is considered a variable interest entity for which we are the primary beneficiary.  We have eliminated all intercompany balances and transactions in consolidation.  The assets and liabilities and non-controlling interest of TEC are recorded at carrying value and the consolidated assets were $5.7 million as of June 30, 2017 and December 31, 2016.  The income taxes reported on our Condensed Consolidated Statement of Revenues, Expenses, and Patronage Capital relate to the tax provision for TEC.  As TEC is wholly-owned by our Class A members, its equity is presented as a non-controlling interest in our consolidated financial statements.

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

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

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

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

 

 

 

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 June 30, 2017 and December 31, 2016: 

 

 

 

 

 

 

Quoted Prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

in Active

 

 

Significant

 

 

 

 

 

 

 

 

 

 

Markets for

 

 

Other

 

 

Significant

 

 

 

 

 

 

Identical

 

 

Observable

 

 

Unobservable

 

 

June 30,

 

 

Assets

 

 

Inputs

 

 

Inputs

 

 

2017

 

 

(Level 1)

 

 

(Level 2)

 

 

(Level 3)

 

 

(in thousands)

 

Nuclear decommissioning trust (1)

$

58,650

 

 

$

58,650

 

 

$

 

 

$

 

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

 

111,904

 

 

 

 

 

 

 

 

 

 

Unrestricted investments and other (3)

 

265

 

 

 

 

 

 

265

 

 

 

 

Derivatives - gas and power (4)

 

549

 

 

 

549

 

 

 

 

 

 

 

Total Financial Assets

$

171,368

 

 

$

59,199

 

 

$

265

 

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivatives - gas and power (4)

$

89

 

 

$

89

 

 

$

 

 

$

 

Total Financial Liabilities

$

89

 

 

$

89

 

 

$

 

 

$

 

 

 

 

 

 

 

Quoted Prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

in Active

 

 

Significant

 

 

 

 

 

 

 

 

 

 

Markets for

 

 

Other

 

 

Significant

 

 

 

 

 

 

Identical

 

 

Observable

 

 

Unobservable

 

 

December 31,

 

 

Assets

 

 

Inputs

 

 

Inputs

 

 

2016

 

 

(Level 1)

 

 

(Level 2)

 

 

(Level 3)

 

 

(in thousands)

 

Nuclear decommissioning trust (1)

$

48,142

 

 

$

48,142

 

 

$

 

 

$

 

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

 

111,013

 

 

 

 

 

 

 

 

 

 

Unrestricted investments and other (3)

 

247

 

 

 

 

 

 

247

 

 

 

 

Derivatives - gas and power (4)

 

6,968

 

 

 

4,874

 

 

 

2,094

 

 

 

 

Total Financial Assets

$

166,370

 

 

$

53,016

 

 

$

2,341

 

 

$

 

 

 

(1)

For additional information about our nuclear decommissioning trust see Note 4 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 2016 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 2016 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.

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

 

 

 

 

 

As of

 

 

As of

 

 

 

 

 

June 30, 2017

 

 

December 31, 2016

 

Commodity

 

Unit of Measure

 

Quantity

 

 

Quantity

 

Natural Gas

 

MMBTU

 

 

16,970,000

 

 

 

14,250,000

 

 

 

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

 

 

 

 

 

Fair Value

 

 

 

 

 

As of

June 30,

 

 

As of

December 31,

 

 

 

Balance Sheet Location

 

2017

 

 

2016

 

 

 

 

 

(in thousands)

 

Derivatives in an asset position:

 

 

 

 

 

 

 

 

 

 

Natural gas futures contracts

 

Deferred charges-other

 

$

549

 

 

$

6,968

 

Total derivatives in an asset position

 

 

 

$

549

 

 

$

6,968

 

 

 

 

 

 

 

 

 

 

 

 

Derivatives in a liability position:

 

 

 

 

 

 

 

 

 

 

Natural gas futures contracts

 

Deferred credits and other liabilities-other

 

$

89

 

 

$

-

 

Total derivatives in a liability position

 

 

 

$

89

 

 

$

-

 

 

The Effect of Derivative Instruments on the Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital for the Three and Six Months Ended June 30, 2017 and 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

 

 

Asset/Liability for

 

 

from Regulatory

 

into Income for

 

 

into Income for

 

Derivatives Accounted for

 

Derivatives as of

 

 

Asset/Liability

 

the Three Months

 

 

the Six Months

 

Utilizing Regulatory Accounting

 

June 30,

 

 

into Income

 

Ended June 30,

 

 

Ended June 30,

 

 

 

2017

 

 

2016

 

 

 

 

2017

 

 

2016

 

 

2017

 

 

2016

 

 

 

(in thousands)

 

 

 

 

(in thousands)

 

 

(in thousands)

 

Natural gas futures contracts

 

$

656

 

 

$

2,093

 

 

Fuel

 

$

(867

)

 

$

(1,475

)

 

$

(999

)

 

$

(2,498

)

Total

 

$

656

 

 

$

2,093

 

 

 

 

$

(867

)

 

$

(1,475

)

 

$

(999

)

 

$

(2,498

)

 

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 June 30, 2017 and December 31, 2016:

 

 

 

 

 

 

 

 

 

Gross

 

 

Gross

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Unrealized

 

 

Unrealized

 

 

Fair

 

 

Carrying

 

Description

 

Designation

 

Cost

 

 

Gains

 

 

Losses

 

 

Value

 

 

Value

 

 

 

 

 

(in thousands)

 

June 30, 2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Nuclear decommissioning trust (1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Debt securities

 

Available for sale

 

$

53,668

 

 

$

4,564

 

 

$

 

 

$

58,232

 

 

$

58,232

 

Equity securities

 

Available for sale

 

 

73,990

 

 

 

37,914

 

 

 

 

 

 

111,904

 

 

 

111,904

 

Cash and other

 

Available for sale

 

 

418

 

 

 

 

 

 

 

 

 

418

 

 

 

418

 

Total Nuclear Decommissioning Trust

 

 

 

$

128,076

 

 

$

42,478

 

 

$

 

 

$

170,554

 

 

$

170,554

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease Deposits (2)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Government obligations

 

Held to maturity

 

$

105,278

 

 

$

1,841

 

 

$

 

 

$

107,119

 

 

$

105,278

 

Total Lease Deposits

 

 

