10-Q 1 a2015q3930201510-q.htm 10-Q 10-Q
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-Q
 
(Mark One)
ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2015
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  ý
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  ý    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
 
ý
  
Smaller reporting company
 
¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  ý
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
 
 
Alstom
  
Alstom Power, Inc.
Bear Island
  
Bear Island Paper WB LLC
CCR
  
Coal combustion residual
Clover
  
Clover Power Station
CO2
 
Carbon dioxide
CPCN
  
Certificate of Public Convenience and Necessity
EPA
  
Environmental Protection Agency
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.
MPSC
  
Maryland Public Service Commission
MW
  
Megawatt(s)
MWh
  
Megawatt hour(s)
North Anna
  
North Anna Nuclear Power Station
ODEC, We, Our
  
Old Dominion Electric Cooperative
PJM
  
PJM Interconnection, LLC
REC
  
Rappahannock Electric Cooperative
RPM
 
Reliability Pricing Model
RTO
  
Regional transmission organization
TEC
  
TEC Trading, Inc.
Wildcat Point
  
Wildcat Point Generation Facility
XBRL
  
Extensible Business Reporting Language


2

OLD DOMINION ELECTRIC COOPERATIVE
INDEX
 
 
 
 
Page
Number
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


3

OLD DOMINION ELECTRIC COOPERATIVE
PART 1. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CONDENSED CONSOLIDATED BALANCE SHEETS
 
September 30,
2015
 
December 31,
2014
 
(in thousands)
 
(unaudited)
 
 
ASSETS:
 
 
 
Electric Plant:
 
 
 
Property, plant, and equipment
$
1,713,175

 
$
1,690,555

Less accumulated depreciation
(811,942
)
 
(784,215
)
Net Property, plant, and equipment
901,233

 
906,340

Nuclear fuel, at amortized cost
19,222

 
19,376

Construction work in progress
442,316

 
171,953

Net Electric Plant
1,362,771

 
1,097,669

Investments:
 
 
 
Nuclear decommissioning trust
140,692

 
145,822

Lease deposits
101,080

 
99,191

Unrestricted investments and other
7,013

 
7,049

Total Investments
248,785

 
252,062

Current Assets:
 
 
 
Cash and cash equivalents
174,312

 
1,424

Accounts receivable
6,345

 
8,656

Accounts receivable–members
77,713

 
83,108

Fuel, materials, and supplies
60,998

 
64,154

Deferred energy
—

 
19,948

Prepayments and other
37,892

 
5,131

Total Current Assets
357,260

 
182,421

Deferred Charges:
 
 
 
Regulatory assets
84,380

 
87,987

Other
11,224

 
18,603

Total Deferred Charges
95,604

 
106,590

Total Assets
$
2,064,420

 
$
1,638,742

 
 
 
 
CAPITALIZATION AND LIABILITIES:
 
 
 
Capitalization:
 
 
 
Patronage capital
$
387,988

 
$
379,097

Non-controlling interest
5,694

 
5,687

Total Patronage capital and Non-controlling interest
393,682

 
384,784

Long-term debt
1,053,038

 
721,038

Revolving credit facility
—

 
86,000

Total Long-term debt and Revolving credit facility
1,053,038

 
807,038

Total Capitalization
1,446,720

 
1,191,822

Current Liabilities:
 
 
 
Long-term debt due within one year
28,292

 
28,292

Accounts payable
142,896

 
96,702

Accounts payable–members
103,291

 
35,217

Accrued expenses
23,742

 
4,568

Deferred energy
13,227

 
—

Total Current Liabilities
311,448

 
164,779

Deferred Credits and Other Liabilities:
 
 
 
Asset retirement obligations
117,038

 
104,936

Obligations under long-term lease
89,148

 
84,730

Regulatory liabilities
69,918

 
78,764

Other
30,148

 
13,711

Total Deferred Credits and Other Liabilities
306,252

 
282,141

Commitments and Contingencies
—

 
—

Total Capitalization and Liabilities
$
2,064,420

 
$
1,638,742

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,
 
2015
 
2014
 
2015
 
2014
 
(in thousands)
 
(in thousands)
Operating Revenues
$
254,265

 
$
233,904

 
$
795,862

 
$
716,331

Operating Expenses:
 
 
 
 
 
 
 
Fuel
48,717

 
33,667

 
127,945

 
178,294

Purchased power
95,339

 
118,605

 
391,772

 
391,951

Transmission
29,456

 
19,688

 
84,614

 
56,504

Deferred energy
31,481

 
12,704

 
33,175

 
(64,256
)
Operations and maintenance
10,750

 
12,468

 
39,584

 
39,151

Administrative and general
9,702

 
9,000

 
30,193

 
31,453

Depreciation and amortization
11,456

 
10,476

 
33,657

 
31,480

Amortization of regulatory asset/(liability), net
835

 
1,282

 
2,421

 
4,080

Accretion of asset retirement obligations
1,161

 
1,019

 
3,533

 
3,057

Taxes, other than income taxes
2,071

 
1,980

 
6,263

 
6,287

Total Operating Expenses
240,968

 
220,889

 
753,157

 
678,001

Operating Margin
13,297

 
13,015

 
42,705

 
38,330

Other expense, net
(801
)
 
(785
)
 
(2,489
)
 
(2,224
)
Investment income
1,542

 
1,650

 
4,498

 
5,177

Interest charges, net
(11,035
)
 
(11,537
)
 
(35,815
)
 
(34,305
)
Income taxes
1

 
1

 
(1
)
 
2

Net Margin including Non-controlling interest
3,004

 
2,344

 
8,898

 
6,980

Non-controlling interest
1

 
5

 
(7
)
 
9

Net Margin attributable to ODEC
3,005

 
2,349

 
8,891

 
6,989

Patronage Capital - Beginning of Period
384,983

 
374,637

 
379,097

 
369,997

Patronage Capital - End of Period
$
387,988

 
$
376,986

 
$
387,988

 
$
376,986

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,
 
2015
 
2014
 
(in thousands)
Operating Activities:
 
 
 
Net Margin including Non-controlling interest
$
8,898

 
$
6,980

Adjustments to reconcile net margin to net cash provided by operating activities:
 
 
 
Depreciation and amortization
33,657

 
31,480

Other non-cash charges
13,881

 
13,512

Amortization of lease obligations
4,418

 
4,126

Interest on lease deposits
(2,174
)
 
(2,121
)
Change in current assets
(21,899
)
 
(2,562
)
Change in deferred energy
33,175

 
(64,256
)
Change in current liabilities
75,756

 
42,992

Change in regulatory assets and liabilities
3,969

 
336

Change in deferred charges-other and deferred credits and other liabilities-other
6,425

