Company Quick10K Filing
Quick10K
Oglethorpe Power
10-Q 2019-06-30 Quarter: 2019-06-30
10-Q 2019-03-31 Quarter: 2019-03-31
10-K 2018-12-31 Annual: 2018-12-31
10-Q 2018-09-30 Quarter: 2018-09-30
10-Q 2018-06-30 Quarter: 2018-06-30
10-Q 2018-03-31 Quarter: 2018-03-31
10-K 2017-12-31 Annual: 2017-12-31
10-Q 2017-09-30 Quarter: 2017-09-30
10-Q 2017-06-30 Quarter: 2017-06-30
10-Q 2017-03-31 Quarter: 2017-03-31
10-K 2016-12-31 Annual: 2016-12-31
10-Q 2016-09-30 Quarter: 2016-09-30
10-Q 2016-06-30 Quarter: 2016-06-30
10-Q 2016-03-31 Quarter: 2016-03-31
10-K 2015-12-31 Annual: 2015-12-31
10-Q 2015-09-30 Quarter: 2015-09-30
10-Q 2015-06-30 Quarter: 2015-06-30
10-Q 2015-03-31 Quarter: 2015-03-31
10-K 2014-12-31 Annual: 2014-12-31
10-Q 2014-09-30 Quarter: 2014-09-30
10-Q 2014-06-30 Quarter: 2014-06-30
10-Q 2014-03-31 Quarter: 2014-03-31
10-K 2013-12-31 Annual: 2013-12-31
8-K 2019-08-28 Regulation FD, Exhibits
8-K 2019-05-21 Regulation FD, Exhibits
8-K 2019-04-10 Regulation FD, Exhibits
8-K 2019-03-22 Enter Agreement, Off-BS Arrangement, Exhibits
8-K 2019-03-07 Enter Agreement, Exhibits
8-K 2019-02-18 Enter Agreement, Exhibits
8-K 2018-11-14 Regulation FD, Exhibits
8-K 2018-10-24 Enter Agreement, Off-BS Arrangement
8-K 2018-10-18 Other Events
8-K 2018-09-26 Enter Agreement, Other Events, Exhibits
8-K 2018-09-08 Officers
8-K 2018-09-07 Enter Agreement, Other Events, Exhibits
8-K 2018-08-16 Regulation FD, Exhibits
8-K 2018-05-31 Regulation FD, Exhibits
8-K 2018-04-09 Regulation FD, Exhibits
TTCM Tautachrome 34
AUSI Aura Systems 21
ONS Oncobiologics 19
ENDV Endonovo Therapeutics 6
ALYE Aly Energy Services 2
GOVX Geovax Labs 0
PNAT Pura Naturals 0
APXR Apex Resources 0
SBP SB Partners 0
PCKK Pocket Shot 0
OPC 2019-06-30
Part I-Financial Information
Item 1. Financial Statements
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Item 4. Controls and Procedures
Part Ii-Other Information
Item 1. Legal Proceedings
Item 1A. Risk Factors
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Item 3. Defaults Upon Senior Securities
Item 4. Mine Safety Disclosures
Item 5. Other Information
Item 6. Exhibits
EX-31.1 a2239466zex-31_1.htm
EX-31.2 a2239466zex-31_2.htm
EX-32.1 a2239466zex-32_1.htm
EX-32.2 a2239466zex-32_2.htm

Oglethorpe Power Earnings 2019-06-30

OPC 10Q Quarterly Report

Balance SheetIncome StatementCash Flow

10-Q 1 a2239466z10-q.htm 10-Q

Use these links to rapidly review the document
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, 2019

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. 333-192954

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

(Address of principal executive offices)

 


30084-5336

(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 every Interactive Data File required to be submitted 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 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, a smaller reporting company, or an emerging growth company. See definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated Filer o    Accelerated Filer o    Non-Accelerated Filer ý    Smaller Reporting Company o    Emerging Growth Company o

        If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. 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

        Securities registered pursuant to Section 12(b) of the Act:

Title of each class:   Trading Symbol(s)   Name of each exchange on which registered:
None   N/A   N/A

        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.

   


Table of Contents


OGLETHORPE POWER CORPORATION
INDEX TO QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED JUNE 30, 2019

 
   
  Page No.
PART I—FINANCIAL INFORMATION    

Item 1.

 

Financial Statements

 
1

 

Unaudited Consolidated Balance Sheets as of June 30, 2019 and December 31, 2018

 
1

 

Unaudited Consolidated Statements of Revenues and Expenses For the Three and Six Months ended June 30, 2019 and 2018

 
3

 

Unaudited Consolidated Statements of Patronage Capital and Membership Fees For the Three and Six Months ended June 30, 2019 and 2018

 
4

 

Unaudited Consolidated Statements of Cash Flows For the Six Months ended June 30, 2019 and 2018

 
5

 

Notes to Unaudited Consolidated Financial Statements

 
6

Item 2.

 

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

 
27

Item 3.

 

Quantitative and Qualitative Disclosures About Market Risk

 
34

Item 4.

 

Controls and Procedures

 
35

PART II—OTHER INFORMATION

 

 

Item 1.

 

Legal Proceedings

 
36

Item 1A.

 

Risk Factors

 
36

Item 2.

 

Unregistered Sales of Equity Securities and Use of Proceeds

 
36

Item 3.

 

Defaults Upon Senior Securities

 
36

Item 4.

 

Mine Safety Disclosures

 
36

Item 5.

 

Other Information

 
36

Item 6.

 

Exhibits

 
37

SIGNATURES

 

38

i


Table of Contents


CAUTIONARY STATEMENT REGARDING

FORWARD-LOOKING STATEMENTS

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 future capital expenditures, business strategy, regulatory actions, 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 "Item 1A—RISK FACTORS" and in other sections of our annual report on Form 10-K for the fiscal year ended December 31, 2018 and in this quarterly report on Form 10-Q. 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 capital improvement and construction projects, in particular, the construction of two additional nuclear units at Plant Vogtle;

    a decision by Georgia Power Company to cancel the additional Vogtle units or a decision by more than 10% of the co-owners of the additional Vogtle units not to proceed with the construction of the additional Vogtle units upon the occurrence of certain material adverse events;

    decisions made by the Georgia Public Service Commission in the regulatory process related to the two additional units at Plant Vogtle;

    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;

    our continued ability to receive advances under the U.S. Department of Energy loan guarantee agreement for construction of two additional nuclear units at Plant Vogtle;

    the occurrence of certain events that give the Department of Energy the option to require that we repay all amounts outstanding under the loan guarantee agreement with the Department of Energy over a five-year period and the Department of Energy's decision to require such repayment;

    the continued availability of funding from the Rural Utilities Service;

    increasing debt caused by significant capital expenditures;

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

ii


Table of Contents

    actions by credit rating agencies;

    commercial banking and financial market conditions;

    the impact of regulatory or legislative responses to climate change initiatives or efforts to reduce greenhouse gas emissions, including carbon dioxide;

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

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

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

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

    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;

    changes in technology available to and utilized by us, our competitors, or residential or commercial consumers in our members' service territories, including from the development and deployment of distributed generation and energy storage technologies;

    the inability of counterparties to meet their obligations to us, including failure to perform under agreements;

    litigation or legal and administrative proceedings and settlements;

    our members' ability to perform their obligations to us;

    our members' ability to offer their residential, commercial and industrial customers competitive rates;

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

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

    general economic conditions;

    weather conditions and other natural phenomena;

    unanticipated changes in interest rates or rates of inflation;

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

    significant changes in critical accounting policies material to us;

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

    other factors discussed elsewhere in this quarterly report and in other reports we file with the SEC.

iii


Table of Contents

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

Oglethorpe Power Corporation
Consolidated Balance Sheets (Unaudited)
June 30, 2019 and December 31, 2018

    (dollars in thousands)  

 

2019  

  2018    

Assets

             

Electric plant:

