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TABLE OF CONTENTS

Table of Contents


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 June 30, 2014

OR

o

 

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

For the transition period from                                    to                                     

Commission File No. 000-53908

logo

(An Electric Membership Corporation)
(Exact name of registrant as specified in its charter)

Georgia
(State or other jurisdiction of
incorporation or organization)
  58-1211925
(I.R.S. employer
identification no.)

2100 East Exchange Place
Tucker, Georgia

 

30084-5336
(Address of principal executive offices)   (Zip Code)

Registrant's telephone number, including area code

 

(770) 270-7600

        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 ý    No o

        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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý    No o

        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 "large accelerated filer," "accelerated filer," and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one): Large Accelerated Filer o    Accelerated Filer o    Non-Accelerated Filer ý    (Do not check if a smaller reporting company)    Smaller Reporting Company o

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

        Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date. The registrant is a membership corporation and has no authorized or outstanding equity securities.

   


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Table of Contents

OGLETHORPE POWER CORPORATION
INDEX TO QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED JUNE 30, 2014

 
   
  Page No.
PART I—FINANCIAL INFORMATION    

Item 1.

 

Financial Statements

 
1

 

Unaudited Condensed Balance Sheets as of June 30, 2014 and December 31, 2013

 
1

 

Unaudited Condensed Statements of Revenues and Expenses For the Three and Six Months ended June 30, 2014 and 2013

 
3

 

Unaudited Condensed Statements of Comprehensive Margin For the Three and Six Months ended June 30, 2014 and 2013

 
4

 

Unaudited Condensed Statements of Patronage Capital and Membership Fees and Accumulated Other Comprehensive Margin (Deficit) For the Six Months ended June 30, 2014 and 2013

 
5

 

Unaudited Condensed Statements of Cash Flows For the Six Months ended June 30, 2014 and 2013

 
6

 

Notes to Unaudited Condensed Financial Statements For the Three and Six Months ended June 30, 2014 and 2013

 
7

Item 2.

 

Management's Discussion and Analysis of Financial Condition and Results of Operations

 
24

Item 3.

 

Quantitative and Qualitative Disclosures About Market Risk

 
31

Item 4.

 

Controls and Procedures

 
31

PART II—OTHER INFORMATION

 

 

Item 1.

 

Legal Proceedings

 
32

Item 1A.

 

Risk Factors

 
33

Item 2.

 

Unregistered Sales of Equity Securities and Use of Proceeds

 
34

Item 3.

 

Defaults Upon Senior Securities

 
34

Item 4.

 

Mine Safety Disclosures

 
34

Item 5.

 

Other Information

 
34

Item 6.

 

Exhibits

 
34

SIGNATURES

 

35

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CAUTIONARY STATEMENTS REGARDING

FORWARD-LOOKING STATEMENTS AND ASSOCIATED RISKS

This quarterly report on Form 10-Q contains "forward-looking statements." All statements, other than statements of historical facts, that address activities, events or developments that we expect or anticipate to occur in the future, including matters such as the timing of various regulatory and other actions, future capital expenditures, business strategy and development, construction or operation of facilities (often, but not always, identified through the use of words or phrases such as "will likely result," "are expected to," "will continue," "is anticipated," "estimated," "projection," "target" and "outlook") are forward-looking statements.

Although we believe that in making these forward-looking statements our expectations are based on reasonable assumptions, any forward-looking statement involves uncertainties and there are important factors that could cause actual results to differ materially from those expressed or implied by these forward-looking statements. Some of the risks, uncertainties and assumptions that may cause actual results to differ from these forward-looking statements are described under the heading "RISK FACTORS" in this quarterly report and under the heading "RISK FACTORS" and in other sections of our annual report on Form 10-K for the fiscal year ended December 31, 2013. In light of these risks, uncertainties and assumptions, the forward-looking events and circumstances discussed in this quarterly report may not occur.

Any forward-looking statement speaks only as of the date of this quarterly report, and, except as required by law, we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for us to predict all of them; nor can we assess the impact of each factor or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. Factors that could cause actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:

    cost increases and schedule delays with respect to our construction projects, in particular, the construction of two additional nuclear units at Plant Vogtle;

    legislative and regulatory compliance standards and our ability to comply with any applicable standards, including mandatory reliability standards, and potential penalties for non-compliance;

    costs associated with achieving and maintaining compliance with applicable environmental laws and regulations, including those related to air emissions, water and coal combustion byproducts;

    potential legislative and regulatory responses to climate change initiatives, including the regulation of carbon dioxide and other greenhouse gas emissions;

    increasing debt caused by significant capital expenditures which is weakening certain of our financial metrics;

    commercial banking and financial market conditions;

    our access to capital, the cost to access capital, and the results of our financing and refinancing efforts, including availability of funds in the capital markets;

    uncertainty as to the continued availability of funding from the Rural Utilities Service and our continued eligibility to receive advances from the U.S. Department of Energy;

    actions by credit rating agencies;

    risks and regulatory requirements related to the ownership and construction of nuclear facilities;

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    adequate funding of our nuclear decommissioning trust fund including investment performance and projected decommissioning costs;

    weather conditions and other natural phenomena;

    continued efficient operation of our generation facilities by us and third-parties;

    the availability of an adequate and economical supply of fuel, water and other materials;

    reliance on third-parties to efficiently manage, distribute and deliver generated electricity;

    acts of sabotage, wars or terrorist activities, including cyber attacks;

    the credit quality and/or inability of various counterparties to meet their financial obligations to us, including failure to perform under agreements;

    our members' ability to perform their obligations to us;

    changes to protections granted by the Georgia Territorial Act that subject our members to increased competition;

    changes in technology available to and utilized by us or our competitors;

    general economic conditions;

    unanticipated variation in demand for electricity or load forecasts resulting from changes in population and business growth (and declines), consumer consumption, energy conservation efforts and the general economy;

    unanticipated changes in interest rates or rates of inflation;

    significant changes in our relationship with our employees, including the availability of qualified personnel;

    unanticipated changes in capital expenditures, operating expenses and liquidity needs;

    litigation or legal and administrative proceedings and settlements;

    significant changes in critical accounting policies material to us; and

    hazards customary to the electric industry and the possibility that we may not have adequate insurance to cover losses resulting from these hazards.

iii


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PART I—FINANCIAL INFORMATION
Item 1. Financial Statements


Oglethorpe Power Corporation
Condensed Balance Sheets (Unaudited)
June 30, 2014 and December 31, 2013



    (dollars in thousands)  

 

2014  

  2013    

Assets

             

Electric plant:

             

In service

  $ 8,258,050   $ 8,050,103  

Less: Accumulated provision for depreciation

    (3,688,112 )   (3,615,375 )
           

    4,569,938     4,434,728  

Nuclear fuel, at amortized cost

   
338,856
   
341,012
 

Construction work in progress

    2,227,216     2,212,224  
           

    7,136,010     6,987,964  
           

Investments and funds:

   
 
   
 
 

Nuclear decommissioning trust fund

    361,746     343,698  

Investment in associated companies

    65,395     66,437  

Long-term investments

    83,545     81,720  

Restricted cash

    2,766     34,975  

Other

    16,617     16,098  
           

    530,069     542,928  
           

Current assets:

   
 
   
 
 

Cash and cash equivalents

    329,866     408,193  

Restricted short-term investments

    293,859     272,686  

Receivables

    150,359     128,992  

Inventories, at average cost

    253,712     286,168  

Prepayments and other current assets

    15,923     16,894  
           

    1,043,719     1,112,933  
           

Deferred charges:

   
 
   
 
 

Deferred debt expense, being amortized

    99,785     57,175  

Regulatory assets

    400,996     331,108  

Other

    51,101     63,104  
           

    551,882     451,387  
           

  $ 9,261,680   $ 9,095,212  
           
           

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

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Oglethorpe Power Corporation
Condensed Balance Sheets (Unaudited)
June 30, 2014 and December 31, 2013



    (dollars in thousands)  

 

2014  

  2013    

Equity and Liabilities

             

Capitalization:

   
 
   
 
 

Patronage capital and membership fees

  $ 750,908   $ 714,489  

Accumulated other comprehensive margin (deficit)

    278     (549 )
           

    751,186     713,940  

Long-term debt

   
6,893,755
   
6,817,518
 

Obligation under capital leases

    114,240     121,731  

Other

    15,898     15,379  
           

    7,775,079     7,668,568  
           

Current liabilities:

   
 
   
 
 

Long-term debt and capital leases due within one year

    289,067     152,153  

Short-term borrowings

    195,913     279,407  

Accounts payable

    76,757     101,529  

Accrued interest

    58,376     58,193  

Member power bill prepayments, current

    93,041     82,405  

Other current liabilities

    34,290     42,253  
           

    747,444     715,940  
           

Deferred credits and other liabilities:

   
 
   
 
 

Gain on sale of plant, being amortized

    21,417     22,157  

Asset retirement obligations

    420,016     408,050  

Member power bill prepayments, non-current

    36,153     32,313  

Power sale agreement, being amortized

    19,388     26,107  

Regulatory liabilities

    175,813     158,789  

Other

    66,370     63,288  
           

    739,157     710,704  
           

  $ 9,261,680   $ 9,095,212  
           
           

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

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Oglethorpe Power Corporation
Condensed Statements of Revenues and Expenses (Unaudited)
For the Three and Six Months Ended June 30, 2014 and 2013



    (dollars in thousands)  

 

Three Months  

 

Six Months  

 

  2014     2013     2014     2013    

Operating revenues:

                         

Sales to Members

  $ 338,116   $ 306,191   $ 672,875   $ 592,844  

Sales to non-Members

    17,867     18,158     50,408     37,419  
                   

Total operating revenues

    355,983     324,349     723,283     630,263  
                   

Operating expenses:

   
 
   
 
   
 
   
 
 

Fuel

    133,976     113,065     266,252     213,215  

Production

    99,004     89,294     207,088     184,014  

Depreciation and amortization

    41,404     38,578     82,118     75,661  

Purchased power

    16,312     14,717     36,378     27,384  

Accretion

    6,108     5,677     12,126     11,307  

Deferral of Hawk Road and Smith Energy Facilities effect on net margin

    (10,421 )   (6,777 )   (20,136 )   (18,667 )
                   

Total operating expenses

    286,383     254,554     583,826     492,914  
                   

Operating margin

    69,600     69,795     139,457     137,349  
                   

Other income:

   
 
   
 
   
 
   
 
 

Investment income

    9,145     8,148     18,427     15,425  

Other

    2,232     2,240     4,609     4,517  
                   

Total other income

    11,377     10,388     23,036     19,942  
                   

Interest charges:

   
 
   
 
   
 
   
 
 

Interest expense

    85,965     76,251     167,882     152,028  

Allowance for debt funds used during construction

    (26,385 )   (24,562 )   (50,114 )   (49,416 )