 
(2,643
)
Net Cash Provided by Operating Activities
156,106

 
27,844

Investing Activities:
 
 
 
Purchases of held to maturity securities
(130,000
)
 
(2,240
)
Proceeds from sale of held to maturity securities
130,000

 
20,000

Increase in other investments
(3,769
)
 
(4,409
)
Electric plant additions
(223,695
)
 
(91,921
)
Net Cash Used for Investing Activities
(227,464
)
 
(78,570
)
Financing Activities:
 
 
 
Issuance of long-term debt
332,000

 
—

Debt issuance costs
(1,754
)
 
—

Draws on revolving credit facility
104,000

 
222,954

Repayments on revolving credit facility
(190,000
)
 
(187,954
)
Net Cash Provided by Financing Activities
244,246

 
35,000

Net Change in Cash and Cash Equivalents
172,888

 
(15,726
)
Cash and Cash Equivalents - Beginning of Period
1,424

 
51,669

Cash and Cash Equivalents - End of Period
$
174,312

 
$
35,943

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, 2015, our consolidated results of operations for the three and nine months ended September 30, 2015 and 2014, and cash flows for the nine months ended September 30, 2015 and 2014. The consolidated results of operations for the three and nine months ended September 30, 2015, 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 2014 Annual Report on Form 10-K filed with the Securities and Exchange Commission.
The accompanying financial statements reflect the consolidated accounts of Old Dominion Electric Cooperative and TEC. We are a not-for-profit wholesale power supply cooperative, incorporated under the laws of the Commonwealth of Virginia in 1948. We have two classes of members. Our Class A members are eleven customer-owned electric distribution cooperatives engaged in the retail sale of power to member customers located in Virginia, Delaware, and Maryland. Our sole Class B member is TEC, a taxable corporation owned by our member distribution cooperatives. Our board of directors is composed of two representatives from each of the member distribution cooperatives and one representative from TEC. In accordance with Consolidation Accounting, TEC is considered a variable interest entity for which we are the primary beneficiary. We have eliminated all intercompany balances and transactions in consolidation. The assets and liabilities and non-controlling interest of TEC are recorded at carrying value and the consolidated assets were $5.7 million at September 30, 2015 and December 31, 2014. 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 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.

Transmission expense has been presented as a separate line item in the prior year's condensed consolidated financial statements to conform to the current year's presentation.
 
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, 2015 and December 31, 2014: 
 
September 30, 2015
 
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
(in thousands)
Nuclear decommissioning trust (1)(2)
$
140,692

 
$
46,103

 
$
94,589

 
$
—

Unrestricted investments and other (3)
202

 
—

 
202

 
—

Total Financial Assets
$
140,894

 
$
46,103

 
$
94,791

 
$
—

 
 
 
 
 
 
 
 
Derivatives - gas and power (4)
$
2,490

 
$
2,490

 
$
—

 
$
—

Total Financial Liabilities
$
2,490

 
$
2,490

 
$
—

 
$
—

 
 
December 31, 2014
 
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
(in thousands)
Nuclear decommissioning trust (1)(2)
$
145,822

 
$
45,573

 
$
100,249

 
$
—

Unrestricted investments and other (3)
198

 
—

 
198

 
—

Total Financial Assets
$
146,020

 
$
45,573

 
$
100,447

 
$
—

 
 
 
 
 
 
 
 
Derivatives - gas and power (4)
$
5,215

 
$
5,215

 
$
—

 
$
—

Total Financial Liabilities
$
5,215

 
$
5,215

 
$
—

 
$
—

 
(1) 
For additional information about our nuclear decommissioning trust see Note 4 below.
(2) 
Nuclear decommissioning trust includes investments that are available for sale and classified as Level 2. These Level 2 assets consist of an equity fund that attempts to replicate the return of the S&P 500, an equity fund that invests in small capitalization stocks, and an equity fund that invests in international stocks. The fair values of the investments in the nuclear decommissioning trust have been estimated using the net asset value per share.
(3) 
Unrestricted investments and other includes investments that are related to equity securities.
(4) 
Derivatives - gas and power represent natural gas futures contracts which are recorded on our Condensed Consolidated Balance Sheet in deferred credits and other liabilities-other, and which are indexed against NYMEX. For additional information about our derivative financial instruments, see Note 1 of the Notes to Consolidated Financial Statements in our 2014 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 2014 Annual Report on Form 10-K.

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


8

Excluding contracts accounted for as normal purchase/normal sale, we had the following outstanding derivative instruments:
 
 
 
 
 
As of
 
As of
 
 
 
 
September 30, 2015
 
December 31, 2014
Commodity
 
Unit of Measure
 
Quantity
 
Quantity
Natural gas
 
MMBTU
 
5,130,000

 
5,610,000


The fair value of our derivative instruments, excluding contracts accounted for as normal purchase/normal sale, was as follows:
 
Balance Sheet Location
 
Fair Value
 
As of September 30, 2015
 
As of December 31, 2014
 
 
 
(in thousands)
Derivatives in a liability position:
 
 
 
 
 
Natural gas futures contracts
Deferred credits and other liabilities-other
 
$
2,490

 
$
5,215

Total derivatives in a liability position
 
 
$
2,490

 
$
5,215

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, 2015 and 2014
 
Derivatives Accounted for Utilizing Regulatory Accounting
 
Amount of Gain (Loss) Recognized in Regulatory Asset/Liability for Derivatives as of September 30,
 
Location of
Gain (Loss)
Reclassified
from Regulatory
Asset/Liability
into Income
 
Amount of Gain (Loss) Reclassified from Regulatory Asset/Liability into Income for the Three Months Ended September 30,
 
Amount of Gain (Loss) Reclassified from Regulatory Asset/Liability into Income for the Nine Months Ended September 30,
 
 
2015
 
2014
 
 
 
2015
 
2014
 
2015
 
2014
 
 
(in thousands)
 
 
 
(in thousands)
 
(in thousands)
Natural gas futures contracts (1)
 
$
(2,530
)
 
$
(135
)
 
Fuel
 
$
(4,079
)
 
$
(1,081
)
 
$
(5,737
)
 
$
(746
)
Purchased power contracts
 
—

 
—

 
Purchased power
 
—

 
—

 
(14
)
 
—

Purchased power contracts - excess sales
 
—

 
(115
)
 
Operating revenues
 
—

 
—

 
—

 
—

Total
 
$
(2,530
)
 
$
(250
)
 
     Total
 
$
(4,079
)
 
$
(1,081
)
 
$
(5,751
)
 
$
(746
)

(1)  
Includes $39.4 thousand of loss on NYMEX contracts designated for October 2015 that were physically sold in September 2015 and the impact on the Statement of Financial Position has been deferred until October 2015.