             

In service

  $ 9,177,193   $ 8,981,238  

Right-of-use assets—finance leases

    302,732     302,732  

Less: Accumulated provision for depreciation

    (4,755,050 )   (4,544,405 )

    4,724,875     4,739,565  

Nuclear fuel, at amortized cost

   
356,113
   
358,358
 

Construction work in progress

    4,224,456     3,866,042  

Total electric plant

    9,305,444     8,963,965  

Investments and funds:

   
 
   
 
 

Nuclear decommissioning trust fund

    478,976     420,818  

Investment in associated companies

    75,913     77,037  

Long-term investments

    189,354     164,125  

Restricted investments

    518,991     503,158  

Other

    24,622     24,259  

Total investments and funds

    1,287,856     1,189,397  

Current assets:

   
 
   
 
 

Cash and cash equivalents

    410,556     752,618  

Restricted short-term investments

    112,500     150,000  

Receivables

    188,835     153,647  

Inventories, at average cost

    274,333     259,087  

Prepayments and other current assets

    12,436     8,098  

Total current assets

    998,660     1,323,450  

Deferred charges:

   
 
   
 
 

Regulatory assets

    780,740     655,063  

Prepayments to Georgia Power

    33,441     29,459  

Other

    18,533     21,934  

Total deferred charges

    832,714     706,456  

Total assets

  $ 12,424,674   $ 12,183,268  

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

1


Table of Contents

Oglethorpe Power Corporation
Consolidated Balance Sheets (Unaudited)
June 30, 2019 and December 31, 2018

    (dollars in thousands)  

 

2019  

  2018    

Equity and Liabilities

             

Capitalization:

   
 
   
 
 

Patronage capital and membership fees

  $ 995,265   $ 962,286  

Long-term debt

    8,875,366     8,727,148  

Obligation under finance leases

    78,771     81,730  

Other

    24,771     21,428  

Total capitalization

    9,974,173     9,792,592  

Current liabilities:

   
 
   
 
 

Long-term debt and finance leases due within one year

    232,856     522,289  

Short-term borrowings

    354,464      

Accounts payable

    149,057     206,577  

Accrued interest

    85,572     60,971  

Member power bill prepayments, current

    124,710     224,957  

Other current liabilities

    59,488     49,465  

Total current liabilities

    1,006,147     1,064,259  

Deferred credits and other liabilities:

   
 
   
 
 

Asset retirement obligations

    1,045,285     1,017,563  

Member power bill prepayments, non-current

    76,700     54,750  

Regulatory liabilities

    285,801     218,998  

Other

    36,568     35,106  

Total deferred credits and other liabilities

    1,444,354     1,326,417  

Total equity and liabilities

  $ 12,424,674   $ 12,183,268  

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

2


Table of Contents

Oglethorpe Power Corporation
Consolidated Statements of Revenues and Expenses (Unaudited)
For the Three and Six Months Ended June 30, 2019 and 2018

    (dollars in thousands)  

 

Three Months  

 

Six Months  

 

  2019     2018     2019     2018    

Operating revenues:

                         

Sales to Members

  $ 358,736   $ 365,811   $ 715,206   $ 739,212  

Sales to non-Members

    124     110     254     355  

Total operating revenues

    358,860     365,921     715,460     739,567  

Operating expenses:

                         

Fuel

    111,450     122,144     210,442     242,591  

Production

    105,584     101,891     208,904     203,163  

Depreciation and amortization

    60,334     56,841     122,638     113,629  

Purchased power

    16,635     14,761     32,699     30,649  

Accretion

    13,145     9,435     23,033     18,756  

Total operating expenses

    307,148     305,072     597,716     608,788  

Operating margin

    51,712     60,849     117,744     130,779  

Other income:

   
 
   
 
   
 
   
 
 

Investment income

    14,250     14,719     30,985     28,683  

Other

    (886 )   1,643     942     3,617  

Total other income

    13,364     16,362     31,927     32,300  

Interest charges:

   
 
   
 
   
 
   
 
 

Interest expense

    99,729     93,856     201,177     184,427  

Allowance for debt funds used during construction

    (46,910 )   (36,981 )   (90,337 )   (72,081 )

Amortization of debt discount and expense

    2,874     3,051     5,852     6,049  

Net interest charges

    55,693     59,926     116,692     118,395  

Net margin

  $ 9,383   $ 17,285   $ 32,979   $ 44,684  

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

3


Table of Contents

Oglethorpe Power Corporation
Consolidated Statements of Patronage Capital and Membership Fees (Unaudited)
For the Three and Six Months Ended June 30, 2019 and 2018

    (dollars in
thousands)
 

Balance at December 31, 2017

  $ 911,087  

Net margin

    27,399  

Balance at March 31, 2018

  $ 938,486  

Net margin

    17,285  

Balance at June 30, 2018

  $ 955,771  

Balance at December 31, 2018

 
$

962,286
 

Net margin

    23,596  

Balance at March 31, 2019

  $ 985,882  

Net margin

    9,383  

Balance at June 30, 2019

  $ 995,265  

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

4


Table of Contents

Oglethorpe Power Corporation
Consolidated Statements of Cash Flows (Unaudited)
For the Six Months Ended June 30, 2019 and 2018

    (dollars in thousands)  

 

2019  

  2018    

Cash flows from operating activities:

             

Net margin

  $ 32,979   $ 44,684  

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

             

Depreciation and amortization, including nuclear fuel

    185,318     184,323  

Accretion cost

    23,033     18,756  

Amortization of deferred gains

    (894 )   (894 )

Allowance for equity funds used during construction

    (427 )   (450 )

Deferred outage costs

    (22,470 )   (12,411 )

(Gain) loss on sale of investments

    (2,346 )   3,152  

Regulatory deferral of costs associated with nuclear decommissioning

    (12,764 )   (13,966 )

Other

    1,282     (2,637 )

Change in operating assets and liabilities:

             

Receivables

    (32,090 )   (7,254 )

Inventories

    (15,246 )   2,460  

Prepayments and other current assets

    (4,564 )   (518 )

Accounts payable

    (50,361 )   (25,517 )

Accrued interest

    24,601     6,161  

Accrued taxes

    22,916     1,269  

Other current liabilities

    (26,402 )   (7,600 )

Member power bill prepayments

    (78,297 )   12,239  

Other

    23,680     6,188  

Total adjustments

    34,969     163,301  

Net cash provided by operating activities

    67,948     207,985  

Cash flows from investing activities:

             

Property additions

    (581,140 )   (561,033 )

Activity in nuclear decommissioning trust fund—Purchases

    (180,121 )   (262,959 )

                                                 —Proceeds

    176,037     259,092  

Decrease in restricted investments

    21,667     77,809  

Activity in other long-term investments—Purchases

    (100,502 )   (102,715 )

                                                      —Proceeds

    88,085     90,329  

Other

    (2,940 )   10,473  

Net cash used in investing activities

    (578,914 )   (489,004 )

Cash flows from financing activities:

             

Long-term debt proceeds

    657,986     236,200  

Long-term debt payments

    (391,206 )   (77,234 )

(Decrease) increase in short-term borrowings, net

    (82,162 )   247,395  

Other

    (15,714 )   1,837  

Net cash provided by financing activities

    168,904     408,198  

Net (decrease) increase in cash and cash equivalents

    (342,062 )   127,179  

Cash and cash equivalents at beginning of period

    752,618     397,695  

Cash and cash equivalents at end of period

  $ 410,556   $ 524,874  

Supplemental cash flow information:

             

Cash paid for—

             

Interest (net of amounts capitalized)

  $ 85,512   $ 104,670  

Supplemental disclosure of non-cash investing and financing activities:

             

Change in asset retirement obligations

  $ 4,830   $ 2,404  

Accrued property additions at end of period

  $ 108,258   $ 141,338  

Interest paid-in-kind

  $ 35,549   $ 29,072  

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

5


Table of Contents

Oglethorpe Power Corporation
Notes to Unaudited Consolidated Financial Statements

(A)
General.    The consolidated 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-month and six-month periods ended June 30, 2019 and 2018. Examples of estimates used include items related to (i) our asset retirement obligations, such as closure and post-closure cost estimates, timing of expenditures, escalation factors and discount rates, and (ii) revenue recognition, such as determining the nature and timing of satisfaction of performance obligations, determining the standalone selling price of performance obligations and variable consideration. Actual results may differ from those estimates. 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 current year presentation.