Amortization of debt discount and expense

    4,201     3,992     8,306     8,153  
                   

Net interest charges

    63,781     55,681     126,074     110,765  
                   

Net margin

  $ 17,196   $ 24,502   $ 36,419   $ 46,526  
                   
                   

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

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Oglethorpe Power Corporation
Condensed Statements of Comprehensive Margin (Unaudited)
For the Three and Six Months Ended June 30, 2014 and 2013



    (dollars in thousands)  

 

Three Months  

 

Six Months  

 

  2014     2013     2014     2013    

Net margin

 
$

17,196
 
$

24,502
 
$

36,419
 
$

46,526
 
                   

Other comprehensive margin:

   
 
   
 
   
 
   
 
 

Unrealized gain (loss) on available-for-sale securities          

    431     (1,090 )   827     (1,302 )
                   

Total comprehensive margin

 
$

17,627
 
$

23,412
 
$

37,246
 
$

45,224
 
                   
                   

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

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Oglethorpe Power Corporation
Condensed Statements of Patronage Capital and Membership Fees
and Accumulated Other Comprehensive Margin (Deficit) (Unaudited)
For the Six Months Ended June 30, 2014 and 2013



      (dollars in thousands)  

 


 

Patronage
Capital and
Membership
Fees

 

Accumulated
Other
Comprehensive
Margin (Deficit)

 

Total

 
Balance at December 31, 2012   $ 673,009   $ 903   $ 673,912  
Components of comprehensive margin:                    

Net margin

    46,526         46,526  

Unrealized (loss) on available-for-sale securities

        (1,302 )   (1,302 )

 

 
Balance at June 30, 2013   $ 719,535   $ (399 ) $ 719,136  
   

Balance at December 31, 2013

 

$

714,489

 

$

(549

)

$

713,940

 
Components of comprehensive margin:                    

Net margin

    36,419         36,419  

Unrealized gain on available-for-sale securities

        827     827  

 

 
Balance at June 30, 2014   $ 750,908   $ 278   $ 751,186  
   

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

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Oglethorpe Power Corporation
Condensed Statements of Cash Flows (Unaudited)
For the Six Months Ended June 30, 2014 and 2013



    (dollars in thousands)  

 

2014  

  2013    

Cash flows from operating activities:

             

Net margin

  $ 36,419   $ 46,526  
           

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

             

Depreciation and amortization, including nuclear fuel

    153,759     141,876  

Accretion cost

    12,126     11,307  

Amortization of deferred gains

    (894 )   (893 )

Allowance for equity funds used during construction

    (731 )   (1,411 )

Deferred outage costs

    (31,411 )   (31,820 )

Deferral of Hawk Road and Smith Energy Facilities effect on net margin

    (20,136 )   (18,667 )

Gain on sale of investments

    (8,961 )   (17,304 )

Regulatory deferral of costs associated with nuclear decommissioning

    1,571     10,085  

Other

    6,816     (3,551 )

Change in operating assets and liabilities:

   
 
   
 
 

Receivables

    (21,180 )   (28,158 )

Inventories

    32,455     (3,902 )

Prepayments and other current assets

    1,209     (1,872 )

Accounts payable

    (45,456 )   (43,540 )

Accrued interest

    183     31,022  

Accrued taxes

    (3,978 )   12,808  

Other current liabilities

    (2,479 )   (5,067 )

Member power bill prepayments

    14,475     50,860  
           

Total adjustments

    87,368     101,773  
           

Net cash provided by operating activities

    123,787     148,299  
           

Cash flows from investing activities:

             

Property additions

    (249,317 )   (321,246 )

Activity in decommissioning fund—Purchases

    (188,815 )   (346,211 )

                                                       —Proceeds

    186,165     343,340  

Decrease (increase) in restricted cash

    32,209     (27,121 )

Increase in restricted short-term investments

    (21,173 )   (141,540 )

Activity in other long-term investments—Purchases

    (28,690 )   (19,670 )

                                                                —Proceeds

    30,385     20,103  

Activity on interest rate options—Collateral returned

    (73,850 )   (46,420 )

                                                  —Collateral received

    41,640     73,540  

Other

    473     1,269  
           

Net cash used in investing activities

    (270,973 )   (463,956 )
           

Cash flows from financing activities:

             

Long-term debt proceeds

    993,707     283,168  

Long-term debt payments

    (333,127 )   (244,042 )

(Decrease) increase in short-term borrowings, net

    (548,494 )   201,391  

Other

    (43,227 )   (2,775 )
           

Net cash provided by financing activities

    68,859     237,742  
           

Net decrease in cash and cash equivalents

    (78,327 )   (77,915 )

Cash and cash equivalents at beginning of period

    408,193     298,565  
           

Cash and cash equivalents at end of period

  $ 329,866   $ 220,650  
           
           

Supplemental cash flow information:

             

Cash paid for—

             

Interest (net of amounts capitalized)

  $ 115,231   $ 69,269  

Supplemental disclosure of non-cash investing and financing activities:

             

Change in plant expenditures included in accounts payable

  $ 22,904   $ (19,846 )

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

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Oglethorpe Power Corporation
Notes to Unaudited Condensed Financial Statements
For the Three and Six Months ended June 30, 2014 and 2013

(A)
General.    The condensed financial statements included in this report have been prepared by us pursuant to the rules and regulations of the Securities and Exchange Commission. In the opinion of management, the information furnished in this report reflects all adjustments (which include only normal recurring adjustments) and estimates necessary to fairly state, in all material respects, the results for the three- and six- month periods ended June 30, 2014 and 2013. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to SEC rules and regulations, although we believe that the disclosures are adequate to make the information presented not misleading. Certain prior year amounts have been reclassified to conform with the current year presentation. These condensed financial statements should be read in conjunction with the financial statements and the notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2013, as filed with the SEC. The results of operations for the three-and six- month periods ended June 30, 2014 are not necessarily indicative of results to be expected for the full year. As noted in our 2013 Form 10-K, our revenues consist primarily of sales to our 38 electric distribution cooperative members and, thus, the receivables on the condensed balance sheets are principally from our members. (See "Notes to Financial Statements" in our 2013 Form 10-K.)
(B)
Fair Value.    Authoritative guidance regarding fair value measurements for financial and non-financial assets and liabilities defines fair value, establishes a framework for measuring fair value in accordance with generally accepted accounting principles, and expands disclosures about fair value measurements.

    The guidance establishes a three-tier fair value hierarchy which prioritizes the inputs used in measuring fair value as follows:

      Level 1.  Quoted prices from active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Quoted prices in active markets provide the most reliable evidence of fair value and are used to measure fair value whenever available. Level 1 primarily consists of financial instruments that are exchange-traded.

      Level 2.  Pricing inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 2 primarily consists of financial instruments that are non-exchange-traded but have significant observable inputs.

      Level 3.  Pricing inputs that include significant inputs which are generally less observable from objective sources. These inputs may include internally developed methodologies that result in management's best estimate of fair value. Level 3 financial instruments are those whose fair value is based on significant unobservable inputs.

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    As required by the guidance, assets and liabilities measured at fair value are based on one or more of the following three valuation techniques:

      1.    Market approach.    The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities (including a business) and deriving fair value based on these inputs.

      2.    Income approach.    The income approach uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts.

      3.    Cost approach.    The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (often referred to as current replacement cost). This approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset or comparable utility, adjusted for obsolescence.

    The tables below detail assets and liabilities measured at fair value on a recurring basis at June 30, 2014 and December 31, 2013.

   

   
 
 

Fair Value Measurements at Reporting Date Using  

 

   

June 30,
2014

   

Quoted Prices in
Active Markets for
Identical Assets

(Level 1)

   

Significant Other
Observable
Inputs

(Level 2)

   

Significant
Unobservable
Inputs

(Level 3)

 
       

    (dollars in thousands)  

Nuclear decommissioning trust funds:

                         

Domestic equity

  $ 151,899   $ 151,899   $   $  

International equity trust

    76,447         76,447      

Corporate bonds

    29,511         29,511      

US Treasury and government agency securities

    60,709     60,709          

Agency mortgage and asset backed securities

    26,920         26,920      

Government bonds

    2,012         2,012      

Other

    14,248     14,248          

Long-term investments:

                         

Corporate bonds

    4,698         4,698      

US Treasury and government agency securities

    13,702     13,702          

Agency mortgage and asset backed securities

    1,870         1,870      

International equity trust

    11,768         11,768      

Mutual funds

    51,368     51,368          

Other

    139     139          

Interest rate options

    18,535             18,535 (1)

Natural gas swaps

    1,250         1,250      

                         

 

 

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Fair Value Measurements at Reporting Date Using  

 

   

December 31,
2013

   

Quoted Prices in
Active Markets for
Identical Assets

(Level 1)

   

Significant Other
Observable
Inputs

(Level 2)

   

Significant
Unobservable
Inputs

(Level 3)

 
       

    (dollars in thousands)  

Nuclear decommissioning trust funds:

                         

Domestic equity

  $ 143,929   $ 143,929   $   $  

International equity trust

    72,466         72,466      

Corporate bonds

    39,863         39,863      

US Treasury and government agency securities

    44,846     44,846          

Agency mortgage and asset backed securities

    30,133         30,133      

Municipal Bonds

    641         641      

Other

    11,820     11,820          

Long-term investments:

                         

Corporate bonds

    6,487         6,487      

US Treasury and government agency securities

    8,563     8,563          

Agency mortgage and asset backed securities

    3,679         3,679      

International equity trust

    11,148         11,148      

Mutual funds

    51,559     51,559          

Other

    284     284          

Interest rate options

    63,471             63,471 (1)

Natural gas swaps

    1,011         1,011      

                         

 

 
(1)
Interest rate options as reflected on the unaudited condensed Balance Sheet include the fair value of the interest rate options offset by $2,760,000 and $34,970,000 of collateral received from the counterparties at June 30, 2014 and December 31, 2013, respectively.

    The Level 2 investments above in corporate bonds and agency mortgage and asset backed securities may not be exchange traded. The fair value measurements for these investments are based on a market approach, including the use of observable inputs. Common inputs include reported trades and broker/dealer bid/ask prices. The fair value of the Level 2 investments above in international equity trust are calculated based on the net asset value per share of the fund. There are no unfunded commitments for the international equity trust and redemption may occur daily with a 3-day redemption notice period.

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    The following tables present the changes in Level 3 assets measured at fair value on a recurring basis during the three and six months ended June 30, 2014 and 2013.