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.

9



4.
Investments
Investments were as follows at September 30, 2015 and December 31, 2014:
Description
 
Designation
 
Cost
 
Gross
Unrealized
Gains
 
Gross
Unrealized
Losses
 
Fair
Value
 
Carrying
Value
 
 
 
 
(in thousands)
September 30, 2015
 
 
 
 
 
 
 
 
 
 
 
 
Nuclear decommissioning trust (1)
 
 
 
 
 
 
 
 
 
 
 
 
Debt securities
 
Available for sale
 
$
42,565

 
$
3,250

 
$
—

 
$
45,815

 
$
45,815

Equity securities
 
Available for sale
 
71,541

 
23,048

 
—

 
94,589

 
94,589

Cash and other
 
Available for sale
 
288

 
—

 
—

 
288

 
288

Total Nuclear Decommissioning Trust
 
 
 
$
114,394

 
$
26,298

 
$
—

 
$
140,692

 
$
140,692

 
 
 
 
 
 
 
 
 
 
 
 
 
Lease Deposits (2)
 
 
 
 
 
 
 
 
 
 
 
 
Government obligations
 
Held to maturity
 
$
101,080

 
$
5,731

 
$
—

 
$
106,811

 
$
101,080

Total Lease Deposits
 
 
 
$
101,080

 
$
5,731

 
$
—

 
$
106,811

 
$
101,080

 
 
 
 
 
 
 
 
 
 
 
 
 
Unrestricted investments
 
 
 
 
 
 
 
 
 
 
 
 
Government obligations
 
Held to maturity
 
$
2,004

 
$
7

 
$
—

 
$
2,011

 
$
2,004

Debt securities
 
Held to maturity
 
2,636

 
2

 
—

 
2,638

 
2,636

Total Unrestricted Investments
 
 
 
$
4,640

 
$
9

 
$
—

 
$
4,649

 
$
4,640

 
 
 
 
 
 
 
 
 
 
 
 
 
Other
 
 
 
 
 
 
 
 
 
 
 
 
Equity securities
 
Trading
 
$
167

 
$
35

 
$
—

 
$
202

 
$
202

Non-marketable equity investments
 
Equity
 
2,171

 
1,954

 
—

 
4,125

 
2,171

Total Other
 
 
 
$
2,338

 
$
1,989

 
$
—

 
$
4,327

 
$
2,373

 
 
 
 
 
 
 
 
 
 
 
 
$
248,785

December 31, 2014
 
 
 
 
 
 
 
 
 
 
 
 
Nuclear decommissioning trust (1)
 
 
 
 
 
 
 
 
 
 
 
 
Debt securities
 
Available for sale
 
$
41,654

 
$
3,516

 
$
—

 
$
45,170

 
$
45,170

Equity securities
 
Available for sale
 
68,259

 
31,990

 
—

 
100,249

 
100,249

Cash and other
 
Available for sale
 
403

 
—

 
—

 
403

 
403

Total Nuclear Decommissioning Trust
 
 
 
$
110,316

 
$
35,506

 
$
—

 
$
145,822

 
$
145,822

 
 
 
 
 
 
 
 
 
 
 
 
 
Lease Deposits (2)
 
 
 
 
 
 
 
 
 
 
 
 
Government obligations
 
Held to maturity
 
$
99,191

 
$
5,569

 
$
—

 
$
104,760

 
$
99,191

Total Lease Deposits
 
 
 
$
99,191

 
$
5,569

 
$
—

 
$
104,760

 
$
99,191

 
 
 
 
 
 
 
 
 
 
 
 
 
Unrestricted investments
 
 
 
 
 
 
 
 
 
 
 
 
Government obligations
 
Held to maturity
 
$
2,005

 
$
—

 
$
—

 
$
2,005

 
$
2,005

Debt securities
 
Held to maturity
 
2,636

 
—

 
(18
)
 
2,618

 
2,636

Total Unrestricted Investments
 
 
 
$
4,641

 
$
—

 
$
(18
)
 
$
4,623

 
$
4,641

 
 
 
 
 
 
 
 
 
 
 
 
 
Other
 
 
 
 
 
 
 
 
 
 
 
 
Equity securities
 
Trading
 
$
151

 
$
47

 
$
—

 
$
198

 
$
198

Non-marketable equity investments
 
Equity
 
2,210

 
1,821

 
—

 
4,031

 
2,210

Total Other
 
 
 
$
2,361

 
$
1,868

 
$
—

 
$
4,229

 
$
2,408

 
 
 
 
 
 
 
 
 
 
 
 
$
252,062


10

 
(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 2014 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.
(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 2014 Annual Report on Form 10-K.

Our investments by classification at September 30, 2015 and December 31, 2014, were as follows:
 
September 30, 2015
 
December 31, 2014
Description
Cost
 
Carrying
Value
 
Cost
 
Carrying
Value
 
(in thousands)
Available for sale
$
114,394

 
$
140,692

 
$
110,316

 
$
145,822

Held to maturity
105,720

 
105,720

 
103,832

 
103,832

Equity
2,171

 
2,171

 
2,210

 
2,210

Trading
167

 
202

 
151

 
198

 
$
222,452

 
$
248,785

 
$
216,509

 
$
252,062

Contractual maturities of debt securities at September 30, 2015, were as follows:
Description
Less than
1 year
 
1-5 years
 
5-10 years
 
More than
10 years
 
Total
 
(in thousands)
Available for sale (1)
$
—

 
$
—

 
$
45,815

 
$
—

 
$
45,815

Held to maturity
517

 
105,203

 
—

 
—

 
105,720

 
$
517

 
$
105,203

 
$
45,815

 
$
—

 
$
151,535

 
(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 generation facility, named Wildcat Point, in Cecil County, Maryland. The development, construction, and operation of Wildcat Point are subject to obtainment of necessary governmental and regulatory approvals. On April 8, 2014, we received a Final Order granting approval of the CPCN from the MPSC. On June 2, 2014, we selected White Oak Power Constructors as the EPC contractor. Site preparation and engineering activities are in process, and permanent construction began in January 2015. The facility is scheduled to become operational in mid-2017. We currently have a ground lease related to land and land rights associated with Wildcat Point that is being accounted for as an operating lease. On June 22, 2015, we reached an agreement to purchase this land and these land rights from Essential Power, LLC for $40.0 million and a payment of $35.5 million was made in the third quarter and is recorded in prepayments and other. We anticipate the transaction will close in the fourth quarter of 2015. Upon closing of the transaction, title will be transferred to us and we will make the remaining payment of $4.5 million. Prior to entering into the agreement to purchase the land and land rights, thus terminating the ground lease, we made prepaid rent payments related to the ground lease. We established a regulatory asset for the unamortized portion of the prepaid rent that will be amortized through May 31, 2017. The balance of this regulatory asset as of September 30, 2015, was $3.5 million. As a result of the agreement to purchase the land and land rights, we currently anticipate that the project cost will be approximately $834.3 million, including financing costs. To fund a portion of the project cost, on January 15, 2015, we issued $332.0 million of first mortgage bonds in a private placement transaction.