    These unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and the notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018, as filed with the SEC. The results of operations for the three- and six-month periods ended June 30, 2019 are not necessarily indicative of results to be expected for the full year. As noted in our 2018 Form 10-K, our revenues consist primarily of sales to our 38 electric distribution cooperative members and, thus, the receivables on the consolidated balance sheets are principally from our members. See "Notes to Consolidated Financial Statements" in our 2018 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

6


Table of Contents

        result in management's best estimate of fair value. Level 3 financial instruments are those whose fair value is based on significant unobservable inputs.

    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, 2019 and December 31, 2018.

 

Fair Value Measurements at Reporting Date Using  

 

   

June 30, 2019

   

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

  $ 161,570   $ 161,570   $   $  

International equity trust

    90,317         90,317      

Corporate bonds and debt

    60,809         60,809      

US Treasury securities

    51,422     51,422          

Mortgage backed securities

    54,478         54,478      

Domestic mutual funds

    51,820     51,820          

Municipal bonds

    316         316      

Federal agency securities

    2,541         2,541      

Non-US Gov't bonds & private placements

    265         265      

Other

    5,438     5,438          

Long-term investments:

                         

International equity trust

    21,734         21,734      

Corporate bonds and debt

    15,861         15,861      

US Treasury securities

    12,792     12,792          

Mortgage backed securities

    9,867         9,867      

Domestic mutual funds

    89,879     89,879          

Federal agency securities

    767         767      

Treasury STRIPS

    36,043         36,043      

Other

    2,411     2,411          

Natural gas swaps

    23,000         23,000      

                         

7


Table of Contents


   

 

Fair Value Measurements at Reporting Date Using  

 

   

December 31,
2018

   

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

  $ 136,196   $ 136,196   $   $  

International equity trust

    76,852         76,852      

Corporate bonds and debt

    51,356         48,853     2,503  

US Treasury securities

    47,712     47,712          

Mortgage backed securities

    56,004         56,004      

Domestic mutual funds

    43,359     43,359          

Municipal bonds

    278         278      

Federal agency securities

    6,066         6,066      

Non-US Gov't bonds & private placements

    964         964      

Other

    2,031     2,031          

Long-term investments:

                         

International equity trust

    17,382         17,382      

Corporate bonds and debt

    12,571         11,366     1,205  

US Treasury securities

    12,062     12,062          

Mortgage backed securities

    11,517         11,517      

Domestic mutual funds

    94,494     94,494          

Federal agency securities

    941         941      

Treasury STRIPS

    14,113         14,113      

Other

    1,045     1,045          

Natural gas swaps

    13,154         13,154      

                         

    The Level 2 investments above in corporate bonds and debt, federal agency mortgage backed securities, and mortgage 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.

    The Level 3 investments above in corporate bonds and debt consist of investments in bank loans which are not exchanged traded. Although these securities may be liquid and priced daily, their inputs are not observable.

8


Table of Contents

    The following table presents the changes in Level 3 assets measured at fair value on a recurring basis during the three and six months ended June 30, 2019 and 2018.

 

Three Months Ended
June 30, 2019
 

 

   

Corporate bonds and debt

 

    (dollars in thousands)  

Assets (Liabilities):

       

Balance at March 31, 2019

  $ 1,317  

Total gains or losses (realized/unrealized):

       

Included in earnings (or changes in net assets)

    8  

Liquidations

    (1,325 )

Balance at June 30, 2019

  $  

       

 

 

Six Months Ended
June 30, 2019
 

 

   

Corporate bonds and debt

 

    (dollars in thousands)  

Assets (Liabilities):

       

Balance at December 31, 2018

  $ 3,708  

Total gains or losses (realized/unrealized):

       

Included in earnings (or changes in net assets)

    94  

Liquidations

    (3,802 )

Balance at June 30, 2019

  $  

       

 

 

Three Months Ended
June 30, 2018
 

 

   

Corporate bonds and debt

 

    (dollars in thousands)  

Assets (Liabilities):

       

Balance at March 31, 2018

  $ 3,807  

Transfers to Level 3

    1,190  

Total gains or losses (realized/unrealized):

       

Included in earnings (or changes in net assets)

     

Balance at June 30, 2018

  $ 4,997  

       

9


Table of Contents


 

Six Months Ended
June 30, 2018
 

 

   

Corporate bonds and debt

 

    (dollars in thousands)  

Assets (Liabilities):

       

Balance at December 31, 2017

  $  

Transfers to Level 3

    4,997  

Total gains or losses (realized/unrealized):

       

Included in earnings (or changes in net assets)

     

Balance at June 30, 2018

  $ 4,997  

       

    The estimated fair values of our long-term debt, including current maturities at June 30, 2019 and December 31, 2018 were as follows (in thousands):

   

2019

   

2018

 

    Carrying
Value
    Fair
Value
    Carrying
Value
    Fair
Value
 

Long-term debt

  $ 9,213,008   $ 10,522,766   $ 9,347,307   $ 9,837,254  

                         

    The estimated fair value of 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). The valuations for the first mortgage bonds and the pollution control revenue bonds were obtained from a third party data reporting 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, 2019 plus an applicable spread, which reflects our borrowing rate for new loans of this type from the Federal Financing Bank. The rates on the CFC debt are fixed and the valuation is based on rate quotes provided by CFC.

    For cash and cash equivalents, and receivables, the carrying amount approximates fair value because of the short-term maturity of those instruments. Restricted investments consist of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account and the carrying amount of these investments approximates fair value because of the liquid nature of the deposits with the U.S. Treasury.

(C)
Derivative Instruments.    We use commodity trading derivatives to manage our exposure to fluctuations in the market price of natural gas. Our risk management and compliance committee provides general oversight over all derivative activities. We do not apply hedge accounting to derivative transactions, but instead apply regulated operations accounting. Consistent with our rate-making, unrealized gains or losses on our natural gas swaps are reflected as regulatory assets or liabilities, as appropriate. Realized gains and losses on natural gas swaps are included in fuel expense within our consolidated statements of revenues and expenses and, therefore, net margins within our consolidated statements of cash flows.

10


Table of Contents

    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 could cause us to have credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations, we could suffer a financial loss. However, as of June 30, 2019, 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 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.

    Under the 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, 2019 and December 31, 2018, the estimated fair values of our natural gas contracts were net liabilities of approximately $23,000,000 and $13,154,000, respectively.

    As of June 30, 2019 and December 31, 2018, neither we nor any counterparties were required to post credit support or collateral under the natural gas swap agreements. If the credit-risk-related contingent features underlying these agreements were triggered on June 30, 2019 due to our credit rating being downgraded below investment grade, we would have been required to post collateral or letters of credit of $23,000,000 with our counterparties.

11


Table of Contents

    The following table reflects the notional volume of our natural gas derivatives as of June 30, 2019 that is expected to settle or mature each year:

Year

   

Natural Gas Swaps
(MMBTUs)
(in millions)

 

2019

    14.2  

2020

    23.9  

2021

    21.7  

2022

    15.0  

2023

    9.9  

2024

    4.7  

Total

    89.4  

    The table below reflects the fair value of derivative instruments and their effect on our consolidated balance sheets at June 30, 2019 and December 31, 2018.

