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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 | ||
OR | ||
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
For the transition period from to |
Commission File No. 000-53908
(An Electric Membership Corporation)
(Exact name of registrant as specified in its charter)
Georgia (State or other jurisdiction of incorporation or organization) | 58-1211925 (I.R.S. employer identification no.) | |
2100 East Exchange Place Tucker, Georgia | 30084-5336 | |
(Address of principal executive offices) | (Zip Code) | |
Registrant's telephone number, including area code | (770) 270-7600 |
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer," and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):Large Accelerated Filer o Accelerated Filer o Non-Accelerated Filer ý (Do not check if a smaller reporting company) Smaller Reporting Company o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý
Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.The registrant is a membership corporation and has no authorized or outstanding equity securities.
(This page has been left blank intentionally)
OGLETHORPE POWER CORPORATION
INDEX TO QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED MARCH 31,JUNE 30, 2014
| | Page No. | ||
---|---|---|---|---|
PART I—FINANCIAL INFORMATION | ||||
Item 1. | Financial Statements | 1 | ||
Unaudited Condensed Balance Sheets as of | 1 | |||
Unaudited Condensed Statements of Revenues and Expenses For the Three and Six Months ended | 3 | |||
Unaudited Condensed Statements of Comprehensive Margin For the Three and Six Months ended | 4 | |||
Unaudited Condensed Statements of Patronage Capital and Membership Fees and Accumulated Other Comprehensive Margin (Deficit) For the | 5 | |||
Unaudited Condensed Statements of Cash Flows For the | 6 | |||
Notes to Unaudited Condensed Financial Statements For the Three and Six Months ended | 7 | |||
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 | |||
SIGNATURES |
i
CAUTIONARY STATEMENTS REGARDING
FORWARD-LOOKING STATEMENTS AND ASSOCIATED RISKS
This quarterly report on Form 10-Q contains "forward-looking statements." All statements, other than statements of historical facts, that address activities, events or developments that we expect or anticipate to occur in the future, including matters such as the timing of various regulatory and other actions, future capital expenditures, business strategy and development, construction or operation of facilities (often, but not always, identified through the use of words or phrases such as "will likely result," "are expected to," "will continue," "is anticipated," "estimated," "projection," "target" and "outlook") are forward-looking statements.
Although we believe that in making these forward-looking statements our expectations are based on reasonable assumptions, any forward-looking statement involves uncertainties and there are important factors that could cause actual results to differ materially from those expressed or implied by these forward-looking statements. Some of the risks, uncertainties and assumptions that may cause actual results to differ from these forward-looking statements are described under the heading "RISK FACTORS" in this quarterly report and under the heading "RISK FACTORS" and in other sections of our annual report on Form 10-K for the fiscal year ended December 31, 2013. In light of these risks, uncertainties and assumptions, the forward-looking events and circumstances discussed in this annualquarterly report may not occur.
Any forward-looking statement speaks only as of the date of this annualquarterly 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:
ii
iii
PART I—FINANCIAL INFORMATION
Item 1. Financial Statements
Oglethorpe Power Corporation
Condensed Balance Sheets (Unaudited)March 31,June 30, 2014 and December 31, 2013
(dollars in thousands) | (dollars in thousands) | |||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||
Assets | ||||||||||||||
Electric plant: | ||||||||||||||
In service | $ | 8,078,128 | $ | 8,050,103 | $ | 8,258,050 | $ | 8,050,103 | ||||||
Less: Accumulated provision for depreciation | (3,648,091 | ) | (3,615,375 | ) | (3,688,112 | ) | (3,615,375 | ) | ||||||