 

$

105,278

 

 

$

1,841

 

 

$

 

 

$

107,119

 

 

$

105,278

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Unrestricted investments

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Government obligations

 

Held to maturity

 

$

2,340

 

 

$

 

 

$

(8

)

 

$

2,332

 

 

$

2,340

 

Debt securities

 

Held to maturity

 

 

2,342

 

 

 

1

 

 

 

 

 

 

2,343

 

 

 

2,342

 

Total Unrestricted Investments

 

 

 

$

4,682

 

 

$

1

 

 

$

(8

)

 

$

4,675

 

 

$

4,682

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity securities

 

Trading

 

$

199

 

 

$

66

 

 

$

 

 

$

265

 

 

$

265

 

Non-marketable equity investments

 

Equity

 

 

2,170

 

 

 

2,074

 

 

 

 

 

 

4,244

 

 

 

2,170

 

Total Other

 

 

 

$

2,369

 

 

$

2,140

 

 

$

 

 

$

4,509

 

 

$

2,435

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$

282,949

 

December 31, 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Nuclear decommissioning trust (1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Debt securities

 

Available for sale

 

$

44,086

 

 

$

3,537

 

 

$

 

 

$

47,623

 

 

$

47,623

 

Equity securities

 

Available for sale

 

 

75,332

 

 

 

35,958

 

 

 

(277

)

 

 

111,013

 

 

 

111,013

 

Cash and other

 

Available for sale

 

 

519

 

 

 

 

 

 

 

 

 

519

 

 

 

519

 

Total Nuclear Decommissioning Trust

 

 

 

$

119,937

 

 

$

39,495

 

 

$

(277

)

 

$

159,155

 

 

$

159,155

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease Deposits (2)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Government obligations

 

Held to maturity

 

$

104,514

 

 

$

2,948

 

 

$

 

 

$

107,462

 

 

$

104,514

 

Total Lease Deposits

 

 

 

$

104,514

 

 

$

2,948

 

 

$

 

 

$

107,462

 

 

$

104,514

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Unrestricted investments

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Government obligations

 

Held to maturity

 

$

2,000

 

 

$

1

 

 

$

 

 

$

2,001

 

 

$

2,000

 

Debt securities

 

Held to maturity

 

 

2,210

 

 

 

6

 

 

 

 

 

 

2,216

 

 

 

2,210

 

Total Unrestricted Investments

 

 

 

$

4,210

 

 

$

7

 

 

$

 

 

$

4,217

 

 

$

4,210

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity securities

 

Trading

 

$

198

 

 

$

49

 

 

$

 

 

$

247

 

 

$

247

 

Non-marketable equity investments

 

Equity

 

 

2,142

 

 

 

2,012

 

 

 

 

 

 

4,154

 

 

 

2,142

 

Total Other

 

 

 

$

2,340

 

 

$

2,061

 

 

$

 

 

$

4,401

 

 

$

2,389

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$

270,268

 

 

 

(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 2016 Annual Report on Form 10-K.  Unrealized gains and losses related to assets held in the nuclear decommissioning trust are deferred as a regulatory asset or liability, respectively.

 

(2)

Investments in lease deposits are restricted for the use of funding our future lease obligations.  See Note 8 of the Notes to Consolidated Financial Statements in our 2016 Annual Report on Form 10-K.

11


Our investments by classification as of June 30, 2017 and December 31, 2016, were as follows:

 

 

 

June 30, 2017

 

 

December 31, 2016

 

 

 

 

 

 

 

Carrying

 

 

 

 

 

 

Carrying

 

Description

 

Cost

 

 

Value

 

 

Cost

 

 

Value

 

 

 

(in thousands)

 

 

(in thousands)

 

Available for sale

 

$

128,076

 

 

$

170,554

 

 

$

119,937

 

 

$

159,155

 

Held to maturity

 

 

109,960

 

 

 

109,960

 

 

 

108,724

 

 

 

108,724

 

Equity

 

 

2,170

 

 

 

2,170

 

 

 

2,142

 

 

 

2,142

 

Trading

 

 

199

 

 

 

265

 

 

 

198

 

 

 

247

 

     Total

 

$

240,405

 

 

$

282,949

 

 

$

231,001

 

 

$

270,268

 

 

Contractual maturities of debt securities as of June 30, 2017, were as follows:

 

 

 

Less than

 

 

 

 

 

 

 

 

 

 

More than

 

 

 

 

 

Description

 

1 year

 

 

1-5 years

 

 

5-10 years

 

 

10 years

 

 

Total

 

 

 

(in thousands)

 

Available for sale (1)

 

$

 

 

$

 

 

$

58,232

 

 

$

 

 

$

58,232

 

Held to maturity

 

 

43,268

 

 

 

66,692

 

 

 

 

 

 

 

 

 

109,960

 

     Total

 

$

43,268

 

 

$

66,692

 

 

$

58,232

 

 

$

 

 

$

168,192

 

 

 

 

(1)

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

 

 

 

 

5.

Other

Wildcat Point Generation Facility 

We are currently constructing, and will be the sole owner of, an approximate 1,000 MW natural gas-fueled combined cycle generation facility, named Wildcat Point, in Cecil County, Maryland.  Wildcat Point's major equipment will consist of two Mitsubishi combustion turbines, two Alstom heat recovery steam generators, and one Alstom steam turbine generator.  While the facility was scheduled to become operational in mid-2017, based upon the most recent information available, we believe that Wildcat Point will achieve substantial completion in the fourth quarter of 2017.  WOPC, the EPC contractor, claims that the delay is 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.  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, and Alstom and we have until August 21, 2017 to respond to the amended complaint.  See “Item 1 – Legal Proceedings.”  We believe that this complaint is without merit and we plan to vigorously defend this claim.  Further, we disagree that we have additional liability under the contract and therefore have not revised our estimated project cost of $834.3 million, before consideration of any liquidated damages which may be due to us as a result of the project delay.  We do not believe that any such delay in the substantial completion of the Wildcat Point facility, or any additional amounts associated with the delay, including PJM capacity delay charges, for which we may be ultimately responsible, are reasonably likely to have a material adverse effect on our results of operations or financial condition due to our ability to collect such amounts through rates charged to our member distribution cooperatives.  Even if we are ultimately responsible for additional costs, any such amounts may be offset in part by liquidated damages under the contract associated with WOPC’s delay in achieving substantial completion.