 

Balance Sheet
Location

   

Fair Value

 

        2019     2018  

 

 

   

(dollars in thousands)

 

Assets:

                 

Natural gas swaps

  Other current assets   $   $ 226  

Liabilities:

 

 

   
 
   
 
 

Natural gas swaps

  Other current liabilities   $ 10,709   $ 2,066  

Natural gas swaps

  Other deferred credits   $ 12,291   $ 11,314  

    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, 2019 and 2018.

 

Statement of
Revenues and
Expenses
Location

   

Three months
ended
June 30,

   

Six months
ended
June 30,

 

       

2019

   

2018

   

2019

   

2018

 

        (dollars in thousands)  

Natural Gas Swaps gains

  Fuel   $ 11   $ 359   $ 224   $ 1,751  

Natural Gas Swaps losses

  Fuel     (1,126 )   (111 )   (1,799 )   (859 )

Total

      $ (1,115 ) $ 248   $ (1,575 ) $ 892  

    The following table presents the unrealized losses on derivative instruments deferred on the balance sheet at June 30, 2019 and December 31, 2018.

 

Balance Sheet
Location

   

2019

   

2018

 

        (dollars in thousands)  

Natural gas swaps

  Regulatory asset   $ 23,000   $ 13,154  

Total

      $ 23,000   $ 13,154  

                 

12


Table of Contents

(D)
Investments in Debt and Equity Securities.    Investment securities we hold are recorded at fair value in the accompanying consolidated balance sheets. We apply regulated operations accounting to the unrealized gains and losses of all investment securities. All realized and unrealized gains and losses are determined using the specific identification method. At June 30, 2019, investments with a fair value of $30,507,000 were in an unrealized loss position for greater than one year and represented approximately 88% of our gross unrealized losses, while investments with a fair value of $10,533,000 were in an unrealized loss position for less than one year. At December 31, 2018, investments with a fair value of $49,975,000 were in an unrealized loss position for greater than one year and represented approximately 59% of our gross unrealized losses, while investments with a fair value of $148,638,000 were in an unrealized loss position for less than one year.

    The following tables summarize debt and equity securities as of June 30, 2019 and December 31, 2018.

   

Gross Unrealized

 

    (dollars in thousands)  

June 30, 2019

    Cost     Gains     Losses     Fair
Value
 

Equity

  $ 255,339   $ 115,977   $ (6,337 ) $ 364,979  

Debt

    287,991     8,400     (888 )   295,503  

Other

    7,848             7,848  

Total

  $ 551,178   $ 124,377   $ (7,225 ) $ 668,330  


   

Gross Unrealized

 

    (dollars in thousands)  

December 31, 2018

    Cost     Gains     Losses     Fair
Value
 

Equity

  $ 251,226   $ 64,954   $ (9,105 ) $ 307,075  

Debt

    278,030     1,718     (4,955 )   274,793  

Other

    3,075             3,075  

Total

  $ 532,331   $ 66,672   $ (14,060 ) $ 584,943  
(E)
Recently Issued or Adopted Accounting Pronouncements.    In February 2016, the FASB issued "Leases (Topic 842)." The new leases standard requires a dual approach for lessee accounting under which a lessee accounts for leases as finance leases or operating leases. Accounting for both finance leases and operating leases results in the lessee recognizing a right-of-use (ROU) asset and a corresponding lease liability. For finance leases the lessee recognizes interest expense and amortization of the ROU asset and for operating leases the lessee recognizes a straight-line total lease expense. Quantitative and qualitative disclosures are required for significant judgments made by management. The new lease standard does not substantially change lessor accounting. We adopted the new standard effective January 1, 2019. For additional information, see Note G.

    In June 2016, the FASB issued "Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments." The amendments in this update replace the current incurred loss impairment methodology with a methodology that reflects expected credit losses. The new standard is effective for us prospectively for annual reporting periods beginning after December 15, 2019, and interim periods therein. The amendments in this update can be adopted earlier as of the fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted. We continue to evaluate the future impact of this standard on our consolidated financial statements, however, we do not expect the impact to be material.

13


Table of Contents

    In August 2018, the FASB issued "Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement." This standard eliminates, adds and modifies certain disclosure requirements for fair value measurements as part of the FASB's disclosure framework project. Entities will no longer be required to disclose the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, the policy for timing of transfers between levels and the valuation processes for Level 3 fair value measurements. However, public business entities will be required to disclose the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. The amendments in this update are effective for all entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. An entity is permitted to early adopt any removed or modified disclosures upon issuance of this update and delay adoption of the additional disclosures until their effective date.

    As the standard relates only to disclosures, we do not expect the adoption of this standard to have a material impact on our consolidated financial statements. We are currently evaluating the standard and whether we will early adopt the standard.

(F)
Revenue Recognition.    As an electric membership cooperative, our principle business is providing wholesale electric service to our members. Our operating revenues are derived primarily from wholesale power contracts we have with each of our 38 members. These contracts, which extend to December 31, 2050, are substantially identical and obligate our members jointly and severally to pay all expenses associated with owning and operating our power supply business. As a cooperative, we operate on a not-for-profit basis and, accordingly, seek only to generate revenues sufficient to recover our cost of service and to generate margins sufficient to establish reasonable reserves and meet certain financial coverage requirements. While not significant, we also have short-term energy sales to non-members made through industry standard contracts. We do not have multiple operating segments.

    Pursuant to our contracts, we primarily provide two services, capacity and energy. Capacity and energy revenues are recognized by us upon transfer of control of promised services to our members and non-members in an amount that reflects the consideration we expect to receive in exchange for those services. Capacity and energy are distinct and we account for them as separate performance obligations. The obligations to provide capacity and energy are satisfied over time as the customer simultaneously receives and consumes the benefit of these services. Both performance obligations are provided directly by us and not through a third party.

    Each of our members is obligated under its wholesale power contract to pay us for capacity and energy we furnish under the wholesale power contract in accordance with rates we establish. We review our rates periodically but are required to do so at least once every year. Revenues from our members are derived through a cost-plus rate structure which is set forth as a formula in the rate schedule to the wholesale power contracts between us and each of our members. The formulary rate provides for the pass-through of our (i) fixed costs (net of any income from other sources) plus a targeted margin as capacity revenues and (ii) variable costs as energy revenues from our members. Power purchase and sale agreements between us and non-members obligate each non-member to pay us for capacity, if any, and energy furnished in accordance with the prices mutually agreed upon. Margins produced from non-member sales are included in our rate schedule formula and reduce revenue requirements from our members.

    The standard selling price at which we provide capacity services to our members is determined by our formulary rate on an annual basis. As a result, the consideration we receive for providing capacity services is determined annually. Over the course of a year, our member capacity revenues are relatively stable. The components of the formulary rate associated with capacity costs include the annual budget of fixed costs, a targeted margin and income from other sources. Capacity

14


Table of Contents

    revenues, therefore, vary to the extent these components vary. Fixed costs include items such as fixed operation and maintenance expenses, administrative and general expenses, depreciation and interest. Year to year, capacity revenue fluctuations are generally due to the recovery of fixed operation and maintenance costs. Fixed costs also include certain costs, such as major maintenance costs, which will be recognized as expense in future periods. Recognition of revenues associated with these future expenses is deferred pursuant to Accounting Standards Codification (ASC) 980, Regulated Operations. The regulatory liabilities are amortized to revenue in accordance with the associated revenue deferral plan. For information regarding regulatory accounting, see Note J.

    Capacity revenues are recognized by us for standing ready to deliver electricity to our customers. Our capacity revenues are based on the associated costs we expect to recover in a given year and are recognized and billed to our members in equal monthly installments over the course of the year regardless of whether our generation and purchased power resources are dispatched to produce electricity. Non-member capacity revenues, if any, are typically billed and recognized in equal monthly installments over the term of the contract.

    We have a power bill prepayment program pursuant to which our members may prepay future capacity costs and receive a discount. As this program provides us with significant financing, we adjust our capacity revenues by the amount of the discount, which is based on our avoided cost of borrowing. For additional information regarding our member prepayment program, see Note K.