   

 

 

 

Three Months Ended
June 30, 2014

 
       
      Interest rate options  
       
      (dollars in thousands)  
Assets (Liabilities):        
Balance at March 31, 2014   $ 31,463  
Total gains or losses (realized/unrealized):        

Included in earnings (or changes in net assets)

    (12,928 )
       
Balance at June 30, 2014   $ 18,535  
       
       
         

 

 

 

   

 

 

 

Three Months Ended
June 30, 2013

 
       
      Interest rate options  
       
      (dollars in thousands)  
Assets (Liabilities):        
Balance at March 31, 2013   $ 26,539  
Total gains or losses (realized/unrealized):        

Included in earnings (or changes in net assets)

    17,141  
       
Balance at June 30, 2013   $ 43,680  
       
       

 

 

 

   

 

 

 

Six Months Ended
June 30, 2014

 
       
      Interest rate options  
       
      (dollars in thousands)  
Assets (Liabilities):        
Balance at December 31, 2013   $ 63,471  
Total gains or losses (realized/unrealized):        

Included in earnings (or changes in net assets)

    (44,936 )
       
Balance at June 30, 2014   $ 18,535  
       
       

 

 

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Six Months Ended
June 30, 2013

 
       
      Interest rate options  
       
      (dollars in thousands)  
Assets (Liabilities):        
Balance at December 31, 2012   $ 25,783  
Total gains or losses (realized/unrealized):        

Included in earnings (or changes in net assets)

    17,897  
       
Balance at June 30, 2013   $ 43,680  
       
       

 

 

    We estimate the value of the interest rate options as the sum of time value and any intrinsic value minus a counterparty credit adjustment. Intrinsic value is the value of the underlying swap, which we are able to calculate based on the forward LIBOR swap rates, the fixed rate on the underlying swap, the time to expiration, the term of the underlying swap and discount rates, all of which we are able to effectively observe. Time value is the additional value of the swaption due to the fact that it is an option. We estimate the time value using an option pricing model which, in addition to the factors used to calculate intrinsic value, also takes into account option volatility, which we estimate based on option valuations we obtain from various sources. We estimate the counterparty credit adjustment by observing credit attributes, including the credit default swap spread of entities similar to the counterparty and the amount of credit support that is available for each swaption. Since the primary component of the LIBOR swaptions' value is time value, which is based on estimated option volatility derived from valuations of comparable instruments that are generally not publicly available, we have categorized these LIBOR swaptions as Level 3. We believe the estimated fair values for the LIBOR swaptions we hold are based on the most accurate information available for these types of derivative contracts. For additional information regarding our interest rate options, see Note C.

    The estimated fair values of our long-term debt, including current maturities at June 30, 2014 and December 31, 2013 were as follows (in thousands):

   

 

 

 

2014

 

 

2013

 
           
      Carrying
Value
    Fair
Value
    Carrying
Value
    Fair
Value
 
           
Long-term debt   $ 7,168,443   $ 7,971,425   $ 6,954,293   $ 7,317,476  
                           

 

 

    Long-term debt is classified as Level 2 and is estimated based on observed or quoted market prices for the same or similar issues or on current rates offered to us for debt of similar maturities. The primary sources of our long-term debt consist of first mortgage bonds, pollution control revenue bonds and long-term debt issued by the Federal Financing Bank that is guaranteed by the Rural Utilities Service or the U.S. Department of Energy. We also have small amounts of long-term debt provided by National Rural Utilities Cooperative Finance Corporation (CFC) and by CoBank, ACB. The valuations for the first mortgage bonds and the pollution control revenue bonds were obtained from third party investment banking firms and a third party subscription service, and are based on secondary market trading of our debt. Valuations for debt issued by the Federal Financing Bank are based on U.S. Treasury rates as of June 30, 2014 plus an applicable spread, which reflects our borrowing rate for new loans of this type from the Federal Financing Bank. We use an interest rate quote sheet provided by CoBank for valuation of the CoBank debt,

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    which reflects current rates for a similar loan. The rates on the CFC debt are fixed and the valuation is based on rate quotes provided by CFC.

    For cash and cash equivalents, restricted cash and receivables, the carrying amount approximates fair value because of the short-term maturity of those instruments.

(C)
Derivative Instruments.    Our risk management and compliance committee provides general oversight over all risk management and compliance activities, including but not limited to, commodity trading, investment portfolio management and interest rate risk management. We use commodity trading derivatives to manage our exposure to fluctuations in the market price of natural gas. To hedge the risk of rising interest rates on long-term debt in connection with capital expenditures, we have entered into interest rate options. We do not apply hedge accounting for any of these derivatives, but apply regulatory accounting. Consistent with our rate-making, unrealized gains or losses on our natural gas swaps and interest rate options are reflected as regulatory assets or liabilities, as appropriate.

    We are exposed to credit risk as a result of entering into these hedging arrangements. Credit risk is the potential loss resulting from a counterparty's nonperformance under an agreement. We have established policies and procedures to manage credit risk through counterparty analysis, exposure calculation and monitoring, exposure limits, collateralization and certain other contractual provisions.

    It is possible that volatility in commodity prices and/or interest rates could cause us to have credit risk exposures with one or more counterparties. We currently have credit risk exposure to our interest rate options counterparties. If such counterparties fail to perform their obligations, we could suffer a financial loss. However, as of June 30, 2014, all of the counterparties with transaction amounts outstanding under our hedging programs are rated investment grade by the major rating agencies or have provided a guaranty from one of their affiliates that is rated investment grade.

    We have entered into International Swaps and Derivatives Association agreements with our natural gas hedge and interest rate option counterparties that mitigate credit exposure by creating contractual rights relating to creditworthiness, collateral, termination and netting (which, in certain cases, allows us to use the net value of affected transactions with the same counterparty in the event of default by the counterparty or early termination of the agreement).

    Additionally, we have implemented procedures to monitor the creditworthiness of our counterparties and to evaluate nonperformance in valuing counterparty positions. We have contracted with a third party to assist in monitoring certain of our counterparties' credit standing and condition. Net liability positions are generally not adjusted as we use derivative transactions as hedges and have the ability and intent to perform under each of our contracts. In the instance of net asset positions, we consider general market conditions and the observable financial health and outlook of specific counterparties, forward looking data such as credit default swaps, when available, and historical default probabilities from credit rating agencies in evaluating the potential impact of nonperformance risk to derivative positions.

    The contractual agreements contain provisions that could require us or the counterparty to post collateral or credit support. The amount of collateral or credit support that could be required is calculated as the difference between the aggregate fair value of the hedges and pre-established credit thresholds. The credit thresholds are contingent upon each party's credit ratings from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty.

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    Gas hedges.     Under our natural gas swap arrangements, we pay the counterparty a fixed price for specified natural gas quantities and receive a payment for such quantities based on a market price index. These payment obligations are netted, such that if the market price index is lower than the fixed price, we will make a net payment, and if the market price index is higher than the fixed price, we will receive a net payment.

    At June 30, 2014 and December 31, 2013, the fair value of our natural gas contracts were a net asset of approximately $1,250,000 and $1,011,000, respectively.

    As of June 30, 2014 and December 31, 2013, neither we nor any counterparties were required to post credit support or collateral under these natural gas swap agreements. If the credit-risk-related contingent features underlying these agreements had been triggered on June 30, 2014 due to our credit rating being downgraded below investment grade, we would not have been required to post letters of credit with our counterparties.

    The following table reflects the volume activity of our natural gas derivatives as of June 30, 2014 that is expected to settle or mature each year:

   

Year

   

Natural Gas Swaps
(MMBTUs)
(in millions)

 

 

 

2014

    2.9  

2015

    1.1  

2016

    0.2  
       

Total

    4.2  

 

 

    Interest rate options.     We are exposed to the risk of rising interest rates when we incur long-term debt in connection with capital expenditures, particularly the construction of Vogtle Units No. 3 and No. 4. In the fourth quarter of 2011, we purchased LIBOR swaptions at a cost of $100,000,000 with a total notional amount of approximately $2,200,000,000 to hedge the interest rates on a portion of the debt that we are incurring to finance two additional nuclear units at Plant Vogtle. Since 2013, swaptions having a notional amount of approximately $1,100,000,000 have expired and as of June 30, 2014, the remaining notional amount of our outstanding swaptions was approximately $1,100,000,000.

    The LIBOR swaptions are each designed to cap our effective interest rate at a specified fixed interest rate on a specified option expiration date. This is accomplished by means of a payment of the cash settlement value our counterparties are obligated to make to us if prevailing fixed LIBOR swap rates exceed the specified fixed rate on the option expiration date. This payment would partially offset our interest costs, thereby reducing our effective interest rate. The cash settlement value would be zero if swap rates are at or below the specified fixed rate on the expiration date. The cash settlement value is calculated based on the value of an underlying swap which we have the right, but not the obligation, to enter into, which would begin on the option expiration date and extend until 2042 and under which we would pay the specified fixed rate and receive a floating LIBOR rate. The fixed rates on the unexpired swaptions we hold average 107 basis points above the corresponding LIBOR swap rates that were in effect as of June 30, 2014 and the weighted average fixed rate is 4.11%. Swaptions having notional amounts totaling $278,145,000 expired without value during the six months ended June 30, 2014. The remaining swaptions expire quarterly through 2017.

    We paid all the premiums to purchase these LIBOR swaptions at the time we entered into these transactions and have no additional payment obligations. These derivatives are recorded at fair

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    value. At June 30, 2014 and December 31, 2013, the fair value of these swaptions was approximately $18,535,000 and $63,471,000, respectively. To manage our credit exposure to our counterparties, we negotiated credit support provisions that require each counterparty to provide us collateral in the form of cash or securities to the extent that the value of the swaptions outstanding for that counterparty exceeds a certain threshold. The collateral thresholds can range from $0 to $10,000,000 depending on each counterparty's credit rating. As of June 30, 2014 and December 31, 2013, we held $2,760,000 and $34,970,000 of funds posted as collateral by the counterparties, respectively. The collateral received is recorded as restricted cash on our balance sheet. The liability associated with the collateral is recorded as an offset to the fair values of the swaptions, which are recorded within other deferred charges on the balance sheet, resulting in a net carrying amount of the interest rate options of $15,775,000 and $28,501,000 at June 30, 2014 and December 31, 2013, respectively.

    We are deferring unrealized gains or losses from the change in fair value of each LIBOR swaption and related carrying and other incidental costs in accordance with our rate-making treatment. The realized deferred costs and deferred gains, if any, from the settlement of the interest rate options will be amortized and collected in rates over the life of the $2.2 billion of debt that we hedged with the swaptions.

    The following table reflects the remaining notional amount of forecasted debt issuances we have hedged in each year with LIBOR swaptions as of June 30, 2014.

   

Year

   

LIBOR Swaption
Notional Dollar
Amount
(in thousands)

 

 

 

2014

  $ 285,280  

2015

    470,625  

2016

    310,533  

2017

    80,169  
       

Total

  $ 1,146,607  

 

 

The table below reflects the fair value of derivative instruments and their effect on our condensed balance sheets at June 30, 2014 and December 31, 2013.