Wildcat Point will consist of two Mitsubishi combustion turbines, two Alstom heat recovery steam generators, and one Alstom steam turbine generator. Beginning in June 2014, following the approval of the CPCN and our selection of the EPC contractor, we began capitalizing all construction-related costs related to Wildcat Point. Through December 31, 2014, we capitalized construction costs related to Wildcat Point totaling $115.8 million, which are recorded in construction work in progress. In January 2015, we began capitalizing interest with respect to the facility upon commencement of permanent construction. Through September 30, 2015, we capitalized construction costs related to Wildcat Point totaling $390.8 million, including $7.6 million of capitalized interest.

11

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. A hearing was held in December 2014, briefs were filed in January 2015, and we received an initial decision from the hearing judge on April 13, 2015. The hearing judge found many components of the formula rate to be just and reasonable. We believe all components of the formula rate are just and reasonable and addressed the components the hearing judge found to be unjust and unreasonable in our brief on exceptions. Briefs on exceptions to the initial decision and briefs opposing exceptions to the initial decision were filed on May 13, 2015, and June 2, 2015, respectively. The FERC commissioners have the ultimate authority in this proceeding and they have no timetable to issue a final order. 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. The results of FERC's further consideration of the matter cannot currently be determined and we have not recorded a receivable related to this matter.

Revolving Credit Facility
We currently maintain a $500.0 million revolving credit facility to cover our short-term and medium-term funding needs. Commitments under this syndicated credit agreement extend until March 5, 2019. At September 30, 2015, we did not have any borrowings outstanding under this facility, as compared to December 31, 2014, when we had $86.0 million outstanding. At September 30, 2015, and December 31, 2014, we had letters of credit outstanding in the amount of $8.2 million and $10.0 million, respectively.

Long-term Debt

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

Disposal of Coal Combustion Residual

In December 2014, the EPA issued the final rule regulating the disposal of CCRs, commonly known as coal ash. The rule establishes technical requirements for CCR landfills and surface impoundments under Subtitle D of the Resource Conservation and Recovery Act. The final rule was published in the Federal Register in April 2015 and, as a result, we established asset retirement obligations totaling $8.6 million during the second quarter of 2015.

New Accounting Pronouncements

In April 2015, the FASB issued Accounting Standards Update 2015-03 Interest-Imputation of Interest (Subtopic 835-30). This update requires that debt issuance costs related to a recognized debt liability be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. We currently present debt issuance costs as an asset in deferred charges-other on our Condensed Consolidated Balance Sheet. We plan to adopt this standard for the fiscal year beginning January 1, 2016.

In May 2015, the FASB issued Accounting Standards Update 2015-07 Fair Value Measurement (Topic 820). This update affects the presentation of investments for which fair value is measured at net asset value per share (or its equivalent). We are currently evaluating the impact of this pronouncement on the presentation of the fair value of our nuclear decommissioning trust. We plan to adopt this standard for the fiscal year beginning January 1, 2016.





12

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, 2015, there have been no significant changes in our critical accounting policies as disclosed in our 2014 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, 2015, were primarily impacted by the continuing effects from the unusually cold weather in the first quarter of 2014, and the construction of Wildcat Point.

•
The unusually cold weather experienced in the entire mid-Atlantic region during the first quarter of 2014 continued to impact our operating results through the third quarter of 2015, and year over year comparisons. Increased costs in the first quarter of 2014, particularly fuel expense for our combustion turbine facilities, resulted in the under-collection of our energy costs, and an under-collected deferred energy balance of $56.2 million at March 31, 2014. To address the under-collection of costs, we increased our energy rates during 2014. At September 30, 2015, our deferred energy balance was an over-collection of $13.2 million.

•
We continue with the construction of Wildcat Point (see “Wildcat Point Generation Facility” below). Through September 30, 2015, we capitalized construction costs totaling $390.8 million. To fund a portion of the Wildcat Point project cost, on January 15, 2015, we issued $332.0 million of long-term debt, and used a portion of the proceeds to repay borrowings outstanding under our revolving credit facility.

Wildcat Point Generation Facility
We are currently constructing, and will be the sole owner of, an approximate 1,000 MW natural gas-fueled generation facility, named Wildcat Point, in Cecil County, Maryland. The development, construction, and operation of Wildcat Point are subject to obtainment of necessary governmental and regulatory approvals. On April 8, 2014, we received a Final Order granting approval of the CPCN from the MPSC. On June 2, 2014, we selected White Oak Power Constructors as the EPC contractor. Site preparation and engineering activities are in process, and permanent construction began in January 2015. The facility is scheduled to become operational in mid-2017. We currently have a ground lease related to land and land rights associated with Wildcat Point that is being accounted for as an operating lease. On June 22, 2015, we reached an agreement to purchase this land and these land rights from Essential Power, LLC for $40.0 million and a payment of $35.5 million was made in the third quarter and is recorded in

13

prepayments and other. We anticipate the transaction will close in the fourth quarter of 2015. Upon closing of the transaction, title will be transferred to us and we will make the remaining payment of $4.5 million. Prior to entering into the agreement to purchase the land and land rights, thus terminating the ground lease, we made prepaid rent payments related to the ground lease. We established a regulatory asset for the unamortized portion of the prepaid rent that will be amortized through May 31, 2017. The balance of this regulatory asset as of September 30, 2015, was $3.5 million. As a result of the agreement to purchase the land and land rights, we currently anticipate that the project cost will be approximately $834.3 million, including financing costs. To fund a portion of the project cost, on January 15, 2015, we issued $332.0 million of first mortgage bonds in a private placement transaction.