    We satisfy our performance obligations to deliver energy as energy is delivered to the applicable meter points. We determine the standard selling price for energy we deliver to our members based upon the variable costs incurred to generate or purchase that energy. Fuel expense is the primary variable cost. Energy revenue recognized equals the actual variable expenses incurred in any given accounting period. Our member energy 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, variable operating costs, the availability of electric generation resources, our decisions of whether to dispatch our owned or purchased resources or member-owned resources over which we have dispatch rights, and by members' decisions of whether to purchase a portion of their hourly energy requirements from our resources or from other suppliers. We do not provide all of our members' energy requirements. The standard selling price for our energy revenues from non-members is the price mutually agreed upon.

    We are required under our first mortgage indenture to produce a margins for interest ratio of at least 1.10 for each fiscal year. For 2019, our board has approved a targeted margins for interest ratio of 1.14. Historically, our board of directors has approved adjustments to revenue requirements by year end such that revenue in excess of that required to meet the targeted margins for interest ratio is refunded to the members. Given that our capacity revenues are based upon budgeted expenditures and generally recognized and billed to our members in equal monthly installments over the course of the year, we may recognize capacity revenues that exceed our actual fixed costs and targeted margins in any given interim reporting period. At each interim reporting period we assess our projected revenue requirements through year end to determine whether a refund to our members of excess consideration is likely. If so, we reduce our capacity revenues and recognize a refund liability to our members. Refund liabilities, if any, are included in accounts payable on our consolidated balance sheets. As of June 30, 2019 and June 30, 2018, we recognized refund liabilities totaling $4,500,000 and $5,650,000, respectively. Based on our current agreements with non-members, we do not refund any consideration received from non-members.

15


Table of Contents

    Sales to members for the three and six months ended June 30, 2019 and 2018 were as follows:

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

    (dollars in thousands)  

   

2019

   

2018

   

2019

   

2018

 

Capacity revenues

  $ 235,049   $ 231,571   $ 481,035   $ 472,052  

Energy revenues

    123,687     134,240     234,171     267,160  

Total

  $ 358,736   $ 365,811   $ 715,206   $ 739,212  

                         

    Sales to non-members during the three and six months ended June 30, 2019 and 2018 were insignificant.

    Electric capacity and energy revenues are recognized by us without any obligation for returns, warranties or taxes collected. As our members are jointly and severally obligated to pay all expenses associated with owning and operating our power supply business and we perform an on-going assessment of the credit worthiness of non-members, we have not recorded an allowance for doubtful accounts associated with our receivables from members or non-members.

    We have a rate management program that allows us to expense and recover interest costs on a current basis that would otherwise be deferred or capitalized. The subscribing members of Vogtle Units No. 3 and No. 4 can elect to participate in this program on an annual basis. The Vogtle program allows for the recovery of financing costs associated with the construction of Vogtle Units No. 3 and No. 4 on a current basis. Under this program, amounts billed to participating members during the six months ended June 30, 2019 and June 30, 2018 were $8,966,000 and $5,400,000, respectively. The cumulative amount billed since inception of the program totaled $75,282,000.

    In 2018, we began an additional rate management program that allows us to recover future expense on a current basis from our members. In general, the program allows for additional collections over a five-year period with those amounts then applied to billings over the subsequent five-year period. The program is designed primarily as a mechanism to assist our members in managing the rate impacts associated with the commercial operation of the new Vogtle units. Under this program, amounts billed to participating members during the six months ended June 30, 2019 and June 30, 2018 were $23,380,000 and $6,174,000, respectively. Funds collected through this program are invested and held until applied to members' bills. In conjunction with this program, we are applying regulated operations accounting to defer these revenues and related investment income on the funds collected. Amounts deferred under the program will be amortized to income when applied to members' bills.

(G)
Leases.    As a lessee, we have a relatively small portfolio of leases with the most significant being our 60% undivided interest in Scherer Unit No. 2 and railcar leases for the transportation of coal. We also have various other leases of minimal value.

    On January 1, 2019, we adopted the new leases standard using the optional transition method to apply the new lease guidance as of January 1, 2019, rather than as of the earliest period presented. In addition, we elected the package of practical expedients permitted under the transition guidance within the new leases standard, which among other things, allowed us to carry forward the historical lease classification. We also elected the practical expedient related to land easements, allowing us to carry forward our accounting treatment for land easements on existing agreements. Adoption of the new leases standard resulted in recognition of right-of-use assets and offsetting lease liabilities totaling approximately $6,983,000. The adoption of this standard did not materially impact our consolidated financial statements.

16


Table of Contents

    We classify our Scherer Unit No. 2 leases as finance leases and our railcar leases as operating leases. We have made an accounting policy election not to recognize right-of-use assets and lease liabilities that arise from short-term leases, leases having an initial term of 12 months or less, for any class of underlying asset. We recognize lease expense for short-term leases on a straight-line basis over the lease term. Lease expense recognized for our short-term leases during the six months ended June 30, 2019 and June 30, 2018 was insignificant.

    Finance Leases

    Three of our finance leases have lease terms through December 31, 2027, and one lease extends through June 30, 2031. At the end of the leases, we can elect at our sole discretion to:

    Renew the leases for a period of not less than one year and not more than five years at fair market value,

    Purchase the undivided interest at fair market value, or

    Redeliver the undivided interest to the lessors.

    For rate-making purposes, we include the actual lease payments for our finance leases in our cost of service. The difference between lease payments and the aggregate of the amortization on the right-of-use asset and the interest on the finance lease obligation is recognized as a regulatory asset. Finance lease amortization is recorded in depreciation and amortization expense.

    Operating Leases

    Our operating leases have terms that extend through October 31, 2023. At the end of the railcar operating leases, we can renew at terms mutually agreeable by us and the lessors, purchase the assets or return the assets to the lessors. We have an additional operating lease that has a term that extends through December 31, 2019 with renewal options for two additional twenty-year terms. We intend to exercise the option for one additional twenty-year term.

    The exercise of renewal options for our finance and operating leases is at our sole discretion.

    As all of our operating leases do not provide an implicit rate, we used our incremental borrowing rate based on the information available on January 1, 2019, the date of adoption of the new leases standard, in determining the present value of lease payments.

    For lease agreements entered into or reassessed after the adoption of the new leases standard, we combine lease and nonlease components.

Classification

   

June 30,
2019

   

December 31,
2018

 

    (dollars in thousands)  

Right-of-Use Assets—Finance leases

             

Right-of-use assets

  $ 302,732   $ 302,732  

Less: Accumulated provision for depreciation

    (254,868 )   (252,233 )

Total finance lease assets

  $ 47,864   $ 50,499  

Lease liabilities—Finance leases

             

Obligations under finance leases

  $ 78,771   $ 81,730  

Long-term debt and finance leases due within one year

    8,421     5,462  

Total finance lease liabilities

  $ 87,192   $ 87,192  

17


Table of Contents


Classification

   

June 30,
2019

   

December 31,
2018

 

    (dollars in thousands)  

Right-of-Use Assets—Operating leases

             

Electric plant in service

  $ 4,878   $  

Total operating lease assets

  $ 4,878   $  

Lease liabilities—Operating leases

             

Capitalization—Other

  $ 2,616   $  

Other current liabilities

    2,648      

Total operating lease liabilities

  $ 5,264   $  

 

 

 

   

Three months ended

   

Six months ended

 

Lease Cost

 

Classification

   

June 30,
2019

   

June 30,
2018

   

June 30,
2019

   

June 30,
2018

 

 

 

   

(dollars in thousands)

 

Finance lease cost:

                             

Amortization of leased assets

  Depreciation and amortization   $ 1,189   $ 1,049   $ 2,378   $ 2,099  

Interest on lease liabilities

  Interest expense     2,372     2,511     4,744     5,022  

Operating lease cost:

  Inventory(1) & production expense     883     1,230     1,766     2,460  

Total leased cost

      $ 4,444   $ 4,790   $ 8,888   $ 9,581  
(1)
The majority of our operating lease costs relates to our railcar leases and such costs are added to the cost of our fossil inventories and are recognized in fuel expense as the inventories are consumed.