| ||||||||||||||
4,430,037 | 4,434,728 | 4,569,938 | 4,434,728 | |||||||||||
Nuclear fuel, at amortized cost | 347,044 | 341,012 | 338,856 | 341,012 | ||||||||||
Construction work in progress | 2,290,024 | 2,212,224 | 2,227,216 | 2,212,224 | ||||||||||
| ||||||||||||||
7,067,105 | 6,987,964 | 7,136,010 | 6,987,964 | |||||||||||
| ||||||||||||||
Investments and funds: | ||||||||||||||
Nuclear decommissioning trust fund | 348,097 | 343,698 | 361,746 | 343,698 | ||||||||||
Investment in associated companies | 66,393 | 66,437 | 65,395 | 66,437 | ||||||||||
Long-term investments | 82,593 | 81,720 | 83,545 | 81,720 | ||||||||||
Restricted cash | 10,736 | 34,975 | 2,766 | 34,975 | ||||||||||
Other | 16,357 | 16,098 | 16,617 | 16,098 | ||||||||||
| ||||||||||||||
524,176 | 542,928 | 530,069 | 542,928 | |||||||||||
| ||||||||||||||
Current assets: | ||||||||||||||
Cash and cash equivalents | 218,493 | 408,193 | 329,866 | 408,193 | ||||||||||
Restricted short-term investments | 289,469 | 272,686 | 293,859 | 272,686 | ||||||||||
Receivables | 130,884 | 128,992 | 150,359 | 128,992 | ||||||||||
Inventories, at average cost | 261,341 | 286,168 | 253,712 | 286,168 | ||||||||||
Prepayments and other current assets | 15,950 | 16,894 | 15,923 | 16,894 | ||||||||||
| ||||||||||||||
916,137 | 1,112,933 | 1,043,719 | 1,112,933 | |||||||||||
| ||||||||||||||
Deferred charges: | ||||||||||||||
Deferred debt expense, being amortized | 97,831 | 57,175 | 99,785 | 57,175 | ||||||||||
Regulatory assets | 385,769 | 331,108 | 400,996 | 331,108 | ||||||||||
Other | 55,976 | 63,104 | 51,101 | 63,104 | ||||||||||
| ||||||||||||||
539,576 | 451,387 | 551,882 | 451,387 | |||||||||||
| ||||||||||||||
$ | 9,046,994 | $ | 9,095,212 | $ | 9,261,680 | $ | 9,095,212 | |||||||
| | |||||||||||||
The accompanying notes are an integral part of these condensed financial statements.
Oglethorpe Power Corporation
Condensed Balance Sheets (Unaudited)March 31,June 30, 2014 and December 31, 2013
(dollars in thousands) | (dollars in thousands) | |||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||
Equity and Liabilities | ||||||||||||||
Capitalization: | ||||||||||||||
Patronage capital and membership fees | $ | 733,712 | $ | 714,489 | $ | 750,908 | $ | 714,489 | ||||||
Accumulated other comprehensive deficit | (153 | ) | (549 | ) | ||||||||||
Accumulated other comprehensive margin (deficit) | 278 | (549 | ) | |||||||||||
| ||||||||||||||
733,559 | 713,940 | 751,186 | 713,940 | |||||||||||
Long-term debt | 6,795,655 | 6,817,518 | 6,893,755 | 6,817,518 | ||||||||||
Obligation under capital leases | 118,871 | 121,731 | 114,240 | 121,731 | ||||||||||
Other | 15,639 | 15,379 | 15,898 | 15,379 | ||||||||||
| ||||||||||||||
7,663,724 | 7,668,568 | 7,775,079 | 7,668,568 | |||||||||||
| ||||||||||||||
Current liabilities: | ||||||||||||||
Long-term debt and capital leases due within one year | 153,772 | 152,153 | 289,067 | 152,153 | ||||||||||
Short-term borrowings | 269,687 | 279,407 | 195,913 | 279,407 | ||||||||||
Accounts payable | 72,865 | 101,529 | 76,757 | 101,529 | ||||||||||
Accrued interest | 49,389 | 58,193 | 58,376 | 58,193 | ||||||||||
Member power bill prepayments, current | 92,460 | 82,405 | 93,041 | 82,405 | ||||||||||
Other current liabilities | 27,624 | 42,253 | 34,290 | 42,253 | ||||||||||
| ||||||||||||||
665,797 | 715,940 | 747,444 | 715,940 | |||||||||||
| ||||||||||||||
Deferred credits and other liabilities: | ||||||||||||||
Gain on sale of plant, being amortized | 21,787 | 22,157 | 21,417 | 22,157 | ||||||||||
Asset retirement obligations | 413,977 | 408,050 | 420,016 | 408,050 | ||||||||||
Member power bill prepayments, non-current | 34,363 | 32,313 | 36,153 | 32,313 | ||||||||||
Power sale agreement, being amortized | 22,747 | 26,107 | 19,388 | 26,107 | ||||||||||
Regulatory liabilities | 160,437 | 158,789 | 175,813 | 158,789 | ||||||||||
Other | 64,162 | 63,288 | 66,370 | 63,288 | ||||||||||
| ||||||||||||||
717,473 | 710,704 | 739,157 | 710,704 | |||||||||||
| ||||||||||||||
$ | 9,046,994 | $ | 9,095,212 | $ | 9,261,680 | $ | 9,095,212 | |||||||
| | |||||||||||||
The accompanying notes are an integral part of these condensed financial statements.