Wildcat Point will consist of two Mitsubishi combustion turbines, two Alstom heat recovery steam generators, and one Alstom steam turbine generator. Beginning in June 2014, following the approval of the CPCN and our selection of the EPC contractor, we began capitalizing all construction-related costs related to Wildcat Point. Through December 31, 2014, we capitalized construction costs related to Wildcat Point totaling $115.8, which are recorded in construction work in progress. In January 2015, we began capitalizing interest with respect to the facility upon commencement of permanent construction. Through September 30, 2015, we capitalized construction costs related to Wildcat Point totaling $390.8 million, including $7.6 million of capitalized interest.
Wholesale Power Contracts
We have wholesale power contracts 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 the member distribution cooperatives to receive up to the greater of 5.0% of their power requirements or 5 MW from owned generation or other suppliers, and to purchase additional power from other suppliers in limited circumstances following approval by our board of directors. Currently, our member distribution cooperatives collectively receive approximately 9 MW under this exception. Beginning in the second quarter of 2016, we currently anticipate that our member distribution cooperatives will collectively receive approximately 60 MW under this exception. 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 Wholesale Power Contracts, see “Business-Members-Member Distribution Cooperatives-Wholesale Power Contracts” in Item 1 of our 2014 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. Effective January 1, 2014, pursuant to FERC’s acceptance of revisions to the formula rate as issued in FERC’s December 2, 2013 order, the base energy rate is no longer a fixed rate that requires FERC approval prior to adjustment. The base energy rate now is developed annually to collect energy costs as estimated in our budget including amounts in the deferred energy account from the prior year. As of January 1 of each year, the energy adjustment rate will be zero. With board approval, we can revise the energy adjustment rate at any time during the year if it becomes apparent that the combined base energy rate and the current energy adjustment rate are over-collecting or under-collecting our actual and anticipated energy costs. See “FERC Proceeding Related to Formula Rate” in “Legal Proceedings” in Part II, Item 1.

14

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. Effective January 1, 2014, pursuant to FERC’s acceptance of the revisions to the formula rate as issued in FERC’s December 2, 2013 order, we now collect our total demand costs through the following three separate rates:
•
Transmission service rate – designed to collect transmission-related and distribution-related costs;

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

•
Remaining owned capacity service rate – recovers all remaining demand costs not billed and/or recovered under the transmission service and RTO capacity service rates.
As stated above, our margin requirements and additional equity contributions approved by our board of directors are recovered through our demand rates. We establish our demand rates to produce a net margin attributable to ODEC equal to 20% of our budgeted total interest charges plus additional equity contributions approved by our board of directors. Effective January 1, 2014:
•
At year end, if the actual net margin attributable to ODEC, excluding any budgeted additional equity contributions, equals more than 20% of our actual total interest charges, our board of directors may approve that, utilizing Margin Stabilization, revenues will be reduced by the amount of such excess margins, or that such excess margins will be retained as an additional equity contribution. For year-to-date interim reporting, if the actual net margin attributable to ODEC, excluding any budgeted additional equity contributions, equals more than 20% of our actual total interest charges, utilizing Margin Stabilization, revenues will be reduced by the amount of such excess margins.

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

•
At year end and for year-to-date interim reporting, if the actual net margin attributable to ODEC, excluding any budgeted additional equity contributions, equals less than 10% of our actual total interest charges, utilizing Margin Stabilization, revenues will be increased to produce a net margin attributable to ODEC, excluding any budgeted additional equity contributions, equal to 10% of our actual total interest charges.
For the three and nine months ended September 30, 2015, we recorded a reduction in operating revenues of $3.0 million, and $9.8 million, respectively, utilizing Margin Stabilization, to produce a net margin equal to 20% of our actual total interest charges. For the three and nine months ended September 30, 2014, we recorded a reduction in operating revenues of $40.1 thousand and $1.9 million, respectively, utilizing Margin Stabilization, to produce a net margin equal to 20% of our actual total interest charges.
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 nine months ended September 30, 2015 and 2014, were as follows:
 
Three Months Ended September 30,
 
%
 
Nine Months Ended September 30,
 
%
 
2015
 
2014
 
Change
 
2015
 
2014
 
Change
Heating degree days
—

 
—

 
—
 
2,708

 
2,607

 
3.9
Cooling degree days
916

 
744

 
23.1
 
1,369

 
1,064

 
28.7


15

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; 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, 2015 and 2014, were as follows:
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
2015
 
2014
 
(in MWh and percentages)
 
(in MWh and percentages)
Generated:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Clover
787,914

 
22.3
%
 
685,719

 
21.0
%
 
2,001,019

 
18.4
%
 
1,996,626

 
19.8
%
North Anna
487,545

 
13.8

 
423,734

 
13.0

 
1,387,335

 
12.8

 
1,399,014

 
13.8

Louisa
139,207

 
4.0

 
34,504

 
1.1

 
293,242

 
2.7

 
181,041

 
1.8

Marsh Run
276,357

 
7.8

 
93,499

 
2.8

 
603,772

 
5.6

 
342,820

 
3.4

Rock Springs
187,952

 
5.3

 
23,399

 
0.7

 
295,958

 
2.7

 
73,521

 
0.7

Distributed Generation
752

 
—

 
176

 
—

 
1,306

 
—

 
2,168

 
—

Total Generated
1,879,727

 
53.2

 
1,261,031

 
38.6

 
4,582,632

 
42.2

 
3,995,190

 
39.5

Purchased:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other than renewable:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term and short-term
1,380,504

 
39.0

 
1,620,616

 
49.6

 
5,218,070

 
48.1

 
4,710,558

 
46.6

Spot market
173,070

 
4.9

 
259,684

 
7.9

 
534,096

 
4.9

 
872,854

 
8.6

Total Other than renewable
1,553,574

 
43.9

 
1,880,300

 
57.5

 
5,752,166

 
53.0

 
5,583,412

 
55.2

Renewable (1)
101,649

 
2.9

 
127,748

 
3.9

 
519,340

 
4.8

 
538,059

 
5.3

Total Purchased
1,655,223

 
46.8

 
2,008,048

 
61.4

 
6,271,506

 
57.8

 
6,121,471

 
60.5

Total Available Energy
3,534,950

 
100.0
%
 
3,269,079

 
100.0
%
 
10,854,138

 
100.0
%
 
10,116,661

 
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 baseload generating facilities, Clover and North Anna. Baseload generating facilities, particularly nuclear power plants such as North Anna, generally have relatively high fixed costs. Nuclear facilities operate with relatively low variable costs due to lower fuel costs and technological efficiencies. In addition, coal-fired facilities have relatively low variable costs, as compared to combustion turbine facilities such as Louisa, Marsh Run, and Rock Springs. Our combustion turbine facilities have relatively low fixed costs and greater operational flexibility; however, they are more expensive to operate and, as a result, are dispatched only when the market price of energy makes their operation economical or when their operation is required by PJM to meet system reliability requirements.
Our generating facilities are under dispatch control of PJM. For further discussion on PJM, see “Business—Power Supply Resources—PJM” in Item 1 of our 2014 Annual Report on Form 10-K. 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.