   

 

Balance Sheet
Location

   

Fair Value

 
   

        2014     2013  

 

 

   

(dollars in thousands)

 

Not designated as hedges:

                 

Assets:

 

 

   
 
   
 
 

Interest rate options(1)

  Other deferred charges   $ 18,535   $ 63,471  

Liabilities:

 

 

   
 
   
 
 

Natural gas swaps

  Other current liabilities   $ 1,250   $ 1,011  

 

 
(1)
Excludes liability associated with cash collateral of $2,760,000 and $34,970,000 as of June 30, 2014 and December 31, 2013, respectively, which is recorded as an offset to the fair value of the swaptions on the unaudited condensed balance sheets.

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    The following table presents the gross realized gains and (losses) on derivative instruments recognized in margin for the three and six months ended June 30, 2014 and 2013.

   

 

Statement of
Revenues and
Expenses

   

Three months ended
June 30,

   

Six months ended
June 30,

 

  Location     2014     2013     2014     2013  
   

        (dollars in thousands)  

Not Designated as hedges:

                             

Natural Gas Swaps

  Fuel   $ 956   $ 449   $ 1,236   $ 566  

Natural Gas Swaps

  Fuel         (379 )       (913 )
           

      $ 956   $ 70   $ 1,236   $ (347 )
           
           

 

 

    The following table presents the unrealized gains and (losses) on derivative instruments deferred on the balance sheet at June 30, 2014 and December 31, 2013.

   

 

Balance Sheet
Location

   

2014

   

2013

 
   

        (dollars in thousands)  

Not designated as hedges:

             

Natural gas swaps

 

Regulatory liability

 
$

1,250
 
$

1,011
 

Interest rate options

  Regulatory asset     (48,669 )   (15,003 )
           

      $ (47,419 ) $ (13,992 )
           

 

 

    The following table presents the gross amounts of derivatives and their related offset amounts as permitted by their respective master netting agreements and obligations to return cash collateral.

   

 

 

 

Gross Amounts
of Recognized
Assets
(Liabilities)

 

 

Gross
Amounts
offset on the
Balance Sheet

 

 

Cash
Collateral

 

 

Net Amounts of
Assets Presented on
the Balance Sheet

 
       
      (dollars in thousands)  
June 30, 2014                          
Assets:                          

Natural gas swaps

  $ 1,356   $ (106 ) $   $ 1,250  

Interest rate options

  $ 18,535   $   $ (2,760 ) $ 15,775  

December 31, 2013

 

 

 

 

 

 

 

 

 

 

 

 

 
Assets:                          

Natural gas swaps

  $ 1,069   $ (58 ) $   $ 1,011  

Interest rate options

  $ 63,471   $   $ (34,970 ) $ 28,501  

 

 
(D)
Investments in Debt and Equity Securities.    Investment securities we hold are classified as available-for-sale. Available-for-sale securities are carried at market value with unrealized gains and losses, net of any tax effect, added to or deducted from other comprehensive margin, except that, in accordance with our rate-making treatment, unrealized gains and losses from investment securities held in the nuclear decommissioning funds are directly added to or deducted from the regulatory asset for asset retirement obligations. Realized gains and losses on the nuclear

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    decommissioning funds are also recorded to the regulatory asset. All realized and unrealized gains and losses are determined using the specific identification method. As of June 30, 2014, approximately 90% of these gross unrealized losses were in effect for less than one year.

    The following tables summarize the activities for available-for-sale securities as of June 30, 2014 and December 31, 2013.

   

 

 

Gross Unrealized  

 
      (dollars in thousands)  
June 30, 2014     Cost     Gains     Losses     Fair
Value
 
   
Equity   $ 191,821   $ 73,297   $ (935 ) $ 264,183  
Debt     163,504     10,484     (7,269 )   166,719  
Other     14,388     2     (1 )   14,389  
   
Total   $ 369,713   $ 83,783   $ (8,205 ) $ 445,291  
   

 

   

 

 

Gross Unrealized  

 
      (dollars in thousands)  
December 31, 2013     Cost     Gains     Losses     Fair
Value
 
   
Equity   $ 182,755   $ 68,424   $ (1,053 ) $ 250,126  
Debt     164,941     7,319     (9,070 )   163,190  
Other     12,101     2         12,103  
   
Total   $ 359,797   $ 75,745   $ (10,123 ) $ 425,419  
   
(E)
Recently Issued or Adopted Accounting Pronouncements.    In May 2014, the Financial Accounting Standards Board issued "Revenue from Contracts with Customers" (Topic 606). The new revenue standard requires that an entity recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. The standard is effective for the annual reporting period beginning after December 15, 2016 and early adoption is not permitted. We are currently evaluating the impact of this standard on our consolidated financial statements.
(F)
Accumulated Comprehensive Margin (Deficit).    The table below provides detail of the beginning and ending balance for each classification of other comprehensive margin (deficit) along with the amount of any reclassification adjustments included in margin for each of the periods presented in the unaudited Condensed Statements of Patronage Capital and Membership Fees and Accumulated Other Comprehensive Margin (Deficit). There were no material changes in the nature, timing or amounts of expected (gain) loss reclassified to net margin from the amounts disclosed in our 2013 Form 10-K. Amounts reclassified to net margin in the table below are reflected in "Other income" on our unaudited Condensed Statement of Revenues and Expenses.

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    Our effective tax rate is zero; therefore, all amounts below are presented net of tax.

   
 
  Accumulated Other
Comprehensive Margin
(Deficit)
Three Months Ended
 

   

(dollars in thousands)

 

   

Available-for-sale
Securities

 
       

Balance at March 31, 2013

  $ 691  

Unrealized (loss)

   
(1,074

)

(Gain) reclassified to net margin

   
(16

)

 

 

 

 

Balance at June 30, 2013

  $ (399 )
       

Balance at March 31, 2014

 
$

(153

)

Unrealized gain

   
492
 

(Gain) reclassified to net margin

   
(61

)

 

 

 

 

Balance at June 30, 2014

  $ 278  
       

 

 

 

   
 
  Six Months Ended  

   

(dollars in thousands)

 

   

Available-for-sale
Securities

 
       

Balance at December 31, 2012

  $ 903  

Unrealized (loss)

   
(1,222

)

(Gain) reclassified to net margin

   
(80

)

 

 

 

 

Balance at June 30, 2013

  $ (399 )
       

Balance at December 31, 2013

 
$

(549

)

Unrealized gain

   
881
 

(Gain) reclassified to net margin

   
(54

)

 

 

 

 

Balance at June 30, 2014

  $ 278  
       

 

 

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(G)
Contingencies and Regulatory Matters.

    Management does not anticipate that the liabilities, if any, for any current proceedings against us will have a material effect on our financial condition or results of operations. However, at this time, the ultimate outcome of any pending or potential litigation cannot be determined.

    a.    Nuclear Construction

    In April 2008, Georgia Power Company, acting for itself and as agent for us, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia (collectively, the Co-owners), and Westinghouse Electric Company LLC and Stone & Webster, Inc. (collectively, the Contractor) entered into an engineering, procurement, and construction agreement to design, engineer, procure, and construct two AP1000 nuclear units with electric generating capacity of approximately 1,100 megawatts each and related facilities, structures, and improvements at Plant Vogtle (Vogtle Units No. 3 and No. 4).

    Under the agreement, the Co-Owners and the Contractor have established both informal and formal dispute resolution procedures in order to resolve issues arising during the course of constructing a project of this magnitude. Georgia Power, on behalf of the Co-owners, has successfully initiated both formal and informal claims through these procedures, including ongoing claims. When matters are not resolved through these procedures, the parties may proceed to litigation. The Contractor and the Co-owners are involved in litigation with respect to certain claims that have not been resolved through the formal dispute resolution process.

    Current litigation relates to costs associated with design changes to the Westinghouse AP1000 Design Control Document (DCD) and costs associated with delays in the project schedule related to the timing of approval of the DCD and issuance of the combined construction permits and operating licenses by the Nuclear Regulatory Commission. In July 2012, the Co-owners and Contractor began negotiations regarding these costs, including the assertion by the Contractor that the Co-owners are responsible for these costs under the terms of the agreement. On November 1, 2012, the Co-owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia, seeking a declaratory judgment that the Co-owners are not responsible for these costs. Also on November 1, 2012, the Contractor filed suit against the Co-owners in the U.S. District Court for the District of Columbia alleging the Co-owners are responsible for these costs. In August 2013, the U.S. District Court for the District of Columbia dismissed the Contractor's suit, ruling that proper venue is the U.S. District Court for the Southern District of Georgia. In September 2013, the Contractor appealed the decision to the U.S. Court of Appeals for the District of Columbia.

    The portion of the additional costs claimed by the Contractor in its initial complaint that would be attributable to us, based on our ownership interest, was approximately $280 million in 2008 dollars with respect to these issues. The Contractor has also asserted that it is entitled to further schedule extensions. On May 22, 2014, the Contractor filed an amended counterclaim to the lawsuit pending in the Southern District of Georgia alleging that (i) the design changes to the DCD imposed by the Nuclear Regulatory Commission have delayed module production and the impacts to the Contractor are recoverable by the Contractor under the agreement and (ii) the changes to the basemat rebar design required by the Nuclear Regulatory Commission caused additional costs and delays recoverable by the Contractor under the agreement. The Contractor did not specify in its amended counterclaim claimed amounts relating to these new allegations but such claimed amounts could be substantial. Georgia Power, on behalf of the Co-owners, has not agreed with either the proposed cost or schedule adjustments or that the Co-owners have any responsibility for costs related to these issues.

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    While litigation is ongoing and Georgia Power and the Co-owners intend to vigorously defend their positions, Georgia Power and the Co-owners also expect negotiations with the Contractor to continue with respect to cost and schedule during which time the parties will attempt to reach a mutually acceptable compromise of their positions.