Oglethorpe Power Corporation
Condensed Statements of Revenues and Expenses (Unaudited)
For the Three and Six Months Ended March 31,June 30, 2014 and 2013
(dollars in thousands) | (dollars in thousands) | |||||||||||||||||||
Three Months | Three Months | Six Months | ||||||||||||||||||
2014 | 2013 | 2014 | 2013 | 2014 | 2013 | |||||||||||||||
Operating revenues: | ||||||||||||||||||||
Sales to Members | $ | 334,759 | $ | 286,653 | $ | 338,116 | $ | 306,191 | $ | 672,875 | $ | 592,844 | ||||||||
Sales to non-Members | 32,541 | 19,261 | 17,867 | 18,158 | 50,408 | 37,419 | ||||||||||||||
| ||||||||||||||||||||
Total operating revenues | 367,300 | 305,914 | 355,983 | 324,349 | 723,283 | 630,263 | ||||||||||||||
| ||||||||||||||||||||
Operating expenses: | ||||||||||||||||||||
Fuel | 132,276 | 100,150 | 133,976 | 113,065 | 266,252 | 213,215 | ||||||||||||||
Production | 108,084 | 94,720 | 99,004 | 89,294 | 207,088 | 184,014 | ||||||||||||||
Depreciation and amortization | 40,714 | 37,083 | 41,404 | 38,578 | 82,118 | 75,661 | ||||||||||||||
Purchased power | 20,066 | 12,667 | 16,312 | 14,717 | 36,378 | 27,384 | ||||||||||||||
Accretion | 6,018 | 5,630 | 6,108 | 5,677 | 12,126 | 11,307 | ||||||||||||||
Deferral of Hawk Road and Smith Energy Facilities effect on net margin | (9,715 | ) | (11,890 | ) | (10,421 | ) | (6,777 | ) | (20,136 | ) | (18,667 | ) | ||||||||
| ||||||||||||||||||||
Total operating expenses | 297,443 | 238,360 | 286,383 | 254,554 | 583,826 | 492,914 | ||||||||||||||
| ||||||||||||||||||||
Operating margin | 69,857 | 67,554 | 69,600 | 69,795 | 139,457 | 137,349 | ||||||||||||||
| ||||||||||||||||||||
Other income: | ||||||||||||||||||||
Investment income | 9,282 | 7,277 | 9,145 | 8,148 | 18,427 | 15,425 | ||||||||||||||
Other | 2,377 | 2,277 | 2,232 | 2,240 | 4,609 | 4,517 | ||||||||||||||
| ||||||||||||||||||||
Total other income | 11,659 | 9,554 | 11,377 | 10,388 | 23,036 | 19,942 | ||||||||||||||
| ||||||||||||||||||||
Interest charges: | ||||||||||||||||||||
Interest expense | 81,917 | 75,777 | 85,965 | 76,251 | 167,882 | 152,028 | ||||||||||||||
Allowance for debt funds used during construction | (23,729 | ) | (24,854 | ) | (26,385 | ) | (24,562 | ) | (50,114 | ) | (49,416 | ) | ||||||||
Amortization of debt discount and expense | 4,105 | 4,161 | 4,201 | 3,992 | 8,306 | 8,153 | ||||||||||||||
| ||||||||||||||||||||
Net interest charges | 62,293 | 55,084 | 63,781 | 55,681 | 126,074 | 110,765 | ||||||||||||||
| ||||||||||||||||||||
Net margin | $ | 19,223 | $ | 22,024 | $ | 17,196 | $ | 24,502 | $ | 36,419 | $ | 46,526 | ||||||||
| | |||||||||||||||||||
The accompanying notes are an integral part of these condensed financial statements.