Through June 30, 2017, we capitalized construction costs related to Wildcat Point totaling $775.8 million, including $59.9 million of capitalized interest, offset by $11.4 million of liquidated damages.

12


FERC Proceeding Related to Formula Rate

On September 30, 2013, we filed with FERC to revise our cost-based formula rate in order to more closely align our cost recovery from our member distribution cooperatives with the methodologies used by PJM to allocate costs to us.  On November 8, 2013, Bear Island, a customer of REC, filed a motion to intervene, protest, and request for hearing.  On December 2, 2013, FERC issued its order accepting the proposed revisions for filing to become effective January 1, 2014, subject to refund, and establishing hearing and settlement procedures.  On April 13, 2015, we received an initial decision from the hearing judge.  On January 19, 2017, FERC issued its order on the hearing judge's initial decision.  On February 21, 2017, we submitted our compliance filing, revising the formula rate as directed in the order.  Additionally, on February 21, 2017, Bear Island filed a request for rehearing.  On March 22, 2017, FERC issued an order granting rehearing of its initial order for the limited purpose of FERC's further consideration of the matter.  Our formula rate remains in effect subject to refund pending a final order from FERC.  If a refund is ultimately determined, we believe it will result in a reallocation of costs among our member distribution cooperatives.

Recovery of Costs from PJM

On June 23, 2014, we filed a petition at FERC seeking recovery from PJM of approximately $14.9 million of unreimbursed costs, which were incurred during the first quarter of 2014 related to the dispatch of our combustion turbine generating facilities.  On June 9, 2015, FERC denied our petition, on July 9, 2015, we filed a request for rehearing, and on August 10, 2015, FERC issued an order granting rehearing for the limited purpose of FERC's further consideration of the matter.  On March 1, 2016, FERC denied our request for rehearing and on April 11, 2016, we filed a Petition for Review in the U.S. Court of Appeals for the District of Columbia Circuit.  Also related to this matter, on January 5, 2017, we filed a complaint and request for relief in the Circuit Court for the County of Henrico in the Commonwealth of Virginia.  We have not recorded a receivable related to this matter.

Long-term Debt

On July 6, 2017, we issued $250.0 million of long-term debt in a private placement transaction.  The issuance consists of $250.0 million of 3.33% First Mortgage Bonds, 2017 Series A due December 1, 2037.  

Revolving Credit Facility

We maintain a $500.0 million revolving credit facility to cover our short-term and medium-term funding needs that are not met by cash from operations or other available funds.  The syndicated credit agreement associated with the facility was amended and restated on March 3, 2017, and commitments under this agreement extend until March 3, 2022.  As of June 30, 2017, we had outstanding under this facility, $239.6 million in borrowings and $12.2 million in letters of credit.  We utilized the proceeds of our July 6, 2017 debt issuance to repay the borrowings outstanding under this facility as of July 7, 2017.  As of December 31, 2016, we had outstanding under this facility, $152.0 million in borrowings and $5.2 million in letters of credit.  

Limited Exception under Wholesale Power Contracts

We have a wholesale power contract with each of our member distribution cooperatives.  Each contract obligates us to sell and deliver to the member distribution cooperative, and obligates the member distribution cooperative to purchase and receive from us, all power that it requires for the operation of its system, with limited exceptions.  One of the limited exceptions permits each of our member distribution cooperatives to receive up to the greater of 5% of its demand and associated energy or 5 MW and associated energy from owned generation or other suppliers.  If all of our member distribution cooperatives elected to utilize the 5% or 5 MW exception, we estimate the current impact would be a reduction of approximately 175 MW of demand and associated energy.  The following table summarizes the 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

 

We do not anticipate that utilization of this exception will have a material impact on our financial condition, results of operations, or cash flows.

13


 

Retail Choice in Virginia

In Virginia, retail choice in the selection of a power supplier is available to customers that consume at least 5 MW of  power individually or in the aggregate (with aggregation subject to the approval of the VSCC) and that do not account for more than 1% of the incumbent utility's peak load during the past year.  Currently, no customer of our member distribution cooperatives has elected to choose an alternate supplier under this provision.  Retail choice is also available to any customer whose noncoincident peak demand exceeds 90 MW.  Beginning June 1, 2016, Bear Island, an industrial customer of REC and the only customer of any of our member distribution cooperatives that has noncoincident peak demand that exceeds 90 MW, elected to purchase its power requirements from an alternate supplier.  We do not anticipate that this will have a material impact on our financial condition, results of operations, or cash flows.

North Anna Unit 3

In 2011, we decided not to participate in North Anna Unit 3, finalized our withdrawal as a participant in the project and transferred our interest to Virginia Power.  In 2011, we established a regulatory asset of $22.7 million for our early stage development costs incurred for North Anna Unit 3.  In 2015, we recovered 70% of these costs from Virginia Power and, with our board of directors’ approval, amortized the remaining balance in 2015.  On June 1, 2017, Virginia Power agreed to return the remaining balance of North Anna Unit 3 development costs that we incurred as part of the resolution of other regulatory matters with Virginia Power.  The remaining balance of North Anna Unit 3 development costs, including interest through May 2018, totals $11.6 million.  As of June 30, 2017, we recorded $6.9 million as amortization of regulatory asset/(liability), net, and $4.4 million as interest income on North Anna Unit 3 cost recovery on our Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital.  During the second quarter of 2017, we received a payment of $6.8 million and established a receivable for the remaining balance, which will continue to accrue interest.  Virginia Power agreed to pay the remaining balance in the second quarter of 2018.

New Accounting Pronouncements

In May 2014, the FASB issued Accounting Standards Update 2014-09 Revenue from Contracts with Customers.  This update requires entities to recognize revenue when the transfer of promised goods or services to customers occurs in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  We 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 are in the process of evaluating our wholesale power and other contracts.  We have not identified any material impact to our recognition of revenue from the sale of power to our member distribution cooperatives, but are still completing our review of the wholesale power contracts as well as other contracts.  We plan to adopt this standard for the fiscal year beginning January 1, 2018.

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

 

14


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 June 30, 2017, there have been no significant changes in our critical accounting policies as disclosed in our 2016 Annual Report on Form 10-K.  These policies include the accounting for regulated operations, deferred energy, margin stabilization, accounting for asset retirement and environmental obligations, and accounting for derivatives and hedging.