    If any or all of these costs are ultimately imposed on the Co-owners, we will capitalize the costs attributable to us. As of June 30, 2014, no material amounts have been recorded related to this claim. Additional claims by the Contractor or Georgia Power, on behalf of the Co-owners, are also likely to arise throughout construction.

    b.    Patronage Capital Litigation

    On March 13, 2014, a lawsuit was filed in the Superior Court of DeKalb County, Georgia, against us, Georgia Transmission and three of our member distribution cooperatives. Plaintiffs filed an amended complaint on July 28, 2014. The amended complaint challenges the patronage capital distribution practices of Georgia's electric cooperatives and seeks to certify a defendant class of all but one of our 38 members. It was filed by four former consumer-members of four of our members on behalf of themselves and a proposed class of all former consumer-members of our members. Plaintiffs claim that approximately 30% of all the defendants' total allocated patronage capital belongs to former consumer-members. Plaintiffs also allege that patronage capital owed to former consumer-members includes patronage capital allocated by us to our members but not yet distributed to our members. Plaintiffs claim that the patronage capital of former consumer-members held by defendants and the proposed defendant class should be retired immediately when the consumer-members end their membership by terminating service, or alternatively, according to a revolving schedule of no longer than 13 years from the date of its allocation and seek relief to effect such retirements. Plaintiffs further seek to require the defendants to adjust rates in order to establish and maintain reasonable reserves to fund patronage capital retirements on this basis. Plaintiffs also claim that defendants and the proposed defendant class should be required to adopt policies to periodically retire the patronage capital of all consumer-members on a revolving schedule of no longer than 13 years from the date of its allocation. Our first mortgage indenture restricts our ability to distribute patronage capital. See "Item 1—BUSINESS—OGLETHORPE POWER CORPORATION—First Mortgage Indenture" in our 2013 Form 10-K. Although not expected, if we were ordered by the Court to make distributions of our patronage capital, our first mortgage indenture would require us to raise our rates to a level sufficient so that we could comply with the current patronage capital restrictions, and the rate increases required to meet the Plaintiffs' demands would be significant for a period of years. We intend to defend vigorously against all claims in this litigation.

    c.    Environmental Matters

    As is typical for electric utilities, we are subject to various federal, state and local environmental laws which represent significant future risks and uncertainties. Air emissions, water discharges and water usage are extensively controlled, closely monitored and periodically reported. Handling and disposal requirements govern the manner of transportation, storage and disposal of various types of waste. We are also subject to climate change regulations that impose restrictions on emissions of greenhouse gases, including carbon dioxide, for certain new and modified facilities.

    In general, these and other types of environmental requirements are becoming increasingly stringent. Such requirements may substantially increase the cost of electric service, by requiring modifications in the design or operation of existing facilities or the purchase of emission allowances. Failure to comply with these requirements could result in civil and criminal penalties and could include the complete shutdown of individual generating units not in compliance. Certain of our debt instruments require us to comply in all material respects with laws, rules, regulations

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    and orders imposed by applicable governmental authorities, which include current and future environmental laws or regulations. Should we fail to be in compliance with these requirements, it would constitute a default under those debt instruments. We believe that we are in compliance with those environmental regulations currently applicable to our business and operations. Although it is our intent to comply with current and future regulations, we cannot provide assurance that we will always be in compliance.

    At this time, the ultimate impact of any new and more stringent environmental regulations described above is uncertain and could have an effect on our financial condition, results of operations and cash flows as a result of future additional capital expenditures and increased operations and maintenance costs.

    Additionally, litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has increased generally throughout the United States. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief, personal injury and property damage allegedly caused by coal combustion residue, greenhouse gas and other emissions have become more frequent.

(H)
Restricted Cash.    At June 30, 2014 and December 31, 2013, we had restricted cash totaling $2,922,000 and $35,131,000, respectively, of which $2,766,000 and $34,975,000, respectively, was classified as long-term. The long-term restricted cash balance at June 30, 2014 and December 31, 2013 consisted primarily of funds posted as collateral by counterparties to our interest rate options.
(I)
Restricted Short-term Investments.    At June 30, 2014 and December 31, 2013, we had $293,859,000 and $272,686,000, respectively, on deposit with the Rural Utilities Service in the Cushion of Credit Account. The restricted funds will be utilized for future Rural Utilities Service Federal Financing Bank debt service payments. The deposit earns interest at a rate of 5% per annum.
(J)
Regulatory Assets and Liabilities.    We apply the accounting guidance for regulated operations. Regulatory assets represent certain costs that are probable of recovery from our members in future revenues through rates under the wholesale power contracts with our members extending through December 31, 2050. Regulatory liabilities represent certain items of income that we are retaining and that will be applied in the future to reduce revenues required to be recovered from our members.

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    The following regulatory assets and liabilities are reflected on the unaudited condensed balance sheet as of June 30, 2014 and December 31, 2013.

   

    2014     2013  

   

(dollars in thousands)

 
   

Regulatory Assets:

             

Premium and loss on reacquired debt(a)

  $ 77,110   $ 82,499  

Amortization on capital leases(b)

    13,347     16,124  

Outage costs(c)

    45,527     35,155  

Interest rate swap termination fees(d)

    11,341     13,336  

Depreciation expense(f)

    47,650     48,362  

Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(g)

    29,894     27,678  

Interest rate options cost(h)

    84,224     38,984  

Deferral of effects on net margin—Smith Energy Facility(i)

    87,335     63,491  

Other regulatory assets(j)

    4,568     5,479  
           

Total Regulatory Assets

  $ 400,996   $ 331,108  

Regulatory Liabilities:

   
 
   
 
 

Accumulated retirement costs for other obligations(e)

  $ 22,325   $ 24,520  

Deferral of effects on net margin—Hawk Road Energy Facility(i)

    26,970     23,379  

Major maintenance reserve(k)

    25,748     28,064  

Deferred debt service adder(l)

    61,995     57,223  

Asset retirement obligations(e)

    32,556     19,508  

Other regulatory liabilities(j)

    6,219     6,095  
           

Total Regulatory Liabilities

  $ 175,813   $ 158,789  
           

Net Regulatory Assets

 
$

225,183
 
$

172,319
 
           
           

 

 
(a)
Represents premiums paid, together with unamortized transaction costs related to reacquired debt amortized over the period of the refunding debt, which range up to 30 years.

(b)
Represents the difference between lease payments and the aggregate of the amortization on the capital lease assets and the interest on the capital lease obligations for rate-making purposes. Recovered over the remaining terms of the leases through 2031.

(c)
Consists of both coal-fired maintenance and nuclear refueling outage costs. Coal-fired costs outages are amortized on a straight-line basis to expense over an 18 to 36-month period. Nuclear refueling outage costs are amortized on a straight-line basis to expense over the 18 to 24-month operating cycles of each unit.

(d)
Represents losses on settled interest rate swap arrangements that are being amortized through 2016 and 2019.

(e)
Represents difference in timing of recognition of the costs of decommissioning for financial statement purposes and for ratemaking purposes.

(f)
Prior to Nuclear Regulatory Commission (NRC) approval of a 20-year license extension for Plant Vogtle, we deferred the difference between Plant Vogtle depreciation expense based on the then 40-year operating license and depreciation expense assuming an expected 20-year license extension. Amortization commenced upon NRC approval of the license extension in 2009 and is being amortized over the remaining life of the plant.

(g)
Deferred charges related to Vogtle Units No. 3 and No. 4 training and interest related carrying costs of such training. Amortization will commence effective with the commercial operation date of each unit and amortized to expense over the life of the units.

(h)
Deferral of net loss associated with the change in fair value of the interest rate options to hedge interest rates on certain borrowings related to Vogtle Units No. 3 and No. 4 construction. Amortization will commence in February 2020 and will be amortized through February 2044, the life of the DOE-guaranteed loan which is financing a portion of the construction project.

(i)
Effects on net margin for Smith and Hawk Road Energy Facilities are deferred until the end of 2015 and will be amortized over the remaining life of each respective plant.

(j)
The amortization period for other regulatory assets range up to 35 years and the amortization period of other regulatory liabilities range up to 18 years.

(k)
Represents collections for future major maintenance costs; revenues are recognized as major maintenance costs when incurred.

(l)
Collections to fund debt payments in excess of depreciation expense through the end of 2025; deferred credits will be amortized over the remaining useful life of the plants.

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(K)
Member Power Bill Prepayments.    We have a power bill prepayment program pursuant to which members can prepay their power bills from us at a discount based on our avoided cost of borrowing. The prepayments are credited against the participating members' power bills in the month(s) agreed upon in advance. The discounts are credited against the power bills and are recorded as a reduction to member revenues. The prepayments are being credited against members' power bills through January 2018, with the majority of the balance scheduled to be credited by the end of 2014.
(L)
Debt.

a)
Department of Energy Loan Guarantee:

    Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005 (the "Title XVII Loan Guarantee Program"), we and the U.S. Department of Energy, acting by and through the Secretary of Energy entered into a Loan Guarantee Agreement on February 20, 2014 (the "Loan Guarantee Agreement") pursuant to which the Department of Energy agreed to guarantee our obligations (the "Department of Energy Guarantee") under the Note Purchase Agreement dated as of February 20, 2014 (the "Note Purchase Agreement"), among us, the Federal Financing Bank and the Department of Energy and the Future Advance Promissory Note No. 1 and the Future Advance Promissory Note No. 2, each dated February 20, 2014, made by us to Federal Financing Bank (the "Federal Financing Bank Notes" and together with the Note Purchase Agreement, the "FFB Credit Facility Documents"). The Federal Financing Bank Credit Facility Documents provide for a multi-advance term loan facility (the "Facility"), under which we may make term loan borrowings through Federal Financing Bank.

    Proceeds of advances made under the Facility will be used to reimburse us for a portion of certain costs of construction relating to Vogtle Units No. 3 and No. 4 that are eligible for financing under the Title XVII Loan Guarantee Program ("Eligible Project Costs"). Aggregate borrowings under the Facility may not exceed the lesser of (i) 70% of Eligible Project Costs or (ii) $3,057,069,461, $335,471,604 of which is designated for capitalized interest.

    Under the Loan Guarantee Agreement, we are obligated to reimburse the Department of Energy in the event the Department of Energy is required to make any payments to Federal Financing Bank under the Department of Energy Guarantee. Our payment obligations to Federal Financing Bank under the Federal Financing Bank Notes and reimbursement obligations to the Department of Energy under the related reimbursement notes are secured equally and ratably with all of our other notes and obligations issued under our first mortgage indenture by a lien on substantially all of our owned tangible and certain of our intangible assets, including property we acquire in the future.

    Advances.    Advances may be requested under the Facility on a quarterly basis through December 31, 2020. On February 20, 2014, we made an initial borrowing in the principal amount of $725,000,000 at a fixed interest rate of 3.867% through February 20, 2044. In connection with the receipt of these funds, we repaid a like amount of outstanding short-term obligations, which included a $260,000,000 term loan originally due April 1, 2014 and $465,000,000 of commercial paper. These outstanding obligations were classified as long-term at December 31, 2013.

    Future advances are subject to satisfaction of customary conditions, as well as certification of compliance with the requirements of the Title XVII Loan Guarantee Program, accuracy of project-related representations and warranties, delivery of updated project-related information, certification regarding Georgia Power's compliance with certain obligations relating to the Cargo Preference Act, as amended, evidence of compliance with the prevailing wage requirements of the Davis-Bacon Act, as amended, and certification from Department of Energy's consulting engineer that proceeds of the advance are used to reimburse Eligible Project Costs.

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    Maturity, Interest Rate and Amortization.    The final maturity date for each advance under the Facility is February 20, 2044. Interest is payable quarterly in arrears on February 20, May 20, August 20 and November 20 of each year. Principal and interest payments will begin on February 20, 2020. Interest accrued and payable through November 20, 2019, up to a maximum of $335,471,604, is reflected as additional borrowings under the Facility. As of June 30, 2014, $10,015,000 of interest is reflected as long-term debt on our condensed balance sheet.