   

June 30,
2019

   

December 31,
2018

 

Lease Term and Discount Rate:

             

Weighted-average remaining lease term (in years)

             

Finance leases

    9.32     9.82  

Operating leases

    5.37     N/A  

Weighted-average discount rate

   
 
   
 
 

Finance leases

    11.05 %   11.05 %

Operating leases

    4.85 %   N/A  

 

   

Six months ended

 

   

June 30,
2019

   

June 30,
2018

 

   

(dollars in thousands)

 

Other Information:

             

Cash paid for amounts included in the measurement of lease liabilities

             

Operating cash flows from finance leases

  $   $ 5,213  

Operating cash flows from operating leases

  $ 1,840   $  

Financing cash flows from finance leases

  $   $ 2,261  

Right-of-use assets obtained in exchange for new operating lease liabilities

 
$

6,983
 
$

 

18


Table of Contents

    Maturity analysis of our finance and operating lease liabilities as of June 30, 2019 is a follows:

   

(dollars in thousands)

 

Year Ending December 31,

   

Finance Leases

   

Operating Leases

   

Total

 

2019

  $ 14,949   $ 1,870   $ 16,819  

2020

    14,949     1,402     16,351  

2021

    14,949     798     15,747  

2022

    14,949     608     15,557  

2023

    14,949     386     15,335  

Thereafter

    70,483     1,157     71,639  

Total lease payments

  $ 145,228   $ 6,221   $ 151,448  

Less: imputed interest

    (58,036 )   (957 )   (58,993 )

Present value of lease liabilities

  $ 87,192   $ 5,264   $ 92,455  

    As a lessor, we primarily lease office space to several tenants within our headquarters building. Several of these tenants are related parties. We account for all of these lease agreements as operating leases.

    Lease income recognized during the three and six months ended June 30, 2019 and June 30, 2018 was as follows:

 

Three months ended June 30,  

 

Six months ended June 30,  

 

   

2019

   

2018

   

2019

   

2018

 

   

(dollars in thousands)

 

Lease income

  $ 1,522   $ 1,472   $ 3,040   $ 2,945  
(H)
Contingencies and Regulatory Matters.    We do 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.

    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 may also become subject to climate change regulations that impose restrictions on emissions of greenhouse gases, including carbon dioxide.

    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 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.

19


Table of Contents

    At this time, the ultimate impact of any potential 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.

(I)
Restricted Investments.    Restricted investments consist of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account that are held by the U.S. Treasury, acting through the Federal Financing Bank. We can only utilize these investments for future Rural Utilities Service-guaranteed Federal Financing Bank debt service payments. The funds on deposit currently earn interest at a rate of 5% per annum. Beginning October 1, 2020, deposits will earn interest at 4% per annum and beginning October 1, 2021, the rates will be set at the 1-year floating treasury rate. The program no longer allows additional funds to be deposited into the account. At June 30, 2019 and December 31, 2018, we had restricted investments totaling $631,491,000 and $653,158,000, respectively, of which $518,991,000 and $503,158,000, respectively, were classified as long-term.
(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.

20


Table of Contents

    The following regulatory assets and liabilities are reflected on the unaudited consolidated balance sheets as of June 30, 2019 and December 31, 2018.

   

2019

   

2018

 

   

(dollars in thousands)

 

Regulatory Assets:

             

Premium and loss on reacquired debt(a)

  $ 43,159   $ 46,315  

Amortization of financing leases(b)

    35,176     34,918  

Outage costs(c)

    41,066     36,352  

Asset retirement obligations—Ashpond and other(k)

    261,622     137,835  

Asset retirement obligations—Nuclear(k)

        7,031  

Depreciation expense(d)

    40,532     41,244  

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

    52,273     51,549  

Interest rate options cost(f)

    119,432     116,960  

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

    157,537     160,509  

Other regulatory assets(m)

    29,943     22,350  

Total Regulatory Assets

  $ 780,740   $ 655,063  

Regulatory Liabilities:

   
 
   
 
 

Accumulated retirement costs for other obligations(h)

  $ 16,072   $ 13,873  

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

    18,793     19,101  

Major maintenance reserve(i)

    39,732     45,547  

Amortization of financing leases(b)

    15,706     17,156  

Deferred debt service adder(j)

    109,835     105,192  

Asset retirement obligations—Nuclear(k)

    42,986     0  

Revenue deferral plan(l)

    39,973     15,670  

Other regulatory liabilities(m)

    2,704     2,459  

Total Regulatory Liabilities

  $ 285,801   $ 218,998  

Net Regulatory Assets

  $ 494,939   $ 436,065  

             
(a)
Represents premiums paid, together with unamortized transaction costs related to reacquired debt that are being amortized over the lives of the refunding debt, which range up to 25 years.

(b)
Represents the difference between expense recognized for rate-making purposes versus financial statement purposes related to finance lease payments and the aggregate of the amortization of the asset and interest on the obligation.

(c)
Consists of both coal-fired maintenance and nuclear refueling outage costs. Coal-fired outage costs are amortized on a straight-line basis to expense over periods up to 48 months, depending on the operating cycle of each unit. Nuclear refueling outage costs are amortized on a straight-line basis to expense over the 18 or 24-month operating cycles of each unit.

(d)
Prior to Nuclear Regulatory Commission (NRC) approval of a 20-year license extension for Plant Vogtle Units No. 1 and No. 2, we deferred the difference between the units' 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.

(e)
Deferred charges consist of training related costs, including interest and 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.

(f)
Deferral of premiums paid to purchase interest rate options used to hedge interest rates on certain borrowings, related carrying costs and other incidentals associated with construction of Vogtle Units No. 3 and No. 4. Amortization will commence in February 2020 and continue through February 2044, the life of the DOE-guaranteed loan which is financing a portion of the construction project.

(g)
Effects on net margin for Smith and Hawk Road Energy Facilities were deferred through the end of 2015 and are being amortized over the remaining life of each respective plant.

(h)
Represents the accrual of retirement costs associated with long-lived assets for which there are no legal obligations to retire the assets.

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

(j)
Represents collections to fund certain debt payments to be made through the end of 2025 which will be in excess of amounts collected through depreciation expense; the deferred credits will be amortized over the remaining useful life of the plants.

(k)
Represents the difference in the timing of recognition of decommissioning costs for financial statement purposes versus ratemaking purposes, as well as the deferral of unrealized gains and losses of funds set aside for decommissioning.

(l)
Deferred revenues under a rate management program that allows for additional collections over a five-year period which began in 2018. These amounts will be amortized to income and applied to member billings over the subsequent five-year period.

(m)
The amortization periods for other regulatory assets range up to 31 years and the amortization periods of other regulatory liabilities range up to 8 years.

21


Table of Contents

(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 February 2024, with the majority of the balance scheduled to be credited by the end of 2019.
(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, 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 pursuant to which the Department of Energy agreed to guarantee our obligations under a Note Purchase Agreement, dated as of February 20, 2014 (the Original Note Purchase Agreement), among us, the Federal Financing Bank and the Department of Energy and two future advance promissory notes, each dated February 20, 2014, made by us to the Federal Financing Bank in the aggregate amount of $3,057,069,461 (the Original FFB Notes and together with the Original Note Purchase Agreement, the Original FFB Documents). Following the bankruptcy of Westinghouse in 2017 (as described in Note M), we and the Department of Energy amended the loan guarantee agreement to restrict further advances pending the satisfaction of certain conditions, including an amendment to the loan guarantee agreement.