Oglethorpe Power Corporation
Condensed Statements of Comprehensive Margin (Unaudited)
For the Three and Six Months Ended March 31,June 30, 2014 and 2013
(dollars in thousands) | (dollars in thousands) | |||||||||||||||||||
Three Months | Three Months | Six Months | ||||||||||||||||||
2014 | 2013 | 2014 | 2013 | 2014 | 2013 | |||||||||||||||
Net margin | $ | 19,223 | $ | 22,024 | $ | 17,196 | $ | 24,502 | $ | 36,419 | $ | 46,526 | ||||||||
| | | | | | | | | | |||||||||||
Other comprehensive margin: | ||||||||||||||||||||
Unrealized gain (loss) on available-for-sale securities | 396 | (212 | ) | 431 | (1,090 | ) | 827 | (1,302 | ) | |||||||||||
| ||||||||||||||||||||
Total comprehensive margin | $ | 19,619 | $ | 21,812 | $ | 17,627 | $ | 23,412 | $ | 37,246 | $ | 45,224 | ||||||||
| | |||||||||||||||||||
The accompanying notes are an integral part of these condensed financial statements.
Oglethorpe Power Corporation
Condensed Statements of Patronage Capital and Membership Fees
and Accumulated Other Comprehensive Margin (Deficit) (Unaudited)
For the ThreeSix Months Ended March 31,June 30, 2014 and 2013
(dollars in thousands) | (dollars in thousands) | |||||||||||||||||||
Patronage Capital and Membership Fees | Accumulated Other Comprehensive Margin (Deficit) | Total | Patronage Capital and Membership Fees | Accumulated Other Comprehensive Margin (Deficit) | Total | |||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Balance at December 31, 2012 | $ | 673,009 | $ | 903 | $ | 673,912 | $ | 673,009 | $ | 903 | $ | 673,912 | ||||||||
Components of comprehensive margin: | ||||||||||||||||||||
Net margin | 22,024 | — | 22,024 | 46,526 | — | 46,526 | ||||||||||||||
Unrealized (loss) on available-for-sale securities | — | (212 | ) | (212 | ) | — | (1,302 | ) | (1,302 | ) | ||||||||||
Balance at March 31, 2013 | $ | 695,033 | $ | 691 | $ | 695,724 | ||||||||||||||
Balance at June 30, 2013 | $ | 719,535 | $ | (399 | ) | $ | 719,136 | |||||||||||||
Balance at December 31, 2013 | $ | 714,489 | $ | (549 | ) | $ | 713,940 | $ | 714,489 | $ | (549 | ) | $ | 713,940 | ||||||
Components of comprehensive margin: | ||||||||||||||||||||
Net margin | 19,223 | — | 19,223 | 36,419 | — | 36,419 | ||||||||||||||
Unrealized gain on available-for-sale securities | — | 396 | 396 | — | 827 | 827 | ||||||||||||||
Balance at March 31, 2014 | $ | 733,712 | $ | (153 | ) | $ | 733,559 | |||||||||||||
Balance at June 30, 2014 | $ | 750,908 | $ | 278 | $ | 751,186 | ||||||||||||||
The accompanying notes are an integral part of these condensed financial statements.
Oglethorpe Power Corporation
Condensed Statements of Cash Flows (Unaudited)
For the ThreeSix Months Ended March 31,June 30, 2014 and 2013
(dollars in thousands) | (dollars in thousands) | |||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||
Cash flows from operating activities: | ||||||||||||||
Net margin | $ | 19,223 | $ | 22,024 | $ | 36,419 | $ | 46,526 | ||||||
| ||||||||||||||
Adjustments to reconcile net margin to net cash provided by operating activities: | ||||||||||||||
Depreciation and amortization, including nuclear fuel | 74,880 | 68,384 | 153,759 | 141,876 | ||||||||||
Accretion cost | 6,018 | 5,630 | 12,126 | 11,307 | ||||||||||
Amortization of deferred gains | (447 | ) | (447 | ) | (894 | ) | (893 | ) | ||||||
Allowance for equity funds used during construction | (389 | ) | (752 | ) | (731 | ) | (1,411 | ) | ||||||
Deferred outage costs | (25,845 | ) | (23,911 | ) | (31,411 | ) | (31,820 | ) | ||||||
Deferral of Hawk Road and Smith Energy Facilities effect on net margin | (9,715 | ) | (11,890 | ) | (20,136 | ) | (18,667 | ) | ||||||