    Under Future Advance Promissory Note No. 1, we may select an interest rate period applicable to each advance, with such interest rate periods ranging from three months to the final maturity date. All advances under Future Advance Promissory Note No. 2 will bear a fixed rate of interest through the final maturity date. Under both Federal Financing Bank Notes, the interest rates during the applicable interest rate periods will equal the current average yield on U.S. Treasuries of comparable maturity at the beginning of the interest rate period, plus a spread equal to 0.375%.

    In connection with our entry into the Loan Guarantee Agreement and the Federal Financing Bank Credit Facility Documents, we incurred issuance costs of approximately $51,000,000, which will be amortized over the life of the borrowings under the Facility. Issuance costs include fees paid to the Department of Energy, legal and consulting expenses and costs for compliance with certain federal requirements (including compliance with the Davis-Bacon Act).

    b)
    Rural Utilities Service Guaranteed Loans:

    For the six month period ended June 30, 2014, we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling $20,282,000 for general and environmental improvements at existing plants.

    On July 30, 2014, we received an additional $7,432,000 in advances on Rural Utilities Service-guaranteed Federal Financing Bank loans for general and environmental improvements at existing plants.

    c)
    Bond Issuance:

    On June 12, 2014, we issued $250,000,000 of 4.55% first mortgage bonds, Series 2014A primarily for the purpose of repaying outstanding commercial paper issued for the interim financing of general and environmental capital expenditures at our existing generation facilities and for general corporate purposes. The bonds are secured under our first mortgage indenture.

(M)
Purchase Agreements.    On April 11, 2014, we signed a precedent agreement with Transcontinental Gas Pipeline Company, LLC (Transco) for additional firm natural gas transportation to our Smith facility. The additional firm transportation is contingent upon the construction of a new natural gas pipeline by Transco. The agreement has a base term of 25 years, with a fixed charge of $37,700,000 per year for the base term. Our obligation to make payments begins when the pipeline expansion project is placed into service, which is projected to be May 1, 2017.

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

General

We are a Georgia electric membership corporation (an EMC) incorporated in 1974 and headquartered in metropolitan Atlanta. We are owned by our 38 retail electric distribution cooperative members. Our members are consumer-owned distribution cooperatives providing retail electric service in Georgia on a not-for-profit basis. Our principal business is providing wholesale electric power to our members through a combination of our generation assets and, to a lesser extent, power purchased from power marketers and other suppliers. As with cooperatives generally, we operate on a not-for-profit basis.

Results of Operations

For the Three and Six Months Ended June 30, 2014 and 2013

Net Margin

Our net margin for the three-month and six-month periods ended June 30, 2014 was $17.2 million and $36.4 million compared to $24.5 million and $46.5 million for the same periods of 2013. Through June 30, 2014, we collected approximately 78% of our targeted net margin of $46.8 million for the year ending December 31, 2014. This is typical as our capacity revenues are recorded evenly throughout the year and our management generally budgets conservatively. We anticipate our board of directors will approve a budget adjustment by the end of the year so that net margins will achieve, but not exceed, the targeted margins for interest ratio. For additional information regarding our net margins requirements and policy, see "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Summary of Cooperative Operations—Margins" of our 2013 Form 10-K.

Operating Revenues

Our operating revenues fluctuate from period to period based on several factors, including fuel costs, weather and other seasonal factors, load requirements in our members' service territories, operating costs, availability of electric generation resources, our decisions of whether to dispatch our owned, purchased or member-owned resources over which we have dispatch rights, and our members' decisions of whether to purchase a portion of their hourly energy requirements from our resources or from other suppliers.

Sales to Members.    Total revenues from sales to members increased 10.4% and 13.5% in the three-month and six-month periods ended June 30, 2014 compared to the same periods of 2013. Megawatt-hour sales to members increased 9.3% and 13.4% for the three-month and six-month periods ended June 30, 2014 compared to the same periods of 2013. The average total revenue per megawatt-hour from sales to members increased 1.0% and 0.1% for the three-month and six-month periods ended June 30, 2014 compared to the same periods of 2013. The increases in revenues from sales to members and in megawatt-hour sales to members in the second quarter of 2014 versus the same quarter of 2013 were driven partly by increased generation at Plant Scherer due to increased member demand and partly due to increased generation at Plant Wansley Unit No. 2 due to extensive testing of Mercury Air Toxic Standards environmental controls that were installed in early 2014. Increased member demand due to extreme cold weather during the first quarter of 2014 also contributed to the increase in sales to members for the six month period ended June 30, 2014 versus the same period of 2013.

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The components of member revenues for the three-month and six-month periods ended June 30, 2014 and 2013 were as follows (amounts in thousands except for cents per kilowatt-hour):

   

    Three Months Ended
June 30,
    Six Months Ended
June 30,
 
           

  2014     2013     2014     2013    

Capacity revenues

  $ 190,077   $ 184,261   $ 381,752   $ 365,375  

Energy revenues

    148,039     121,930     291,123     227,469  
                   

Total

  $ 338,116   $ 306,191   $ 672,875   $ 592,844  
                   
                   

Kilowatt-hours sold to members

   
5,174,273
   
4,732,825
   
10,079,497
   
8,886,487
 

Cents per kilowatt-hour

    6.53¢     6.47¢     6.68¢     6.67¢  
   

Capacity revenues from members increased 3.2% and 4.5% for the three-month and six-month periods ended June 30, 2014 compared to the same periods of 2013. Capacity revenues are the revenues we receive for electric service whether or not our generation and purchased power resources are dispatched to produce electricity and are designed to cover the fixed costs associated with our business, including fixed production expenses, depreciation and amortization expenses and interest charges, plus a targeted margin. Each member is required to pay us for capacity furnished under its wholesale power contract according to the individual fixed percentage capacity cost responsibility for each resource in which it participates. Our capacity revenues are based on the costs we expect to incur on an annual basis and are subject to adjustment by our board such that our net margins will achieve, but not exceed, the targeted margins for interest ratio.

Energy revenues were 21.4% and 28.0% higher for the three-month and six-month periods ended June 30, 2014 compared to the same periods of 2013. Our average energy revenue per megawatt-hour from sales to members increased 11.1% and 12.8% for the three-month and six-month periods ended June 30, 2014 as compared to the same periods of 2013. The increase in energy revenues for the comparable three-month periods was primarily due to an increase in higher cost coal-fired generation and higher natural gas prices. In addition to the foregoing, the increase for the comparable six-month periods was due to increased generation during the first quarter of 2014 as a result of extreme cold weather. For a discussion of total fuel costs and total generation, see "—Operating Expenses."

Sales to Non-Members.    Sales to non-members for the three-month and six-month periods ended June 30, 2014 decreased 1.6% and increased 34.7% as compared to the same periods of 2013. This increase for year-to-date 2014 as compared to the same period of 2013 was primarily due to sales of natural gas of $10.8 million during the first quarter of 2014.

Operating Expenses

Operating expenses for the three-month and six-month periods ended June 30, 2014 increased 12.5% and 18.4% as compared to the same periods of 2013. This increase was due to higher fuel costs, production costs and depreciation and amortization expenses as compared to the same periods of 2013.

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The following table summarizes our megawatt-hour generation and fuel costs by generating source.

   

    Three Months Ended
June 30,
 
       

    2014     2013  
           

Fuel Source
    Cost     Generation     Cost per
MWh
    Cost     Generation     Cost per
MWh
 
                           

    (thousands)     (MWh)           (thousands)     (MWh)        

Coal

  $ 63,661     2,017,328   $ 31.56   $ 45,167     1,490,279   $ 30.31  

Nuclear

    22,000     2,577,243     8.54     22,598     2,574,270     8.78  

Gas:

                                     

Combined Cycle

    41,382     1,026,369     40.32     41,532     1,142,648     36.35  

Combustion Turbine

    6,933     96,138     72.12     3,768     47,568     79.21  
                           

  $ 133,976     5,717,078   $ 23.43   $ 113,065     5,254,765   $ 21.52  
                           
                           

 

 

 

   

    Six Months Ended
June 30,
 
       

    2014     2013  
           

Fuel Source
    Cost     Generation     Cost per
MWh
    Cost     Generation     Cost per
MWh
 
                           

    (thousands)     (Mwh)           (thousands)     (Mwh)        

Coal

  $ 120,148     3,913,554   $ 30.70   $ 85,812     2,974,233   $ 28.85  

Nuclear

    42,766     4,803,209     8.90     40,930     4,659,362     8.78  

Gas:

                                     

Combined Cycle

    92,582     2,164,453     42.77     81,670     2,419,201     33.76  

Combustion Turbine

    10,756     118,766     90.56     4,803     64,332     74.66  
                           

  $ 266,252     10,999,982   $ 24.20   $ 213,215     10,117,128   $ 21.07  
                           
                           

 

 

For the three-month and six-month periods ended June 30, 2014, total fuel costs increased 18.5% and 24.9% and megawatt-hour generation increased 8.8% and 8.7%, respectively, compared to the same periods of 2013. Average fuel costs per megawatt-hour increased 8.9% and 14.9% in the three-month and six-month periods ended June 30, 2014 compared to the same periods of 2013. The increase in total fuel costs was partly due to higher generation from our coal-fired plants and partly due to higher natural gas prices. As discussed above, extensive testing of environmental equipment at Plant Wansley Unit No. 2 during the second quarter of 2014 increased generation in 2014 by 421,000 megawatt-hours for the six-month period ended June 30, 2014 as compared to the same period of 2013 when it was in reserve shutdown for most of the six month period primarily due to more economical generation from natural gas-fired facilities. Generation from Plant Scherer also increased 18.2% during the six-month period ended June 30, 2014 as compared to the same period of 2013 due to increased demand from our members. Generation from our gas-fired facilities decreased in the three-month and six-month periods ended June 30, 2014 versus the same periods of 2013 due primarily to lower utilization of the Smith Energy Facility; however, this was more than offset by increased natural gas prices in 2014. The extreme cold weather in the first quarter of 2014 as compared to the first quarter of 2013 also contributed to the increase in megawatt-hours of generation for the six month period ended June 30, 2014 compared to the same period of 2013.

Production costs increased 10.9% and 12.5% for the three-month and six-month periods ended June 30, 2014 as compared to the same periods of 2013. The increase in the second quarter of 2014 versus the same period of 2013 resulted primarily from higher operations and maintenance expenses at our co-owned facilities, primarily Plants Vogtle and Hatch. The increase for the six-month period ended

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June 30, 2014 as compared to the same period of 2013 resulted partly from the cost of gas sold to non-members of $6 million and partly from higher operations and maintenance costs at our co-owned facilities, primarily Plants Vogtle and Hatch.

Depreciation and amortization costs increased 7.3% and 8.5% for the three-month and six-month periods ended June 30, 2014 as compared to the same periods of 2013. The increase in depreciation expense in 2014 as compared to 2013 was primarily due to $291 million of environmental capital improvements at Plant Scherer that were primarily placed into service in May and August of 2013.