Basis of Presentation

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

Overview

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

Our results for the three and six months ended June 30, 2017, were primarily impacted by decreases in our total energy rate, changes in our member distribution cooperatives’ requirements for power, the dispatch of our generating facilities, our continued investment in Wildcat Point, and the return of North Anna Unit 3 development costs.  

 

 

In 2016 and 2017, we implemented decreases to our total energy rate that contributed to the 13.7% and 16.8% decrease in the average cost of energy we charged to our member distribution cooperatives, for the three and six months ended June 30, 2017, respectively.  These decreases to our total energy rate also contributed to the $26.2 million decrease in our over-collected deferred energy balance.

 

 

Our energy sales in MWh to our member distribution cooperatives were 5.1% and 8.0% lower for the three and six months ended June 30, 2017, respectively.  We had decreases in our load requirements related to retail choice in Virginia and a limited exception provision in our wholesale power contract.  Additionally, we experienced milder weather during the first three months of 2017.

15


 

Clover generation decreased 36.7% and 44.2% for the three and six months ended June 30, 2017, respectively, due to PJM’s economic dispatch of the facility and reduced operational availability.  Our combustion turbine facilities generation decreased 30.6% for the six months ended June 30, 2017, due to PJM’s economic dispatch of the facilities.  These factors contributed to the $9.8 million, or 32.3%, decrease in fuel expense for the three months ended June 30, 2017, and the $26.4 million, or 40.9%, decrease for the six months ended June 30, 2017.

 

During the three and six months ended June 30, 2017, we capitalized $27.2 million and $59.9 million, respectively, of construction costs related to Wildcat Point.  

 

On June 1, 2017, Virginia Power agreed to return the remaining balance of North Anna Unit 3 development costs that we incurred prior to our 2011 decision not to participate in North Anna Unit 3.  As of June 30, 2017, we recorded $11.3 million comprised of $6.9 million of amortization of regulatory asset/(liability), net, and $4.4 million of interest income on North Anna Unit 3 cost recovery.  During the second quarter of 2017, we received a payment of $6.8 million and established a receivable for the remaining balance.  

Wildcat Point Generation Facility

We are currently constructing, and will be the sole owner of, an approximate 1,000 MW natural gas-fueled combined cycle generation facility, named Wildcat Point, in Cecil County, Maryland.  Wildcat Point's major equipment will consist of two Mitsubishi combustion turbines, two Alstom heat recovery steam generators, and one Alstom steam turbine generator.  While the facility was scheduled to become operational in mid-2017, based upon the most recent information available, we believe that Wildcat Point will achieve substantial completion in the fourth quarter of 2017.  WOPC, the EPC contractor, claims that the delay is 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.  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, and Alstom and we have until August 21, 2017 to respond to the amended complaint.  See “Item 1 – Legal Proceedings.”  We believe that this complaint is without merit and we plan to vigorously defend this claim.  Further, we disagree that we have additional liability under the contract and therefore have not revised our estimated project cost of $834.3 million, before consideration of any liquidated damages which may be due to us as a result of the project delay.  We do not believe that any such delay in the substantial completion of the Wildcat Point facility, or any additional amounts associated with the delay, including PJM capacity delay charges, for which we may be ultimately responsible, are reasonably likely to have a material adverse effect on our results of operations or financial condition due to our ability to collect such amounts through rates charged to our member distribution cooperatives.  Even if we are ultimately responsible for additional costs, any such amounts may be offset in part by liquidated damages under the contract associated with WOPC’s delay in achieving substantial completion.

Through June 30, 2017, we capitalized construction costs related to Wildcat Point totaling $775.8 million, including $59.9 million of capitalized interest, offset by $11.4 million of liquidated damages.

Limited Exception under Wholesale Power Contracts

We have a wholesale power contract with each of our member distribution cooperatives.  Each contract obligates us to sell and deliver to the member distribution cooperative, and obligates the member distribution cooperative to purchase and receive from us, all power that it requires for the operation of its system, with limited exceptions.  One of the limited exceptions permits each of our member distribution cooperatives to receive up to the greater of 5% of its demand and associated energy or 5 MW and associated energy from owned generation or other suppliers.  If all of our member distribution cooperatives elected to utilize the 5% or 5 MW exception, we estimate the current impact would be a reduction of approximately 175 MW of demand and associated energy.  The following table summarizes the removal of load requirements under this exception since January 1, 2016.    

16


Date

 

MW

 

January 1, 2016

 

 

9

 

May 1, 2016

 

 

60

 

June 1, 2017

 

 

65

 

We do not anticipate that utilization of this exception will have a material impact on our financial condition, results of operations, or cash flows.  For further discussion on Wholesale Power Contracts, see “Business—Members—Member Distribution Cooperatives—Wholesale Power Contracts” in Item 1 of our 2016 Annual Report on Form 10-K.  

Retail Choice in Virginia

In Virginia, retail choice in the selection of a power supplier is available to customers that consume at least 5 MW of  power individually or in the aggregate (with aggregation subject to the approval of the VSCC) and that do not account for more than 1% of the incumbent utility's peak load during the past year.  Currently, no customer of our member distribution cooperatives has elected to choose an alternate supplier under this provision.  Retail choice is also available to any customer whose noncoincident peak demand exceeds 90 MW.  Beginning June 1, 2016, Bear Island, an industrial customer of REC and the only customer of any of our member distribution cooperatives that has noncoincident peak demand that exceeds 90 MW, elected to purchase its power requirements from an alternate supplier.  We do not anticipate that this will have a material impact on our financial condition, results of operations, or cash flows.  For further discussion on Retail Choice in Virginia, see “Business—Members—Member Distribution Cooperatives—Competition” in Item 1 of our 2016 Annual Report on Form 10-K.  

Factors Affecting Results

Formula Rate

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

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

 

 

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.  The base energy rate is developed annually to collect energy costs as estimated in our budget including amounts in the deferred energy account from the prior year.  As of January 1 of each year, the base energy rate is reset in accordance with our budget and the energy adjustment rate is reset to zero.  With board approval, we can revise the energy adjustment rate at any time during the year if it becomes apparent that the combined base energy rate and the current energy adjustment rate are over-collecting or under-collecting our actual and anticipated energy costs.  See “FERC Proceeding Related to Formula Rate” in “Legal Proceedings” in Part II, Item 1.