16

The operational availability of our owned generating resources for the three and nine months ended September 30, 2015 and 2014, was as follows:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
Clover
95.6
%
 
92.6
%
 
82.1
%
 
83.8
%
North Anna
100.0

 
87.0

 
95.3

 
95.4

Louisa
98.3

 
100.0

 
97.5

 
97.5

Marsh Run
99.7

 
100.0

 
97.3

 
98.8

Rock Springs
77.3

 
99.4

 
91.5

 
97.6

The output of Clover and North Anna for the three and nine months ended September 30, 2015 and 2014, as a percentage of maximum dependable capacity rating of the facilities, was as follows:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
Clover
82.3
%
 
72.0
%
 
70.7
%
 
70.5
%
North Anna
100.6

 
87.4

 
96.5

 
97.4

The scheduled and unscheduled outages for Clover and North Anna for the three and nine months ended September 30, 2015 and 2014, 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,
 
2015
 
2014
 
2015
 
2014
 
2015
 
2014
 
2015
 
2014
 
(in days)
 
(in days)
Scheduled
5.0

 
6.5

 
85.3

 
72.1

 
—

 
24.0

 
20.5

 
24.0

Unscheduled
3.1

 
7.2

 
12.4

 
16.5

 
—

 
—

 
5.3

 
1.3

Total
8.1

 
13.7

 
97.7

 
88.6

 
—

 
24.0

 
25.8

 
25.3


Sales to Member Distribution Cooperatives
Revenues from sales to our member distribution cooperatives are a function of our formula rate for sales of power and sales of renewable energy credits to our member distribution cooperatives, and our member distribution cooperatives’ customers’ requirements for power. Our formula rate is based on our cost of service in meeting these requirements. See “Factors Affecting Results—Formula Rate” above.
Sales to TEC
In accordance with Consolidation Accounting, TEC is considered a variable interest entity for which ODEC is the primary beneficiary. The financial statements of TEC are consolidated and the intercompany balances are eliminated in consolidation. TEC’s sales to third parties are reflected as non-member revenues; however, in 2015 and 2014, TEC had no sales to third parties.
Sales to Non-members
Sales to non-members consist of sales of excess purchased and generated energy and sales of renewable energy credits. We primarily sell excess energy to PJM at the prevailing market price at the time of sale. Excess energy is the result of changes in our purchased power portfolio, differences between actual and forecasted needs, and changes in market conditions. Renewable energy credits that are not sold to our member distribution cooperatives are sold to non-members.



17

Results of Operations
Operating Revenues
Our operating revenues are derived from sales of power and renewable energy credits to our member distribution cooperatives and non-members. Our operating revenues by type of purchaser for the three and nine months ended September 30, 2015 and 2014, were as follows:
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands)
 
(in thousands)
Revenues from sales to:
 
 
 
Member distribution cooperatives
 
 
 
 
 
 
 
Energy revenues (1)
$
153,850

 
$
147,770

 
$
479,680

 
$
436,414

Demand revenues
89,773

 
80,837

 
275,233

 
243,284

Total revenues from sales to member distribution cooperatives
243,623

 
228,607

 
754,913

 
679,698

Non-members (2)
10,642

 
5,297

 
40,949

 
36,633

Total operating revenues
$
254,265

 
$
233,904

 
$
795,862

 
$
716,331

 
 
 
 
 
 
 
 
Average cost of energy to member distribution cooperatives (per MWh)
$
47.19

 
$
47.61

 
$
48.11

 
$
45.43

Average cost of demand to member distribution cooperatives (per MWh)
27.54

 
26.04

 
27.61

 
25.32

Average total cost to member distribution cooperatives (per MWh)
$
74.73

 
$
73.65

 
$
75.72

 
$
70.75

 
(1) 
Includes sales of renewable energy credits of $0.8 million and $2.2 million, for the three and nine months ended September 30, 2015, respectively, and $0.8 million and $1.3 million for the three and nine months ended September 30, 2014, respectively.
(2) 
Includes sales of renewable energy credits of $1.0 million and $8.5 million for the three and nine months ended September 30, 2015, respectively, and $0 million and $3.7 million for the three and nine months ended September 30, 2014, respectively.
Our energy sales in MWh to our member distribution cooperatives and non-members for the three and nine months ended September 30, 2015 and 2014, were as follows:
 
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
2015
 
2014
 
(in MWh)
 
(in MWh)
Energy sales to:
 
 
 
 
 
 
 
Member distribution cooperatives
3,259,985

 
3,103,902

 
9,969,176

 
9,607,339

Non-members
263,586

 
153,614

 
838,142

 
449,010

Total energy sales
3,523,571

 
3,257,516

 
10,807,318

 
10,056,349

Our energy sales in MWh to our member distribution cooperatives for the three and nine months ended September 30, 2015, were 5.0% and 3.8% higher, respectively, as compared to the same periods in 2014.
Our energy sales in MWh to non-members for the three and nine months ended September 30, 2015, were 71.6% and 86.7% higher, respectively, as compared to the same periods in 2014 as the result of the increase in the volume of excess purchased and generated energy.
Total revenues from sales to our member distribution cooperatives for the three months ended September 30, 2015, increased $15.0 million, or 6.6%, as compared to the same period in 2014, substantially due to the $8.9 million, or 11.1%, increase in demand revenues, primarily due to increased transmission expenses. Additionally, energy revenues increased $6.1 million, or 4.1%, due to the 5.0% increase in the volume of MWh sales to our member distribution cooperatives. Total revenues from sales to our member distribution cooperatives for the nine months ended September 30, 2015, increased $75.2 million, or 11.1%, as compared to the same period in 2014, substantially due to the $43.3 million, or 9.9%, increase in energy revenues. The increase in energy revenues is due to the 5.9% increase in the average cost of energy sold to our member distribution cooperatives and the 3.8% increase in the volume of MWh sales. Additionally, demand revenues increased $31.9 million, or 13.1%, primarily due to increased transmission expenses.