Interest charges

Interest expense increased 12.7% and 10.4% for the three-month and six-month periods ended June 30, 2014 as compared to the same periods of 2013 primarily due to increased debt to finance construction of Vogtle Units No. 3 and No. 4.

Financial Condition

Balance Sheet Analysis as of June 30, 2014

Assets

Cash used for property additions for the six-month period ended June 30, 2014 totaled $249.3 million. Of this amount, approximately $172 million was associated with construction expenditures for Vogtle Units No. 3 and No. 4, $21 million for environmental control systems being installed primarily at Plant Scherer and $35 million for nuclear fuel purchases. The remaining expenditures were for normal additions and replacements to existing generation facilities.

The $293.8 million of restricted short-term investments at June 30, 2014 represent funds deposited into a Rural Utilities Service Cushion of Credit Account with the U.S. Treasury that earns interest at a rate of 5% per annum. The funds, including interest earned thereon, can only be applied to debt service on Rural Utilities Service and Rural Utilities Service-guaranteed Federal Financing Bank notes. Decisions regarding when to apply the funds are guided by the interest rate environment and our anticipated liquidity needs.

Deferred debt expense, being amortized increased $42.6 million for the six months ended June 30, 2014 due to debt related costs associated with a $3.057 billion loan with the Department of Energy, which closed in February 2014. For additional information regarding this loan, see Note L.

Regulatory assets increased $69.9 million for the six months ending June 30, 2014. The increase was primarily due to a $45.2 million increase in the deferral of unrealized losses on, and expirations of, our interest rate options. For information regarding our interest rate options, see Note C. In addition, there was a $24.9 million increase in deferred losses related to Smith Energy Facility. The effects on net margin for Smith are being deferred until the end of 2015 at which time the amounts will be amortized over the remaining life of the facility.

Equity and Liabilities

Accounts payable decreased $24.8 million for the six-month period ended June 30, 2014 as a result of a $38.4 million in credits applied to the members' bills in the first quarter of 2014 for a board approved reduction to 2013 revenue requirements as a result of margins collected in excess of our 2013 target. Offsetting the decrease was a $12.7 million increase in natural gas purchases.

Member power bill prepayments represent funds received from the members for the prepayment of their monthly power bills. At June 30, 2014, $93.0 million of member power bill prepayments was classified as a current liability and $36.2 million was classified as a long-term liability. During the six-month period ended June 30, 2014, $27.1 million of prepayments were received from the members

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and $12.6 million was applied to the members' monthly power bills. For information regarding the power bill prepayment program, see Note K.

Capital Requirements and Liquidity and Sources of Capital

Vogtle Units No. 3 and No. 4.

We, along with Georgia Power, the Municipal Electric Authority of Georgia and the City of Dalton are participating in the construction of two Westinghouse AP1000 nuclear generating units at Plant Vogtle, each with a nominally rated generating capacity of approximately 1,100 megawatts. Our ownership interest is 30%, representing 660 megawatts of total capacity. As of June 30, 2014, our total investment in Vogtle Units No. 3 and No. 4 was $2.2 billion.

For additional information about the Vogtle construction project, see "Item 1—BUSINESS—OUR POWER SUPPLY RESOURCES—Future Power Resources—Plant Vogtle Units No. 3 and No. 4" and "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Capital Requirements—Capital Expenditures" in our 2013 Form 10-K. Also see Note G and Note L.

Environmental Regulations

The U.S. Environmental Protection Agency, or EPA, continues to develop a number of rules that significantly expand the scope of regulation of air emissions, water and waste management at power plants. Following are some of the developments that may affect future operations at our facilities.

On June 18, 2014, EPA proposed new source performance standards for existing sources the "Clean Power Plan," slated to cut carbon dioxide emissions from existing fossil fuel-fired power plants nationwide by an average of 30% from 2005 levels by 2030, with an additional interim goal for the years 2020 through 2029. For Georgia, however, the proposal would require a 44% reduction in emission rates from 2012 levels. Under the proposal, each state would have to reduce carbon dioxide emissions on a state-wide basis pursuant to state goals, determined through the application of certain "building blocks" that include plant efficiency upgrades, shifting generation from coal plants to natural gas facilities, expansions in renewable and nuclear power sources and implementation of demand-side energy efficiency programs. That same day, EPA also proposed new source performance standards for certain modified or reconstructed fossil fuel-fired power plants which, if finalized, could apply to our coal-fired facilities (Plants Scherer and Wansley) and several of our natural gas-fired power plants. EPA is scheduled to finalize the Clean Power Plan as well as the standards for modified or reconstructed sources by June 1, 2015. The outcome of the Clean Power Plan and the standards for modified or reconstructed sources rulemakings, including any subsequent challenges, cannot be determined at this time, but they could result in material compliance costs, including increased operating costs or decreased operations or both at Plants Scherer and Wansley.

On June 23, 2014, the U.S. Supreme Court issued a decision on an appeal of the original greenhouse gas rules EPA began promulgating in 2009. Among other things, those rules imposed new source review requirements on emissions of greenhouse gases, including carbon dioxide, through the Prevention of Significant Deterioration (PSD) Preconstruction Permitting Program and the Title V Operating Permit Program. The rules directly regulated new or modified larger sources of greenhouse gases, including fossil-fueled power plants. Concluding that portions of the rules were invalid, the Court ruled that EPA could not impose PSD or Title V permitting requirements on sources solely due to emissions of greenhouse gases, and that instead, EPA could regulate greenhouse gas emissions pursuant to PSD or Title V only when new or modified source emissions trigger PSD or Title V regulation for other regulated pollutants. We cannot predict the ultimate outcome of this litigation as the decision may undergo further appeal, and EPA may need to conduct further rulemaking in response to the Court's decision.

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On February 12, 2013, EPA proposed a rule that would require many states, including Georgia, to revise those portions of their State Implementation Plans (SIPs) that relate to the regulation of excess emissions at industrial facilities, including fossil fuel-fired electric generating units, during periods of startup, shut-down or malfunction (SSM). EPA's proposed determination, if finalized, would require revisions to all affected SIPs within 18 months. Recently, in litigation over this rulemaking, EPA delayed final action on the proposal until May 22, 2015. If finalized as proposed, these new rules could result in additional compliance and operational costs at our power plants.

Section 316(b) of the Clean Water Act requires that the location, design, construction and capacity of cooling water intake structures reflect the best technology available for minimizing adverse environmental impacts on fish and other aquatic life. EPA issued its final section 316(b) requirements for existing power plants and manufacturing facilities on May 19, 2014. The final rule applies to all existing facilities that withdraw at least two million gallons of water per day and that use at least 25% of such water exclusively for cooling purposes. We are in the process now of determining what modifications, if any, need to be made to our four co-owned power plants that meet the cooling water use threshold (Plants Scherer, Wansley, Vogtle and Hatch) to meet the new standards. Capital requirements for any additional controls that might be needed for compliance at any of these plants cannot be determined at this time, and the result of any litigation challenging the final rules cannot be predicted.

For further discussion regarding potential effects on our business from environmental regulations, including potential capital requirements, see "Item 2—Management's Discussion and Analysis of Financial Condition and Results of Operations—Financial Condition—Capital Requirements and Liquidity and Sources of Capital—Environmental Regulations" in our quarterly report on Form 10-Q for the quarterly period ending March 31, 2014 and "Item 1—BUSINESS—REGULATION—Environmental," "Item 1A—RISK FACTORS" and "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial ConditionCapital RequirementsCapital Expenditures" in our 2013 Form 10-K.

Liquidity

At June 30, 2014, we had $1.8 billion of unrestricted available liquidity to meet our short-term cash needs and liquidity requirements. This amount included $330 million in cash and cash equivalents and $1.5 billion of unused and available committed credit arrangements.

At June 30, 2014, we had in excess of $1.9 billion of committed credit arrangements in place and $1.5 billion available under these facilities. These six separate facilities are reflected in the table below:


 

Committed Credit Facilities


 

   

Authorized
Amount

   

Available
June 30,
2014

 

Expiration Date

 

    (dollars in millions)    

Unsecured Facilities:

               

Syndicated Line of Credit led by Bank of America

  $ 1,265   $ 934 (1) June 2015

Syndicated Line of Credit led by CoBank(2)

    150     150   September 2014

CFC Line of Credit

    110     110   September 2016

CFC Line of Credit(3)

    210     210   December 2018

JPMorgan Chase Line of Credit

    150     34 (4) December 2018

Secured Facilities:

   
 
   
 
 

 

CFC Term Loan(3)

    250     250   December 2018

 
(1)
Of the portion of this facility that was unavailable at June 30, 2014, $195.9 million was dedicated to support outstanding commercial paper and $135.5 million was related to letters of credit issued to support variable rate demand bonds. We plan to renew this facility in first quarter 2015.

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(2)
We do not plan to renew this facility when it expires on September 30, 2014.

(3)
Any amounts drawn under the $210 million unsecured line of credit with CFC will reduce the amount that can be drawn under the $250 million secured term loan. Any amounts borrowed under the $250 million term loan would be secured under our first mortgage indenture, with a maturity no later than December 31, 2043.

(4)
Of the portion of this facility that was unavailable at June 30, 2014, $113.7 million related to letters of credit issued to support variable rate demand bonds and $2.2 million related to letters of credit issued to post collateral to third parties.

As of June 30, 2014, we were using our commercial paper program to provide interim funding for 1) the monthly payments related to the construction of Vogtle Units No. 3 and No. 4 prior to receiving advances of permanent funding under the Department of Energy-guaranteed Federal Financing Bank loan, which can be requested no more frequently than quarterly and 2) the premium payments made in connection with our interest rate hedging program. Between our credit arrangements and projected cash on hand, we believe we have sufficient liquidity to cover our normal operations and to provide for the interim financings described above.

Under our commercial paper program, we are authorized to issue commercial paper in amounts that do not exceed the amount of any committed backup lines of credit, thereby providing 100% dedicated support for any commercial paper outstanding.

Under our unsecured committed lines of credit, we have the ability to issue letters of credit totaling $1.045 billion in the aggregate, of which $794 million remained available at June 30, 2014. However, amounts related to issued letters of credit reduce the amount that would otherwise be available to draw for working capital needs. Also, due to the requirement to have 100% dedicated backup for any commercial paper outstanding, any amounts drawn under our committed credit facilities for working capital or related to issued letters of credit will reduce the amount of commercial paper that we can issue. The majority of our outstanding letters of credit are for the purpose of providing credit enhancement on variable rate demand bonds.

Several of our credit facilities contain a financial covenant that requires us to maintain minimum levels of patronage capital. At June 30, 2014, the required minimum level was $675 million and our actual patronage capital was $751 million. Additional covenants contained in several of our credit facilities limit our secured indebtedness and unsecured indebtedness, both as defined in the credit agreements, to $12.0 billion and $4.0 billion, respectively. At June 30, 2014, we had $7.3 billion of secured indebtedness and $196 million of unsecured indebtedness outstanding, which was well within the covenant thresholds.