    In September 2017, the Department of Energy issued a conditional commitment to us to guarantee an additional $1,619,679,706 of funding from the Federal Financing Bank. On March 7, 2019, we entered into an amendment and waiver of the loan guarantee agreement under which we received an advance of $585,000,000. On March 22, 2019, we and the Department of Energy entered into an Amended and Restated Loan Guarantee Agreement (as amended, the Loan Guarantee Agreement) which increased the aggregate amount guaranteed by the Department of Energy to $4,676,749,167 and permits us to draw the remaining amount under the Original FFB Notes. We also entered into a Note Purchase Agreement dated as of March 22, 2019 (the Additional Note Purchase Agreement), among us, the Federal Financing Bank and the Department of Energy and a future advance promissory note, dated March 22, 2019, made by us to the Federal Financing Bank in the amount of $1,619,679,706 (the Additional FFB Note and together with the Additional Note Purchase Agreement, the Additional FFB Documents).

    Together, the Original FFB Documents and Additional FFB Documents provide for a multi-advance term loan facility (the Facility) under which we may make long-term loan borrowings through the Federal Financing Bank.

    Proceeds of advances made under the Facility are 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). Borrowings under the Original FFB Notes may not exceed $3,057,069,461, of which $335,471,604 is designated for capitalized interest. Borrowings under the Additional FFB Note may not exceed (i) $1,619,679,706 or (ii) an amount that, when aggregated with borrowings under the Original FFB Notes, equals 70% of Eligible Project Costs less the $1,104,000,000 guarantee payment we received from Toshiba Corporation in December 2017. Total borrowings under the Facility will not exceed $4,676,749,167.

22


Table of Contents

    At June 30, 2019, aggregate Department of Energy-guaranteed borrowings, including capitalized interest totaled $2,415,271,000. We have no amounts outstanding under the Additional FFB Note.

    Under the Loan Guarantee Agreement, we are obligated to reimburse the Department of Energy in the event it is required to make any payments to the Federal Financing Bank under its guarantee. Our payment obligations to the Federal Financing Bank under the FFB Notes and reimbursement obligations to the Department of Energy under its guarantee, but not our covenants to the Department of Energy under the Loan Guarantee Agreement, are secured equally and ratably with all of our other obligations issued under our first mortgage indenture. The final maturity date for each advance is February 20, 2044. Interest is payable quarterly in arrears and principal payments on all advances under the FFB Notes will begin on February 20, 2020. Interest rates on borrowings 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%.

    Advances under the Original FFB Notes may be requested on a quarterly basis through December 31, 2020. Advances under the Additional FFB Note may be requested on a quarterly basis through November 30, 2023, one year beyond the current anticipated commercial operation date of Vogtle Unit No. 4.

    Future advances under the Facility are subject to satisfaction of customary conditions, as well as (i) certification of compliance with the requirements of the Title XVII loan guarantee program, (ii) accuracy of project-related representations and warranties, (iii) delivery of updated project-related information, (iv) no Project Adverse Event (as described in Note M) having occurred or, if a Project Adverse Event has occurred, that Co-owners (as described in Note M) representing at least 90% of the ownership interests have voted to continue construction, have not deferred construction and we have provided the Department of Energy with certain additional information, (v) certification regarding Georgia Power's compliance with certain obligations relating to the Cargo Preference Act, as amended, (vi) evidence of compliance with the applicable wage requirements of the Davis-Bacon Act, as amended, (vii) certification from the Department of Energy's consulting engineer that proceeds of the advance are used to reimburse Eligible Project Costs and (viii) if either the Services Agreement or the Bechtel Agreement (each, as described in Note M) are terminated, or rejected in bankruptcy proceedings, the Department of Energy has approved the replacement agreement.

    We may voluntarily prepay outstanding borrowings under the Facility. Under the FFB Documents, any prepayment will be subject to a make-whole premium or discount, as applicable. Any amounts prepaid may not be re-borrowed.

    Under the Loan Guarantee Agreement, we are subject to customary borrower affirmative and negative covenants and events of default. In addition, we are subject to project-related reporting requirements and other project-specific covenants and events of default.

    If certain events occur, referred to as an "Alternate Amortization Event," at the Department of Energy's option the Federal Financing Bank's commitment to make further advances under the Facility will terminate and we will be required to repay the outstanding principal amount of all borrowings under the Facility over a period of five years, with level principal amortization. These events include (i) abandonment of the Vogtle Units No. 3 and No. 4 project, including a decision by Georgia Power to cancel the project, (ii) cessation of the construction of Vogtle Units No. 3 and No. 4 for twelve consecutive months, (iii) termination of the Services Agreement or rejection of the Services Agreement in bankruptcy, if Georgia Power does not maintain access to certain related intellectual property rights, (iv) termination of the Services Agreement by Westinghouse or termination of the Bechtel Agreement by Bechtel Power Corporation, (v) delivery of certain notices by the Co-owners to the Department of Energy of their intent to cancel construction of

23


Table of Contents

    Vogtle Units No. 3 and No. 4 coupled with termination by the Co-owners of the Services Agreement or the Bechtel Agreement, (vi) failure of the Co-owners to enter into a replacement contract with respect to the Services Agreement or the Bechtel Agreement following the Co-owners' termination of such agreement with the intent to replace it, (vii) the Department of Energy's takeover of construction of Vogtle Units No. 3 and No. 4 under certain conditions, (viii) the occurrence of any Project Adverse Event that results in a cancellation of the Vogtle Units No. 3 and No. 4 project or the cessation or deferral of construction beyond the periods permitted under the Loan Guarantee Amendment, (ix) loss of or failure to receive necessary regulatory approvals under certain circumstances, (x) loss of access to intellectual property rights necessary to construct or operate Vogtle Units No. 3 and No. 4 under certain circumstances, (xi) our failure to fund our share of operation and maintenance expenses for Vogtle Units No. 3 and No. 4 for twelve consecutive months, (xii) change of control of Oglethorpe and (xiii) certain events of loss or condemnation. If we receive proceeds from an event of condemnation relating to Vogtle Units No. 3 and No. 4, such proceeds must be applied to immediately prepay outstanding borrowings under the Facility.

    b)
    Rural Utilities Service Guaranteed Loans:

    For the six-month period ended June 30, 2019, we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling $72,986,000 for long-term financing of general and environmental improvements at existing plants.

    In July 2019, we received an additional $25,022,000 in advances on Rural Utilities Service-guaranteed Federal Financing Bank loans for long-term financing of general and environmental improvements at existing plants.

(M)
Vogtle Units No. 3 and No. 4 Construction Project.    We, Georgia Power, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, doing business as Dalton Utilities (collectively, the Co-owners) are parties to an Ownership Participation Agreement that, along with other agreements, governs our participation in two additional nuclear units under construction at Plant Vogtle, Units No. 3 and No. 4. The Co-owners appointed Georgia Power to act as agent under this agreement. Our ownership interest and proportionate share of the cost to construct these units is 30%. Pursuant to this agreement, Georgia Power has designated Southern Nuclear Operating Company, Inc. as its agent for licensing, engineering, procurement, contract management, construction and pre-operation services. As of June 30, 2019, our total investment in the additional Vogtle units was approximately $4,357,227,000.

    In 2008, Georgia Power, acting for itself and as agent for the Co-owners, entered into an Engineering, Procurement and Construction Agreement (the EPC Agreement) with Westinghouse Electric Company LLC and Stone & Webster, Inc., which was subsequently acquired by Westinghouse and changed its name to WECTEC Global Project Services Inc. (collectively, Westinghouse). Pursuant to the EPC Agreement, Westinghouse agreed to design, engineer, procure, construct and test two 1,100 megawatt nuclear units using the Westinghouse AP1000 technology and related facilities at Plant Vogtle.

    Until March 2017, construction on Units No. 3 and No. 4 continued under the substantially fixed price EPC Agreement. In March 2017, Westinghouse filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. Effective in July 2017, Georgia Power, acting for itself and as agent for the other Co-owners, and Westinghouse entered into a services agreement (the Services Agreement), pursuant to which Westinghouse is providing facility design and engineering services, procurement and technical support and staff augmentation on a time and materials cost basis. The Services Agreement provides that it will continue until the start-up and

24


Table of Contents

    testing of Vogtle Units No. 3 and No. 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Co-owners upon 30 days' written notice.