18

The average total cost to member distribution cooperatives is affected by changes in our revenues as well as sales volumes. Our average total cost to member distribution cooperatives per MWh for the three months ended September 30, 2015, was 1.5% higher, as compared to the same period in 2014, substantially as a result of an increase in demand costs primarily related to transmission expense. Our average total cost to member distribution cooperatives per MWh for the nine months ended September 30, 2015, was 7.0% higher, as compared to the same period in 2014, substantially as a result of the net increase in our total energy rate and an increase in demand costs primarily related to transmission expense.
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

April 1, 2014
11.8

October 1, 2014
2.4

January 1, 2015
(0.3
)
July 1, 2015
(2.9
)
Non-member revenue for the three months ended September 30, 2015, increased $5.3 million, or 100.9%, as compared to the same period in 2014, primarily due to a 81.8% increase in revenue from sales of excess energy. The increase in revenue from sales of excess energy was due to a 71.6% increase in the volume of excess energy sales and a 5.9% increase in the average price of excess energy. Non-member revenue for the nine months ended September 30, 2015, increased $4.3 million, or 11.8%, as compared to the same period in 2014, due to the 130.0% increase in revenue from sales of renewable energy credits. We primarily sell excess energy to PJM at the prevailing market price at the time of sale. Excess energy is the result of changes in our purchased power portfolio, differences between actual and forecasted needs, and changes in market conditions.
Operating Expenses
The following is a summary of the components of our operating expenses for the three and nine months ended September 30, 2015 and 2014:
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands)
 
(in thousands)
Fuel
$
48,717

 
$
33,667

 
$
127,945

 
$
178,294

Purchased power
95,339

 
118,605

 
391,772

 
391,951

Transmission
29,456

 
19,688

 
84,614

 
56,504

Deferred energy
31,481

 
12,704

 
33,175

 
(64,256
)
Operations and maintenance
10,750

 
12,468

 
39,584

 
39,151

Administrative and general
9,702

 
9,000

 
30,193

 
31,453

Depreciation and amortization
11,456

 
10,476

 
33,657

 
31,480

Amortization of regulatory asset/(liability), net
835

 
1,282

 
2,421

 
4,080

Accretion of asset retirement obligations
1,161

 
1,019

 
3,533

 
3,057

Taxes, other than income taxes
2,071

 
1,980

 
6,263

 
6,287

Total Operating Expenses
$
240,968

 
$
220,889

 
$
753,157

 
$
678,001

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 $20.1 million, or 9.1%, and $75.2 million, or 11.1%, for the three and nine months ended September 30, 2015, respectively, as compared to the same periods in 2014. The increase for the three months ended September 30, 2015, was primarily due to increases in deferred energy expense, fuel expense, and transmission expense, partially offset by the decrease in purchased power expense. The increase for the nine months ended September 30, 2015, was primarily due to increases in deferred energy expense and transmission expense, partially offset by the decrease in fuel expense.
 

19

•
Deferred energy expense increased $18.8 million and $97.4 million for the three and nine months ended September 30, 2015, respectively, as compared to the same periods in 2014. For the three months ended September 30, 2015 and 2014, we over-collected $31.5 million and $12.7 million, respectively. For nine months ended September 30, 2015, we over-collected $33.2 million whereas for the nine months ended September 30, 2014, we under-collected $64.3 million. 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 2014 Annual Report on Form 10-K.

•
Transmission expense increased $9.8 million, or 49.6%, and $28.1 million, or 49.7%, for the three and nine months ended September 30, 2015, respectively, as compared to the same periods in 2014, primarily due to an increase in PJM charges for network transmission services.

•
Fuel expense increased $15.1 million, or 44.7%, for the three months ended September 30, 2015, as compared to the same period in 2014, primarily due to the 298.6% increase in the dispatch of our combustion turbine facilities partially offset by the 34.3% decrease in the average cost of fuel for our combustion turbine facilities. Fuel expense decreased $50.3 million, or 28.2%, for the nine months ended September 30, 2015, as compared to the same period in 2014. This decrease was primarily driven by the 74.5% decrease in the average cost of fuel for our combustion turbine facilities partially offset by the 99.7% increase in the dispatch of our combustion turbine facilities.

•
Purchased power expense, which includes the cost of purchased energy and capacity, decreased $23.3 million, or 19.6%, for the three months ended September 30, 2015, as compared to the same period in 2014. The volume of purchased energy decreased 17.6% and the average cost of purchased energy decreased 5.1% for the three months ended September 30, 2015, as compared to the same period in 2014.
Other Items
Investment Income
Investment income decreased $0.1 million, or 6.5%, and $0.7 million, or 13.1%, for the three and nine months ended September 30, 2015, respectively, as compared to the same periods in 2014, primarily due to lower income earned on our nuclear decommissioning trust.
Interest Charges, Net
The primary factors affecting our interest charges, net are issuance of indebtedness, scheduled payments of principal on our indebtedness, interest charges related to our revolving credit facility, and capitalized interest. The major components of interest charges, net for the three and nine months ended September 30, 2015 and 2014, were as follows:
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands)
 
(in thousands)
Interest on long-term debt
$
(14,693
)
 
$
(11,385
)
 
$
(43,510
)
 
$
(34,140
)
Interest on revolving credit facility
(164
)
 
(263
)
 
(545
)
 
(592
)
Other interest
(171
)
 
(100
)
 
(405
)
 
(213
)
Total interest charges
(15,028
)
 
(11,748
)
 
(44,460
)
 
(34,945
)
Allowance for borrowed funds used during construction
3,993

 
211

 
8,645

 
640

Interest charges, net
$
(11,035
)
 
$
(11,537
)
 
$
(35,815
)
 
$
(34,305
)
Interest charges, net decreased for the three months ended September 30, 2015, by $0.5 million, or 4.4%, as compared to the same period in 2014, due to the increase in allowance for borrowed funds used during construction, substantially offset by the increase in interest on long-term debt. Interest charges, net increased by$1.5 million, or 4.4%, for the nine months ended September 30, 2015, as compared to the same period in 2014, primarily as a result of the increase in total interest charges due to the January 2015 debt issuance, substantially offset by the increase in allowance for borrowed funds used during construction.
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, increased for the three and nine months ended September 30, 2015, by $0.7 million, or 27.9%, and $1.9 million, or 27.2%, respectively, as compared to the same periods in 2014.

20

Financial Condition
The principal changes in our financial condition from December 31, 2014 to September 30, 2015, were caused by the increases in long-term debt, construction work in progress, accounts payable-members, accounts payable, and prepayments and other, the decrease in revolving credit facility, and the change in deferred energy.

•
Long-term debt increased $332.0 million due to issuance of long-term debt on January 15, 2015.

•
Construction work in progress increased $270.4 million primarily due to expenditures related to Wildcat Point.

•
Accounts payable-members increased $68.1 million due to the increase in member prepayments and the increase in amounts owed to our member distribution cooperatives under Margin Stabilization.

•
Accounts payable increased $46.2 million primarily due to increased payables related to Wildcat Point.

•
Prepayments and other increased $32.8 million primarily due to the $35.5 million prepayment related to the purchase of the land and land rights associated with Wildcat Point.