At June 30, 2014, our current assets included $293.9 million of restricted short-term investments pursuant to deposits made into a Rural Utilities Service Cushion of Credit Account. See "—Balance Sheet Analysis as of June 30, 2014—Assets" for more information regarding this account.

Financing Activities

First Mortgage Indenture.    At June 30, 2014, we had $7.2 billion of long-term debt outstanding under our first mortgage indenture secured equally and ratably by a lien on substantially all of our owned tangible and certain of our intangible property, including property we acquire in the future. See "Item 1—BUSINESSOGLETHORPE POWER CORPORATION—First Mortgage Indenture" in our 2013 Form 10-K for further discussion of our first mortgage indenture.

Rural Utilities Service-Guaranteed Loans.    We currently have four approved Rural Utilities Service-guaranteed loans, totaling $871 million, which are being funded through the Federal Financing Bank and are in various stages of being drawn down, with $441 million remaining to be advanced. When advanced, the debt will be secured under our first mortgage indenture.

Department of Energy-Guaranteed Loan.    In February 2014, we closed on a loan with the Department of Energy that will fund up to the lesser of $3.057 billion or 70% of eligible project costs related to the

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cost to construct our 30% undivided share of Vogtle Units No. 3 and No. 4. This loan is being funded by the Federal Financing Bank and is backed by a federal loan guarantee provided by the Department of Energy.

As of June 30, 2014, our total investment in Vogtle Units No. 3 and No. 4 was $2.2 billion and we have incurred $2.1 billion of debt to provide long-term financing for this investment. This long-term debt includes $1.4 billion of taxable first mortgage bonds we previously issued and $735 million, including capitalized interest, under the Department of Energy loan facility. The facility may be used until no later than December 2020 to provide long-term funding for up to 70% of eligible project costs after they are incurred. As of June 30, 2014, we have the capacity to fund an additional $730 million under the facility based on the amount of eligible project costs we have incurred to date. We anticipate making draws under the facility on at least a semi-annual basis to meet our funding requirements as construction progresses. When advanced, the debt will be secured under our first mortgage indenture. For additional information regarding this loan, see Note L.

Bond Financing.

On June 12, 2014, we issued $250 million of Series 2014A first mortgage bonds to provide long-term financing for general and environmental improvements to certain of our existing facilities and for general corporate purposes.

For more detailed information regarding our financing plans, see "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Financing Activities" in our 2013 Form 10-K.

Newly Adopted or Issued Accounting Standards

For a discussion of recently issued or adopted accounting pronouncements, see Note E of Notes to Unaudited Condensed Financial Statements.

Item 3.    Quantitative and Qualitative Disclosures About Market Risk

There have not been any material changes to market risks from those reported in "Item 7A—QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK" of our 2013 Form 10-K.

Item 4.    Controls and Procedures

As of June 30, 2014, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended. Based on this evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures are effective.

There have been no changes in internal control over financial reporting or other factors that occurred during the quarter ended June 30, 2014 that have materially affected, or are reasonably likely to affect, our internal control over financial reporting.

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PART II—OTHER INFORMATION

Item 1.    Legal Proceedings

Vogtle Units No. 3 and No. 4

In April 2008, Georgia Power Company, acting for itself and as agent for us, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia (collectively, the Co-owners), and Westinghouse Electric Company LLC and Stone & Webster, Inc. (collectively, the Contractor) entered into an engineering, procurement, and construction agreement to design, engineer, procure, and construct two AP1000 nuclear units with electric generating capacity of approximately 1,100 megawatts each and related facilities, structures, and improvements at Plant Vogtle (Vogtle Units No. 3 and No. 4).

Under the agreement, the Co-Owners and the Contractor have established both informal and formal dispute resolution procedures in order to resolve issues arising during the course of constructing a project of this magnitude. Georgia Power, on behalf of the Co-owners, has successfully initiated both formal and informal claims through these procedures, including ongoing claims. When matters are not resolved through these procedures, the parties may proceed to litigation. The Contractor and the Co-owners are involved in litigation with respect to certain claims that have not been resolved through the formal dispute resolution process.

Current litigation relates to costs associated with design changes to the Westinghouse AP1000 Design Control Document (DCD) and costs associated with delays in the project schedule related to the timing of approval of the DCD and issuance of the combined construction permits and operating licenses by the Nuclear Regulatory Commission. In July 2012, the Co-owners and Contractor began negotiations regarding these costs, including the assertion by the Contractor that the Co-owners are responsible for these costs under the terms of the agreement. On November 1, 2012, the Co-owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia, seeking a declaratory judgment that the Co-owners are not responsible for these costs. Also on November 1, 2012, the Contractor filed suit against the Co-owners in the U.S. District Court for the District of Columbia alleging the Co-owners are responsible for these costs. In August 2013, the U.S. District Court for the District of Columbia dismissed the Contractor's suit, ruling that proper venue is the U.S. District Court for the Southern District of Georgia. In September 2013, the Contractor appealed the decision to the U.S. Court of Appeals for the District of Columbia.

The portion of the additional costs claimed by the Contractor in its initial complaint that would be attributable to us, based on our ownership interest, was approximately $280 million in 2008 dollars with respect to these issues. The Contractor has also asserted that it is entitled to further schedule extensions. On May 22, 2014, the Contractor filed an amended counterclaim to the lawsuit pending in the Southern District of Georgia alleging that (i) the design changes to the DCD imposed by the Nuclear Regulatory Commission have delayed module production and the impacts to the Contractor are recoverable by the Contractor under the agreement and (ii) the changes to the basemat rebar design required by the Nuclear Regulatory Commission caused additional costs and delays recoverable by the Contractor under the agreement. The Contractor did not specify in its amended counterclaim claimed amounts relating to these new allegations but such claimed amounts could be substantial. Georgia Power, on behalf of the Co-owners, has not agreed with either the proposed cost or schedule adjustments or that the Co-owners have any responsibility for costs related to these issues.

While litigation is ongoing and Georgia Power and the Co-owners intend to vigorously defend their positions, Georgia Power and the Co-owners also expect negotiations with the Contractor to continue with respect to cost and schedule during which time the parties will attempt to reach a mutually acceptable compromise of their positions. Management does not anticipate that the liabilities, if any, for these proceedings will have a material effect on our financial condition or results of operations. However, at this time, the ultimate outcome of this litigation cannot be determined. Additional claims

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by the Contractor or Georgia Power, on behalf of the Co-owners, are also likely to arise throughout construction.

For further information regarding the two additional units at Plant Vogtle, see "Item 1—BUSINESS—OUR POWER SUPPLY RESOURCES—Future Power Resources—Plant Vogtle Units No. 3 and No. 4" in our 2013 Form 10-K and "Management's Discussion and Analysis of Financial Condition and Results of Operations and Financial Condition—Capital Requirements and Liquidity and Sources of Capital—Vogtle Units No. 3 and No. 4" in our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2014, filed with the SEC on May 12, 2014.

Patronage Capital Litigation

On March 13, 2014, a lawsuit was filed in the Superior Court of DeKalb County, Georgia, against us, Georgia Transmission and three of our member distribution cooperatives. Plaintiffs filed an amended complaint on July 28, 2014. The amended complaint challenges the patronage capital distribution practices of Georgia's electric cooperatives and seeks to certify a defendant class of all but one of our 38 members. It was filed by four former consumer-members of four of our members on behalf of themselves and a proposed class of all former consumer-members of our members. Plaintiffs claim that approximately 30% of all the defendants' total allocated patronage capital belongs to former consumer-members. Plaintiffs also allege that patronage capital owed to former consumer-members includes patronage capital allocated by us to our members but not yet distributed to our members. Plaintiffs claim that the patronage capital of former consumer-members held by defendants and the proposed defendant class should be retired immediately when the consumer-members end their membership by terminating service, or alternatively, according to a revolving schedule of no longer than 13 years from the date of its allocation and seek relief to effect such retirements. Plaintiffs further seek to require the defendants to adjust rates in order to establish and maintain reasonable reserves to fund patronage capital retirements on this basis. Plaintiffs also claim that defendants and the proposed defendant class should be required to adopt policies to periodically retire the patronage capital of all consumer-members on a revolving schedule of no longer than 13 years from the date of its allocation. Our first mortgage indenture restricts our ability to distribute patronage capital. See "Item 1—BUSINESS—OGLETHORPE POWER CORPORATION—First Mortgage Indenture" in our 2013 Form 10-K. Although not expected, if we were ordered by the Court to make distributions of our patronage capital, our first mortgage indenture would require us to raise our rates to a level sufficient so that we could comply with the current patronage capital restrictions, and the rate increases required to meet the Plaintiffs' demands would be significant for a period of years.

We intend to defend vigorously against all claims in this litigation. While the ultimate outcome of this litigation cannot be predicted at this time, management does not anticipate that the ultimate liabilities, if any, arising from this proceeding would have a material effect on our financial condition or results of operations.

Item 1A.    Risk Factors

Except as discussed below, there have been no material changes from the risks disclosed in "Item 1A—RISK FACTORS" of our 2013 Form 10-K.

    We cannot predict the outcome of legal proceedings related to our business activities.

From time to time we are subject to litigation from various parties, the most significant of which are described under the heading "Legal Proceedings" in this quarterly report. Our business, financial condition, and results of operations may be materially affected by adverse results of certain litigation. Unfavorable resolution of legal proceedings in which we are involved or other future legal proceedings could require significant expenditures that could have the effect of increasing the cost of electric service

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we provide to our members and, as a result, affect our members' ability to perform their contractual obligations to us.

Item 2.    Unregistered Sales of Equity Securities and Use of Proceeds

Not Applicable.

Item 3.    Defaults upon Senior Securities

Not Applicable.

Item 4.    Mine Safety Disclosures

Not Applicable.

Item 5.    Other Information

Not Applicable.

Item 6.    Exhibits

Number  
Description
  31.1   Rule 13a-14(a)/15d-14(a) Certification, by Michael L. Smith (Principal Executive Officer).

 

31.2

 

Rule 13a-14(a)/15d-14(a) Certification, by Elizabeth B. Higgins (Principal Financial Officer).

 

32.1

 

Certification Pursuant to 18 U.S.C. 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Michael L. Smith (Principal Executive Officer).

 

32.2

 

Certification Pursuant to 18 U.S.C. 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Elizabeth B. Higgins (Principal Financial Officer).

 

101

 

XBRL Interactive Data File.

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SIGNATURES

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.

        Oglethorpe Power Corporation
(An Electric Membership Corporation)

Date: August 11, 2014

 

By:

 

/s/ Michael L. Smith
Michael L. Smith
President and Chief Executive Officer

Date: August 11, 2014

 

 

 

/s/ Elizabeth B. Higgins
Elizabeth B. Higgins
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)

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