17


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

 

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

As stated above, our margin requirements and additional equity contributions approved by our board of directors are recovered through our demand rates.  We establish our demand rates to produce a net margin attributable to ODEC equal to 20% of our budgeted total interest charges plus additional equity contributions approved by our board of directors.  

 

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

 

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

 

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

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

For the three and six months ended June 30, 2017, we recorded a reduction in operating revenues of $19.0 million and $37.0 million, respectively, utilizing Margin Stabilization, to produce a net margin equal to 20% of our actual total interest charges.  For the three and six months ended June 30, 2016, we recorded an increase in operating revenues of $0.9 million and a reduction in operating revenues of $2.2 million, respectively, utilizing Margin Stabilization, to produce a net margin equal to 20% of our actual total interest charges.  For further discussion of Margin Stabilization, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies—Margin Stabilization” in Item 7 of our 2016 Annual Report on Form 10-K.

18


Weather

Weather affects the demand for electricity.  Relatively higher or lower temperatures tend to increase the demand for energy to use air conditioning and heating systems, respectively.  Mild weather generally reduces the demand because heating and air conditioning systems are operated less.  Weather also plays a role in the price of market energy through its effects on the market price for fuel, particularly natural gas.  Heating and cooling degree days are measurement tools used to quantify the need to utilize heating or cooling, respectively, for a building.  The heating and cooling degree days for the three and six months ended June 30, 2017, were as follows:

 

 

 

Three Months Ended

June 30,

 

 

Six Months Ended

June 30,

 

 

 

2017

 

 

2016

 

 

Change

 

 

2017

 

 

2016

 

 

Change

 

Heating degree days

 

 

5

 

 

 

183

 

 

 

(97.3

)%

 

 

1,637

 

 

 

2,087

 

 

 

(21.6

)%

Cooling degree days

 

 

285

 

 

 

264

 

 

 

8.0

%

 

 

285

 

 

 

264

 

 

 

8.0

%

 

Power Supply Resources

We provide power to our members through a combination of our interests in Clover, a coal-fired generating facility; North Anna, a nuclear power station; our three combustion turbine facilities – Louisa, Marsh Run, and Rock Springs; diesel-fired distributed generation facilities; and physically-delivered forward power purchase contracts and spot market energy purchases.  Our energy supply resources for the three and six months ended June 30, 2017 and 2016, were as follows:

 

 

 

Three Months Ended

June 30,

 

Six Months Ended

June 30,

 

 

 

2017

 

2016

 

2017

 

2016

 

 

 

(in MWh and percentages)

 

(in MWh and percentages)

 

Generated:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Clover

 

405,759

 

15.9

%

641,421

 

23.5

%

758,830

 

13.3

%

1,360,727

 

21.3

%

North Anna

 

490,585

 

19.3

 

462,414

 

17.0

 

976,642

 

17.2

 

895,617

 

14.1

 

Louisa

 

65,201

 

2.6

 

88,559

 

3.2

 

90,129

 

1.6

 

152,779

 

2.4

 

Marsh Run

 

54,974

 

2.1

 

47,951

 

1.8

 

87,186

 

1.5

 

131,853

 

2.1

 

Rock Springs

 

46,286

 

1.8

 

37,554

 

1.4

 

46,286

 

0.8

 

37,570

 

0.6

 

Distributed Generation

 

162

 

 

57

 

 

188

 

 

103

 

 

Total Generated

 

1,062,967

 

41.7

 

1,277,956

 

46.9

 

1,959,261

 

34.4

 

2,578,649

 

40.5

 

Purchased:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other than renewable:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term and short-term

 

975,621

 

38.3

 

1,068,470

 

39.2

 

2,612,270

 

45.9

 

2,999,768

 

47.1

 

Spot market

 

325,369

 

12.8

 

216,738

 

8.0

 

685,699

 

12.1

 

384,446

 

6.0

 

Total Other than renewable

 

1,300,990

 

51.1

 

1,285,208

 

47.2

 

3,297,969

 

58.0

 

3,384,214

 

53.1

 

Renewable (1)

 

182,907

 

7.2

 

161,688

 

5.9

 

432,071

 

7.6

 

409,904

 

6.4

 

Total Purchased

 

1,483,897

 

58.3

 

1,446,896

 

53.1

 

3,730,040

 

65.6

 

3,794,118

 

59.5

 

Total Available Energy

 

2,546,864

 

100.0

%

2,724,852

 

100.0

%

5,689,301

 

100.0

%

6,372,767

 

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.  Typically, nuclear facilities are almost always dispatched and coal-fired and combustion turbine facilities are generally dispatched based upon economic factors, including the market price of energy, and to meet system reliability requirements.  For further discussion on PJM, see “Business—Power Supply Resources—PJM” in Item 1 of our 2016 Annual Report on Form 10-K.  

19


Operational Availability

The operational availability of our owned generating resources for the three and six months ended June 30, 2017 and 2016, was as follows:

 

 

Three Months Ended

June 30,

 

 

Six Months Ended

June 30,

 

 

 

 

2017

 

 

2016

 

 

2017

 

 

2016

 

 

Clover

 

 

67.9

%

 

 

78.9

%

 

 

71.7

%

 

 

84.4

%

 

North Anna

 

 

100.0

 

 

 

94.9

 

 

 

99.6

 

 

 

90.3

 

 

Louisa

 

 

91.0

 

 

 

97.8

 

 

 

95.4

 

 

 

98.5

 

 

Marsh Run

 

 

99.5

 

 

 

93.5

 

 

 

99.5

 

 

 

96.6

 

 

Rock Springs

 

 

98.6

 

 

 

99.0

 

 

 

94.9

 

 

 

93.1

 

 

Capacity Factor

The output of Clover and North Anna, our baseload facilities, for the three and six months ended June 30, 2017 and 2016, as a percentage of maximum dependable capacity rating of the facilities, was as follows:

 

 

 

Three Months Ended

June 30,

 

 

Six Months Ended

June 30,

 

 

 

2017

 

 

2016

 

 

2017

 

 

2016

 

Clover

 

 

43.7

%

 

 

67.9

%

 

 

41.2

%

 

 

72.2

%

North Anna

 

 

102.4

 

 

 

96.5

 

 

 

102.5

 

 

 

92.1

 

Due to outages and economic dispatch by PJM, both units at Clover experienced reduced dispatch during the first six months of 2017.  