Gain on sale of investments | (3,996 | ) | (3,529 | ) | (8,961 | ) | (17,304 | ) | ||||||
Regulatory deferral of costs associated with nuclear decommissioning | (84 | ) | (97 | ) | 1,571 | 10,085 | ||||||||
Other | 1,384 | (2,119 | ) | 6,816 | (3,551 | ) | ||||||||
Change in operating assets and liabilities: | ||||||||||||||
Receivables | (1,799 | ) | 6,124 | (21,180 | ) | (28,158 | ) | |||||||
Inventories | 24,827 | 10,181 | 32,455 | (3,902 | ) | |||||||||
Prepayments and other current assets | 1,892 | 1,794 | 1,209 | (1,872 | ) | |||||||||
Accounts payable | (33,330 | ) | (70,675 | ) | (45,456 | ) | (43,540 | ) | ||||||
Accrued interest | (8,804 | ) | 14,451 | 183 | 31,022 | |||||||||
Accrued taxes | (13,144 | ) | 4,634 | (3,978 | ) | 12,808 | ||||||||
Other current liabilities | (2,075 | ) | (2,892 | ) | (2,479 | ) | (5,067 | ) | ||||||
Member power bill prepayments | 12,105 | 84,903 | 14,475 | 50,860 | ||||||||||
| ||||||||||||||
Total adjustments | 21,478 | 79,789 | 87,368 | 101,773 | ||||||||||
| ||||||||||||||
Net cash provided by operating activities | 40,701 | 101,813 | 123,787 | 148,299 | ||||||||||
| ||||||||||||||
Cash flows from investing activities: | ||||||||||||||
Property additions | (134,354 | ) | (180,365 | ) | (249,317 | ) | (321,246 | ) | ||||||
Activity in decommissioning fund—Purchases | (101,894 | ) | (106,460 | ) | (188,815 | ) | (346,211 | ) | ||||||
—Proceeds | 100,648 | 105,148 | 186,165 | 343,340 | ||||||||||
Decrease (increase) in restricted cash | 24,239 | (4,410 | ) | 32,209 | (27,121 | ) | ||||||||
Increase in restricted short-term investments | (16,783 | ) | (139,127 | ) | (21,173 | ) | (141,540 | ) | ||||||
Activity in other long-term investments—Purchases | (12,220 | ) | (6,394 | ) | (28,690 | ) | (19,670 | ) | ||||||
—Proceeds | 12,413 | 6,633 | 30,385 | 20,103 | ||||||||||
Activity on interest rate options—Collateral returned | (46,940 | ) | (17,440 | ) | (73,850 | ) | (46,420 | ) | ||||||
—Collateral received | 22,700 | 21,850 | 41,640 | 73,540 | ||||||||||
Other | (401 | ) | 2,076 | 473 | 1,269 | |||||||||
| ||||||||||||||
Net cash used in investing activities | (152,592 | ) | (318,489 | ) | (270,973 | ) | (463,956 | ) | ||||||
| ||||||||||||||
Cash flows from financing activities: | ||||||||||||||
Long-term debt proceeds | 734,608 | 20,734 | 993,707 | 283,168 | ||||||||||
Long-term debt payments | (295,740 | ) | (215,663 | ) | (333,127 | ) | (244,042 | ) | ||||||
Decrease (Increase) in short-term borrowings, net | (474,720 | ) | 351,944 | |||||||||||
(Decrease) increase in short-term borrowings, net | (548,494 | ) | 201,391 | |||||||||||
Other | (41,957 | ) | 610 | (43,227 | ) | (2,775 | ) | |||||||
| ||||||||||||||
Net cash (used in) provided by financing activities | (77,809 | ) | 157,625 | |||||||||||
Net cash provided by financing activities | 68,859 | 237,742 | ||||||||||||
| ||||||||||||||
Net decrease in cash and cash equivalents | (189,700 | ) | (59,051 | ) | (78,327 | ) | (77,915 | ) | ||||||
Cash and cash equivalents at beginning of period | 408,193 | 298,565 | 408,193 | 298,565 | ||||||||||
| ||||||||||||||
Cash and cash equivalents at end of period | $ | 218,493 | $ | 239,514 | $ | 329,866 | $ | 220,650 | ||||||
| | |||||||||||||
Supplemental cash flow information: | ||||||||||||||
Cash paid for— | ||||||||||||||
Interest (net of amounts capitalized) | $ | 65,816 | $ | 35,312 | $ | 115,231 | $ | 69,269 | ||||||
Supplemental disclosure of non-cash investing and financing activities: | ||||||||||||||
Change in plant expenditures included in accounts payable | $ | 6,463 | $ | 1,420 | $ | 22,904 | $ | (19,846 | ) |
The accompanying notes are an integral part of these condensed financial statements.