    In October 2017, Georgia Power, acting for itself and as agent for the other Co-owners, entered into a construction completion agreement with Bechtel Power Corporation, pursuant to which Bechtel serves as the primary contractor for the remaining construction activities for Vogtle Units No. 3 and No. 4 (the Bechtel Agreement). The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Co-owner is severally, and not jointly, liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Co-owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Co-owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Co-owner suspensions of work, certain breaches of the Bechtel Agreement by the Co-owners, Co-owner insolvency and certain other events.

    In April 2019, Georgia Power and Southern Nuclear completed a cost and schedule validation process to verify and update quantities of commodities remaining to install, labor hours to install remaining quantities and related productivity, testing and system turnover requirements, and forecasted staffing needs and related costs. This process confirmed the total estimated project capital cost forecast for Vogtle Units No. 3 and No. 4. Accordingly, we did not change our $7.5 billion project budget, which includes capital costs, allowance for funds used during construction, our allocation of the project-level contingency and a separate Oglethorpe-level contingency. There was also no change to the in-service dates of November 2021 for Unit No. 3 and November 2022 for Unit No. 4 previously approved by the Georgia Public Service Commission following the validation process.

    As construction continues and testing and system turnover activities increase, risks remain that challenges with management of contractors, subcontractors and vendors; supervision of craft labor and related craft labor productivity, ability to attract and retain craft labor and/or related cost escalation; procurement, fabrication, delivery, assembly and/or installation and the initial testing and start-up, including any required engineering changes, of plant systems, structures or components or regional transmission upgrades, any of which may require additional labor and/or materials; or other issues could arise and further impact the projected schedule and estimated cost.

    The April 2019 cost and schedule validation process established target values for monthly construction production and system turnover activities as part of a strategy to maintain margin to the approved in-service dates. To support that strategy, monthly production and activity targets will continue to increase significantly throughout 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers, particularly electrical and pipefitter craft labor, as well as additional supervision and other field support resources, must be retained and deployed.

    There have been technical and procedural challenges to the construction and licensing of Vogtle Units No. 3 and No. 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the Nuclear Regulatory Commission that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the Nuclear Regulatory Commission.

25


Table of Contents

    Various design and other licensing-based compliance matters, including the timely submittal by Southern Nuclear of the inspections, tests, analyses, and acceptance criteria documentation for each unit and the related reviews and approvals by the Nuclear Regulatory Commission necessary to support authorization to load fuel, may arise which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be further delays in the project schedule that could result in increased costs to the Co-owners.

    The Co-owners' joint ownership agreements, as amended, provide that the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 must vote to continue construction, or can vote to suspend construction, if certain adverse events occur, including: (i) the bankruptcy of Toshiba Corporation; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement, the Bechtel Agreement or the agency agreement with Southern Nuclear; (iii) Georgia Power publicly announces its intention not to submit for rate recovery any portion of its investment in Vogtle Units No. 3 and No. 4 (or associated financing costs) or the Georgia Public Service Commission determines that any of Georgia Power's costs relating to the construction of Vogtle Units No. 3 and No. 4 will not be recovered in retail rates, excluding any additional amounts paid by Georgia Power on behalf of the other Co-owners pursuant to the Joint Ownership Agreement provisions described above and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Public Service Commission for recovery, or for which Georgia Power elects not to seek cost recovery, through retail rates or (iv) an incremental extension of one year or more over the most recently approved schedule (each, a Project Adverse Event).

    The ultimate outcome of these matters cannot be determined at this time. See Note 8 in Item 8 Notes to Audited Consolidated Financial Statements in our 2018 Form 10-K for additional information about Vogtle Units No. 3 and No. 4.

26


Table of Contents

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, which we provide primarily from our generation assets and, to a lesser extent, from power purchased from 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, 2019 and 2018

Net Margin

Our net margins for the three-month and six-month periods ended June 30, 2019 were $9.4 million and $33.0 million, respectively, compared to $17.3 million and $44.7 million for the same periods of 2018. For the six-months ended June 30, 2019, our net margin was approximately 60% of our targeted net margin of $54.6 million for the year ending December 31, 2019. The targeted net margin for 2019 is based upon achieving a margins for interest ratio of 1.14 as approved by our board of directors. If our net margin exceeds the targeted net margin, we anticipate our board of directors will approve a budget adjustment by year end so that net margin will achieve, but not exceed, the 2019 targeted net margin. As a result, we assessed our projected net margin and annual revenue requirement to meet the targeted margins for interest ratio and recognized a refund liability of $4.5 million and $5.7 million during the second quarter of 2019 and 2018, respectively. For additional information regarding our net margin requirements and policy, see "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Summary of Cooperative Operations—Margins" in our 2018 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.    We generate revenues principally from the sale of electric capacity and energy to our members. 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 recover the fixed costs associated with our business, including fixed production expenses, depreciation and amortization expenses and interest charges, plus a targeted margin. Energy revenues are earned by selling electricity to our members, which involves generating or purchasing electricity for our members. Energy revenues recover the variable costs of our business, including fuel, purchased energy and variable operation and maintenance expense.

27


Table of Contents

The components of member revenues for the three-month and six-month periods ended June 30, 2019 and 2018 were as follows:

 
   
   
   
   
   
   
 

    Three Months Ended
June 30,
    2019 vs.
2018
% Change
    Six Months Ended
June 30,
    2019 vs.
2018
% Change
 

    (dollars in thousands)           (dollars in thousands)        

   

2019

   

2018

   

 

   

2019

   

2018

       

Capacity revenues

  $ 235,049   $ 231,571     1.5%   $ 481,035   $ 472,052     1.9%  

Energy revenues

    123,687     134,240     (7.9%)     234,171     267,160     (12.3%)  

Total

  $ 358,736   $ 365,811     (1.9%)   $ 715,206   $ 739,212     (3.2%)  

MWh Sales to members

    5,837,713     5,926,738     (1.5%)     10,535,848     11,027,064     (4.5%)  

Cents/kWh

    6.15     6.17     (0.4%)     6.79     6.70     1.3%  

Member energy requirements supplied

   
59

%
 
62

%
 

(4.8%)

   
56

%
 
58

%
 

(3.4%)

 

Energy revenues from members decreased for the three-month and six-month periods ended June 30, 2019 compared to the same periods in 2018 primarily due to the recovery of fuel costs. For a discussion of fuel costs, which are the primary costs recovered by energy revenues, see "—Operating Expenses."

28


Table of Contents

Operating Expenses

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

 
   
   
   
   
   
   
   
   
   
 

    Cost     Generation     Cents per kWh
 

    (dollars in thousands)     (MWh)                    

   

Three Months Ended June 30,

   

2019 vs.

   

Three Months Ended June 30,

   

2019 vs.

   

Three Months Ended
June 30,

   

2019 vs.

 

Fuel Source

    2019     2018     2018
%
Change
    2019     2018     2018
%
Change
    2019     2018     2018
%
Change
 

Coal

  $ 26,057   $ 31,361     (16.9%)     825,171     1,048,979     (21.3%)     3.16     2.99     5.6%  

Nuclear

    20,743     21,660     (4.2%)     2,616,214     2,597,891     0.7%     0.79     0.83     (4.9%)  

Gas:

                                                       

Combined Cycle

    49,267     57,012     (13.6%)     2,114,879     2,168,551     (2.5%)     2.33     2.63     (11.4%)  

Combustion Turbine

    15,383     12,111     27.0%     428,422     298,698     43.4%     3.59     4.05     (11.4%)  

  $ 111,450   $ 122,144     (8.8%)     5,984,686     6,114,119     (2.1%)     1.86     2.00     (6.8%)