Outages

The scheduled and unscheduled outages for Clover and North Anna for the three and six months ended June 30, 2017 and 2016, were as follows:

 

 

 

Clover

 

 

North Anna

 

 

 

Three Months Ended

June 30,

 

 

Six Months Ended

June 30,

 

 

Three Months Ended

June 30,

 

 

Six Months Ended

June 30,

 

 

 

2017

 

 

2016

 

 

2017

 

 

2016

 

 

2017

 

 

2016

 

 

2017

 

 

2016

 

 

 

(in days)

 

 

(in days)

 

 

(in days)

 

 

(in days)

 

Scheduled

 

 

49.6

 

 

 

35.1

 

 

 

77.5

 

 

 

35.1

 

 

 

 

 

 

9.4

 

 

 

 

 

 

35.3

 

Unscheduled

 

 

8.8

 

 

 

3.3

 

 

 

24.7

 

 

 

21.9

 

 

 

 

 

 

 

 

 

1.4

 

 

 

 

Total

 

 

58.4

 

 

 

38.4

 

 

 

102.2

 

 

 

57.0

 

 

 

 

 

 

9.4

 

 

 

1.4

 

 

 

35.3

 

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

Sales to Member Distribution Cooperatives

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

20


Sales to Non-members

Sales to non-members consist of sales of excess purchased and generated energy and sales of renewable energy credits.  We primarily sell excess energy to PJM under its rates for providing energy imbalance service.  Excess energy is the result of changes in our purchased power portfolio, differences between actual and forecasted needs, and changes in market conditions.  Renewable energy credits that are not sold to our member distribution cooperatives are sold to non-members.

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 six months ended June 30, 2017 and 2016, were as follows:

 

 

Three Months Ended

June 30,

 

 

Six Months Ended

June 30,

 

 

 

2017

 

 

2016

 

 

2017

 

 

2016

 

 

 

(in thousands)

 

 

(in thousands)

 

Revenues from sales to:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Member distribution cooperatives

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Energy revenues (1)

 

$

88,339

 

 

$

107,737

 

 

$

197,273

 

 

$

257,709

 

Demand revenues

 

 

64,906

 

 

 

87,860

 

 

 

141,274

 

 

 

181,199

 

Total revenues from sales to member distribution cooperatives

 

 

153,245

 

 

 

195,597

 

 

 

338,547

 

 

 

438,908

 

Non-members (2)

 

 

3,662

 

 

 

3,552

 

 

 

8,139

 

 

 

16,700

 

Total operating revenues

 

$

156,907

 

 

$

199,149

 

 

$

346,686

 

 

$

455,608

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Energy sales to:

 

(in MWh)

 

 

(in MWh)

 

Member distribution cooperatives

 

 

2,446,721

 

 

 

2,576,995

 

 

 

5,463,075

 

 

 

5,940,890

 

Non-members

 

 

91,165

 

 

 

122,958

 

 

 

212,277

 

 

 

379,225

 

Total energy sales

 

 

2,537,886

 

 

 

2,699,953

 

 

 

5,675,352

 

 

 

6,320,115

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

$

36.10

 

 

$

41.81

 

 

$

36.11

 

 

$

43.38

 

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

 

 

26.53

 

 

 

34.09

 

 

 

25.86

 

 

 

30.50

 

Average total cost to member distribution cooperatives (per MWh)

 

$

62.63

 

 

$

75.90

 

 

$

61.97

 

 

$

73.88

 

 

 

(1)

Includes sales of renewable energy credits of $3 thousand and $16 thousand for the three and six months ended June 30, 2017, respectively, and $1.0 million and $1.6 million for the three and six months ended June 30, 2016, respectively.

 

(2)

Includes sales of renewable energy credits of $0.6 million and $1.5 million for the three and six months ended June 30, 2017, respectively, and $0.3 million and $6.7 million for the three and six months ended June 30, 2016, respectively.

Member Distribution Cooperatives

For the three and six months ended June 30, 2017, total revenues from sales to our member distribution cooperatives were 21.7% and 22.9% lower, respectively, as compared to the same periods in 2016, due to the decrease in energy and demand revenues.  Energy revenues decreased $19.4 million, or 18.0%, and $60.4 million, or 23.5%, respectively, for the three and six months ended June 30, 2017, as compared to the same periods in 2016 due to the decrease in the average cost of energy sold to our member distribution cooperatives and the decrease in energy sales in MWh to our member distribution cooperatives.  The average cost of energy sold to our member distribution cooperatives decreased 13.7% and 16.8%, respectively, and the energy sales in MWh to our member distribution cooperatives decreased 5.1% and 8.0%, respectively.  The average cost of energy sold to our member distribution cooperatives was impacted by the rate decreases we implemented in 2016 and 2017 (see table below).  The decrease in the volume of energy sales was primarily a result of the reduction in our load requirements related to retail choice in Virginia and a limited exception provision in our wholesale power contract.  See “Retail Choice in Virginia” and “Limited Exception under Wholesale Power Contracts” above.  These two events resulted in a load reduction of 145,666 MWh and 411,750 MWh, respectively, for the three and six months ended June 30, 2017, as compared to the same periods in 2016.  Additionally, we experienced milder weather in the first three months of 2017.  Demand revenues decreased $23.0 million, or 26.1%, and $39.9 million, or 22.0%,

21


respectively, for the three and six months ended June 30, 2017, as compared to the same periods in 2016 primarily due to decreases in transmission expense and capacity-related purchased power expense, and the recovery of North Anna Unit 3 development costs.

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:

 

Effective Date of Rate Change

 

% Change

 

January 1, 2016

 

 

(5.4

)

April 1, 2016

 

 

(6.8

)

September 1, 2016

 

 

(6.5

)

January 1, 2017

 

 

(6.7

)

Non-members

Revenues from sales to non-members were relatively flat for the three months ended June 30, 2017, as compared to the same period in 2016.  Revenues from sales to non-members for the six months ended June 30, 2017, decreased $8.6 million, or 51.3%, as compared to the same period in 2016, due to a $5.3 million decrease in revenue from sales of renewable energy credits and a $3.3 million decrease in revenue from sales of excess energy.  The decrease in revenue from sales of excess energy for the six months ended June 30, 2017, was primarily due to a 44.0% decrease in volume of excess energy sales.  We primarily sell excess energy to PJM at the prevailing market price at the time of sale.  Excess energy is the result of changes in our purchased power portfolio, differences between actual and forecasted needs, and changes in market conditions.