•
Revolving credit facility decreased $86.0 million due to the repayment of outstanding borrowings under our revolving credit facility using proceeds from the January 2015 debt issuance.

•
Deferred energy changed $33.2 million as a result of the over-collection of our energy costs in 2015. The deferred energy balance changed from a $19.9 million asset (under-collection) at December 31, 2014, to a $13.2 million liability (over-collection) at September 30, 2015.

Liquidity and Capital Resources
Sources
Cash generated by our operations, periodic borrowings under our credit facility, and occasional issuances of long-term indebtedness provide our sources of liquidity and capital.
Operations
During the first nine months of 2015 and 2014, our operating activities provided cash flows of $156.1 million and $27.8 million, respectively. Operating activities in 2015 were primarily impacted by the following:

•
Current liabilities changed $75.8 million substantially due to the $68.1 million increase in accounts payable-members;

•
Deferred energy changed $33.2 million due to the over-collection of our energy costs in 2015 as compared to the under-collection of our energy costs in 2014; and

•
Current assets changed $21.9 million due to the $32.8 million change in prepayments and other, partially offset by changes in accounts receivable-members, fuel, materials, and supplies, and accounts receivable.
Revolving Credit Facility
We currently maintain a $500.0 million revolving credit facility to cover our short-term and medium-term funding needs. Commitments under this syndicated credit agreement extend until March 5, 2019. At September 30, 2015, we did not have any borrowings outstanding under this facility, as compared to December 31, 2014, when we had $86.0 million outstanding. At September 30, 2015, and December 31, 2014, we had letters of credit outstanding in the amount of $8.2 million and $10.0 million, respectively.
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 January 15, 2015, we issued $332.0 million of first mortgage bonds in a private placement transaction. The issuance consisted of $260.0 million of 4.46% First Mortgage Bonds, 2015 Series A due December 1, 2044, and $72.0 million of 4.56% First Mortgage Bonds, 2015 Series B due December 1, 2053.

21


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.

22

ITEM 3. QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK
No material changes occurred in our exposure to market risk during the third quarter of 2015.
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.


23

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. A hearing was held in December 2014, briefs were filed in January 2015, and we received an initial decision from the hearing judge on April 13, 2015. The hearing judge found many components of the formula rate to be just and reasonable. We believe all components of the formula rate are just and reasonable and addressed the components the hearing judge found to be unjust and unreasonable in our brief on exceptions. Briefs on exceptions to the initial decision and briefs opposing exceptions to the initial decision were filed on May 13, 2015, and June 2, 2015, respectively. The FERC commissioners have the ultimate authority in this proceeding and they have no timetable to issue a final order. Our formula rate remains in effect subject to refund pending a final order from FERC. If a refund is ultimately determined, we believe it will result in a reallocation of costs among our member distribution cooperatives.
Other Matters
Other than legal proceedings arising out of the ordinary course of business, which management believes will not have a material adverse impact on our results of operations or financial condition, there is no other litigation pending or threatened against us.
ITEM 1A. RISK FACTORS
In addition to the other information set forth in this report, you should carefully consider the factors discussed in “Risk Factors” in Part I, Item 1A of our 2014 Annual Report on Form 10-K, which could affect our business, financial condition or future results. The risks described in our Annual Report on Form 10-K are not the only risks facing us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.
ITEM 5. OTHER INFORMATION
Recovery of Costs from PJM
On June 23, 2014, we filed a petition at FERC seeking recovery from PJM of approximately $14.9 million of unreimbursed costs, which were incurred during the first quarter of 2014 related to the dispatch of our combustion turbine generating facilities. On June 9, 2015, FERC denied our petition, on July 9, 2015, we filed a request for rehearing, and on August 10, 2015, FERC issued an order granting rehearing for the limited purpose of FERC's further consideration of the matter. The results of FERC's further consideration of the matter cannot currently be determined and we have not recorded a receivable related to this matter.
Disposal of Coal Combustion Residual
In December 2014, the EPA issued the final rule regulating the disposal of CCRs, commonly known as coal ash. The rule establishes technical requirements for CCR landfills and surface impoundments under Subtitle D of the Resource Conservation and Recovery Act. The final rule was published in the Federal Register in April 2015 and, as a result, we established asset retirement obligations totaling $8.6 million during the second quarter of 2015.
Capacity Performance
In December 2014, PJM proposed multiple changes to RPM and on June 9, 2015, FERC approved most of PJM’s proposed changes. These changes are expected to result in higher capacity clearing prices and are intended to increase the availability of generating units, especially during emergency conditions. This could enable generation owners, such as ODEC, to earn increased compensation for capacity for certain generating units.  While generating units have the potential to earn increased compensation for capacity, they are exposed to significantly higher charges if they do not perform during emergency conditions.  For the PJM delivery year beginning June 1, 2016, qualifying generating units may be voluntarily offered into PJM’s capacity auction as a capacity performance unit. A unit not offered as a capacity performance unit, known as a base capacity unit, will be excluded from the assessment of the charges for non-performance during the winter months. Starting with the delivery year beginning June 1, 2020, capacity revenue will only be paid to generating units offered as a capacity performance unit. We continue to evaluate our bidding strategy for our generating units for the PJM capacity auctions.

24


Amended Articles of Incorporation
On September 29, 2015, our members approved the Amended and Restated Articles of Incorporation. On October 6, 2015, the Virginia State Corporation Commission issued the Certificate of Amendment and Restatement, which caused the Amended and Restated Articles of Incorporation to become effective. The Amended and Restated Articles of Incorporation are filed as Exhibit 3.1. We have no class of equity securities registered under Section 12 of the Securities Exchange Act.
Clean Power Plan
On October 23, 2015, the EPA's Clean Power Plan rule was published in the Federal Register and, subject to a 60-day period to legally challenge the rule, will take effect December 23, 2015. The rule establishes emission guidelines for CO2 from existing electric utility generating units under 111(d) of the Clean Air Act. We currently cannot predict the impact of EPA's Clean Power Plan rule on our existing facilities due to its implementation through state plans, or if none, a federal plan, each of which has not been developed. We continue to follow developments related to this rule.

25

ITEM 6.
EXHIBITS
 
3.1
 
Amended and Restated Articles of Incorporation
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


26

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 10, 2015
 
 
 
 
 
/s/     Robert L. Kees        
 
 
 
 
 
 
Robert L. Kees
 
 
 
 
 
 
Senior Vice President and Chief Financial Officer
 
 
 
 
 
 
(Principal financial officer)


27

EXHIBIT INDEX
 
 
 
 
Exhibit
Number
  
Description of Exhibit
 
 
3.1
 
Amended and Restated Articles of Incorporation
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


28