Operating Expenses

The following is a summary of the components of our operating expenses for the three and six months ended June 30, 2017 and 2016:

 

 

 

Three Months

Ended

June 30,

 

 

Six Months

Ended

June 30,

 

 

 

2017

 

 

2016

 

 

2017

 

 

2016

 

 

 

(in thousands)

 

 

(in thousands)

 

Fuel

 

$

20,498

 

 

$

30,266

 

 

$

38,181

 

 

$

64,588

 

Purchased power

 

 

80,729

 

 

 

80,999

 

 

 

202,845

 

 

 

220,281

 

Transmission

 

 

23,979

 

 

 

30,772

 

 

 

47,721

 

 

 

62,360

 

Deferred energy

 

 

(4,705

)

 

 

8,869

 

 

 

(26,243

)

 

 

10,414

 

Operations and maintenance

 

 

12,099

 

 

 

12,618

 

 

 

24,572

 

 

 

25,177

 

Administrative and general

 

 

11,309

 

 

 

10,156

 

 

 

22,439

 

 

 

20,795

 

Depreciation and amortization

 

 

11,340

 

 

 

11,630

 

 

 

22,683

 

 

 

23,168

 

Amortization of regulatory asset/(liability), net

 

 

(850

)

 

 

646

 

 

 

(20

)

 

 

77

 

Accretion of asset retirement obligations

 

 

1,257

 

 

 

1,211

 

 

 

2,512

 

 

 

2,421

 

Taxes, other than income taxes

 

 

2,087

 

 

 

2,098

 

 

 

4,191

 

 

 

4,219

 

Total Operating Expenses

 

$

157,743

 

 

$

189,265

 

 

$

338,881

 

 

$

433,500

 

 

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.

22


Total operating expenses decreased $31.5 million, or 16.7%, and $94.6 million, or 21.8%, for the three and six months ended June 30, 2017, respectively, as compared to the same periods in 2016.  The decrease for the three and six months ended June 30, 2017, was primarily due to decreases in deferred energy expense, fuel expense, and transmission expense.  For the six months ended June 30, 2017, the decrease was also due to the decrease in purchased power expense.

 

Deferred energy expense decreased $13.6 million and $36.7 million for the three and six months ended June 30, 2017, respectively, as compared to the same periods in 2016.  For the three and six months ended June 30, 2017, we under-collected $4.7 million and $26.2 million, respectively.  For the three and six months ended June 30, 2016, we over-collected $8.9 million and $10.4 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 2016 Annual Report on Form 10-K.

 

Fuel expense decreased $9.8 million, or 32.3%, and $26.4 million, or 40.9%, for the three and six months ended June 30, 2017, respectively, as compared to the same periods in 2016.  Clover generation decreased 36.7% and 44.2%, for the three and six months ended June 30, 2017, respectively, due to reduced operational availability as a result of additional outage days and PJM’s economic dispatch of the facility.  Our combustion turbine facilities generation decreased 30.6%, for the six months ended June 30, 2017, due to PJM’s economic dispatch of the facilities.  

 

Transmission expense decreased $6.8 million, or 22.1%, and $14.6 million, or 23.5%, for the three and six months ended June 30, 2017, as compared to the same periods in 2016, primarily due to decreases in PJM charges for network transmission services.

 

Purchased power expense, which includes the cost of purchased energy and capacity, decreased $17.4 million, or 7.9%, for the six months ended June 30, 2017, as compared to the same period in 2016.  Purchased capacity decreased $10.7 million for the six months ended June 30, 2017, as a result of decreased capacity charges by PJM.  Purchased energy decreased $6.7 million for the six months ended June 30, 2017, due the 1.8% decrease in the average cost of purchased energy and the 1.7% decrease in the volume of purchased energy.  

Other Items

Investment Income

Investment income increased $5.4 million and $6.8 million for the three and six months ended June 30, 2017, respectively, as compared to the same periods in 2016, primarily due to increased earnings on our nuclear decommissioning trust.

Interest Income on North Anna Unit 3 Cost Recovery

In 2011, we decided not to participate in North Anna Unit 3, finalized our withdrawal as a participant in the project and transferred our interest to Virginia Power.  In 2011, we established a regulatory asset of $22.7 million for our early stage development costs incurred for North Anna Unit 3.  In 2015, we recovered 70% of these costs from Virginia Power and, with our board of directors’ approval, amortized the remaining balance in 2015.  On June 1, 2017, Virginia Power agreed to return the remaining balance of North Anna Unit 3 development costs that we incurred as part of the resolution of other regulatory matters with Virginia Power.  The remaining balance of North Anna Unit 3 development costs, including interest through May 2018, totals $11.6 million.  As of June 30, 2017, we recorded $6.9 million as amortization of regulatory asset/(liability), net, and $4.4 million as interest income on North Anna Unit 3 cost recovery on our Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital.  During the second quarter of 2017, we received a payment of $6.8 million and established a receivable for the remaining balance, which will continue to accrue interest.  Virginia Power agreed to pay the remaining balance in the second quarter of 2018.

 

23


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 six months ended June 30, 2017 and 2016, were as follows:

 

 

 

Three Months Ended

June 30,

 

 

Six Months Ended

June 30,

 

 

 

2017

 

 

2016

 

 

2017

 

 

2016

 

 

 

(in thousands)

 

 

(in thousands)

 

Interest on long-term debt

 

$

(13,790

)

 

$

(14,200

)

 

$

(27,572

)

 

$

(28,396

)

Interest on revolving credit facility

 

 

(1,201

)

 

 

(298

)

 

 

(2,080

)

 

 

(529

)

Other interest

 

 

(240

)

 

 

(278

)

 

 

(419

)

 

 

(613

)

Total interest charges

 

 

(15,231

)

 

 

(14,776

)

 

 

(30,071

)

 

 

(29,538

)

Allowance for borrowed funds used during construction

 

 

8,904

 

 

 

7,435

 

 

 

17,500

 

 

 

13,832

 

Interest charges, net

 

$

(6,327

)

 

$

(7,341

)

 

$

(12,571

)

 

$

(15,706

)

Interest charges, net decreased $1.0 million, or 13.8%, and $3.1 million, or 20.0%, for the three and six months ended June 30, 2017, respectively, as compared to the same periods in 2016, due to the increase in allowance for borrowed funds used during construction (capitalized interest) related to Wildcat Point.

Net Margin Attributable to ODEC

Net margin attributable to ODEC, which is a function of our total interest charges plus any additional equity contributions approved by our board of directors, was relatively flat for the three and six months ended June 30, 2017, as compared to the same periods in 2016.

Financial Condition

The principal changes in our financial condition from December 31, 2016 to June 30, 2017, were caused by the increases in revolving credit facility and construction work in progress, and decreases in accounts payable, and deferred energy.

 

Revolving credit facility increased $87.6 million due to outstanding borrowings under this facility, principally to fund construction of Wildcat Point.

 

Construction work in progress increased $73.1 million substantially due to expenditures related to Wildcat Point.

 

Accounts payable decreased $29.5 million primarily due to decreased payables for purchased power and construction.

 

Deferred energy decreased $26.2 million as a result of the under-collection of our energy costs in 2017.  The deferred energy balance was a liability of $13.8 million and $40.0 million as of June 30, 2017 and December 31, 2016, respectively.  

Liquidity and Capital Resources

Sources

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

Operations

During the first six months of 2017 and 2016, our operating activities provided cash flows of $4.6 million and $26.2 million, respectively.  Operating activities in 2017 were primarily impacted by the following:

 

Deferred energy changed $26.2 million due to the under-collection of our energy costs in 2017 as compared to the over-collection of energy costs in 2016; and

24


 

Current liabilities changed $12.6 million primarily due to the change in accounts payable.

Revolving Credit Facility

We maintain a $500.0 million revolving credit facility to cover our short-term and medium-term funding needs that are not met by cash from operations or other available funds.  The syndicated credit agreement associated with the facility was amended and restated on March 3, 2017, and commitments under this agreement extend until March 3, 2022.  As of June 30, 2017, we had outstanding under this facility, $239.6 million in borrowings and $12.2 million in letters of credit.  We utilized the proceeds of our July 6, 2017 debt issuance to repay the borrowings outstanding under this facility as of July 7, 2017.  As of December 31, 2016, we had outstanding under this facility, $152.0 million in borrowings and $5.2 million in letters of credit.

Financings

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

On July 6, 2017, we issued $250.0 million of long-term debt in a private placement transaction.  The issuance consists of $250.0 million of 3.33% First Mortgage Bonds, 2017 Series A due December 1, 2037.  

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.

25


ITEM 3.  QUANTITATIVE AND QUALITATIVE

DISCLOSURES ABOUT MARKET RISK

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

ITEM 4.  CONTROLS AND PROCEDURES

As of the end of the period covered by this report, our management, including the President and Chief Executive Officer, and Senior Vice President and Chief Financial Officer, conducted an evaluation of the effectiveness of our disclosure controls and procedures.  Based upon that evaluation, the President and Chief Executive Officer, and Senior Vice President and Chief Financial Officer concluded that our disclosure controls and procedures are effective in ensuring that all material information required to be filed in this report has been made known to them in a timely matter.  We have established a Disclosure Assessment Committee comprised of members from senior and middle management to assist in this evaluation.  There have been no material changes in our internal controls over financial reporting or in other factors that could significantly affect such controls during the past fiscal quarter.

26


OLD DOMINION ELECTRIC COOPERATIVE

PART II.  OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS

FERC Proceeding Related to Formula Rate

On September 30, 2013, we filed with FERC to revise our cost-based formula rate in order to more closely align our cost recovery from our member distribution cooperatives with the methodologies used by PJM to allocate costs to us.  On November 8, 2013, Bear Island, a customer of REC, filed a motion to intervene, protest, and request for hearing.  On December 2, 2013, FERC issued its order accepting the proposed revisions for filing to become effective January 1, 2014, subject to refund, and establishing hearing and settlement procedures.  On April 13, 2015, we received an initial decision from the hearing judge.  On January 19, 2017, FERC issued its order on the hearing judge's initial decision.  On February 21, 2017, we submitted our compliance filing, revising the formula rate as directed in the order.  Additionally, on February 21, 2017, Bear Island filed a request for rehearing.  On March 22, 2017, FERC issued an order granting rehearing of its initial order for the limited purpose of FERC's further consideration of the matter.  Our formula rate remains in effect subject to refund pending a final order from FERC.  If a refund is ultimately determined, we believe it will result in a reallocation of costs among our member distribution cooperatives.

 

Wildcat Point

Wildcat Point was scheduled to become operational in mid-2017; however, based upon the most recent information available, we believe that Wildcat Point will achieve substantial completion in the fourth quarter of 2017.  WOPC, the EPC contractor, claims that the delay is 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.  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, and Alstom and we have until August 21, 2017 to respond to the amended complaint.  We have reviewed the asserted claims of WOPC and believe they are without merit.  We do not believe any liability is estimable or probable and intend to vigorously defend these claims.  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 2016 Annual Report on Form 10-K, which could affect our business, financial condition or future results.  The risks described in our Annual Report on Form 10-K are not the only risks facing us.  Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.

ITEM 5.  OTHER INFORMATION

Recovery of Costs from PJM

On June 23, 2014, we filed a petition at FERC seeking recovery from PJM of approximately $14.9 million of unreimbursed costs, which were incurred during the first quarter of 2014 related to the dispatch of our combustion turbine generating facilities.  On June 9, 2015, FERC denied our petition, on July 9, 2015, we filed a request for rehearing, and on

27


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

 

 

 

 

28


ITEM 6.  EXHIBITS

 

  31.1

 

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

  31.2

 

Certification of the Chief Financial Officer pursuant to Rule 13a-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

 

29


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: August 9, 2017

 

/s/     Robert L. Kees        

 

 

Robert L. Kees

 

 

Senior Vice President and Chief Financial Officer

 

 

(Principal financial officer)

 

30


EXHIBIT INDEX

 

Exhibit

Number

 

Description of Exhibit

 

 

 

  31.1

 

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

  31.2

 

Certification of the Chief Financial Officer pursuant to Rule 13a-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