Oglethorpe Power Corporation
Notes to Unaudited Condensed Financial Statements
For the Three and Six Months ended March 31,June 30, 2014 and 2013
The guidance establishes a three-tier fair value hierarchy which prioritizes the inputs used in measuring fair value as follows:
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 March 31,June 30, 2014 and December 31, 2013.
| Fair Value Measurements at Reporting Date Using | Fair Value Measurements at Reporting Date Using | ||||||||||||||||||||||||
March 31, | Quoted Prices in | Significant Other | Significant | June 30, | Quoted Prices in | Significant Other | Significant | |||||||||||||||||||
(dollars in thousands) | (dollars in thousands) | |||||||||||||||||||||||||
Nuclear decommissioning trust funds: | ||||||||||||||||||||||||||
Domestic equity | $ | 145,202 | $ | 145,202 | $ | — | $ | — | $ | 151,899 | $ | 151,899 | $ | — | $ | — | ||||||||||
International equity trust | 73,159 | — | 73,159 | — | 76,447 | — | 76,447 | — | ||||||||||||||||||
Corporate bonds | 39,492 | — | 39,492 | — | 29,511 | — | 29,511 | — | ||||||||||||||||||
US Treasury and government agency securities | 49,026 | 49,026 | — | — | 60,709 | 60,709 | — | — | ||||||||||||||||||
Agency mortgage and asset backed securities | 29,654 | — | 29,654 | — | 26,920 | — | 26,920 | — | ||||||||||||||||||
Government bonds | 2,012 | — | 2,012 | — | ||||||||||||||||||||||
Other | 11,564 | 11,564 | — | — | 14,248 | 14,248 | — | — | ||||||||||||||||||
Long-term investments: | ||||||||||||||||||||||||||
Corporate bonds | 6,154 | — | 6,154 | — | 4,698 | — | 4,698 | — | ||||||||||||||||||
US Treasury and government agency securities | 9,883 | 9,883 | — | — | 13,702 | 13,702 | — | — | ||||||||||||||||||
Agency mortgage and asset backed securities | 3,267 | — | 3,267 | — | 1,870 | — | 1,870 | — | ||||||||||||||||||
International equity trust | 11,259 | — | 11,259 | — | 11,768 | — | 11,768 | — | ||||||||||||||||||
Mutual funds | 51,986 | 51,986 | — | — | 51,368 | 51,368 | — | — | ||||||||||||||||||
Other | 44 | 44 | — | — | 139 | 139 | — | — | ||||||||||||||||||
Interest rate options | 31,463 | — | — | 31,463 | (1) | 18,535 | — | — | 18,535 | (1) | ||||||||||||||||
Natural gas swaps | 1,960 | — | 1,960 | — | 1,250 | — | 1,250 | — | ||||||||||||||||||
Fair Value Measurements at Reporting Date Using | |||||||||||||
December 31, | Quoted Prices in | Significant Other | Significant | ||||||||||
(dollars in thousands) | |||||||||||||
Nuclear decommissioning trust funds: | |||||||||||||
Domestic equity | $ | 143,929 | $ | 143,929 | $ | — | $ | — | |||||
International equity trust | 72,466 | — | 72,466 | — | |||||||||
Corporate bonds | 39,863 | — | 39,863 | — | |||||||||
US Treasury and government agency securities | 44,846 | 44,846 | — | — | |||||||||
Agency mortgage and asset backed securities | 30,133 | — | 30,133 | — | |||||||||
Municipal Bonds | 641 | — | 641 | — | |||||||||
Other | 11,820 | 11,820 | — | — | |||||||||
Long-term investments: | |||||||||||||
Corporate bonds | 6,487 | — | 6,487 | — | |||||||||
US Treasury and government agency securities | 8,563 | 8,563 | — | — | |||||||||
Agency mortgage and asset backed securities | 3,679 | — | 3,679 | — | |||||||||
International equity trust | 11,148 | — | 11,148 | — | |||||||||
Mutual funds | 51,559 | 51,559 | — | — | |||||||||
Other | 284 | 284 | — | — | |||||||||
Interest rate options | 63,471 | — | — | 63,471 | (1) | ||||||||
Natural gas swaps | 1,011 | — | 1,011 | — | |||||||||
The Level 2 investments above in international equity trust, corporate bonds and agency mortgage and asset backed securities may not be exchange traded. The fair value measurements for these investments are based on a market approach, including the use of observable inputs. Common inputs include reported trades and broker/dealer bid/ask prices. The fair value of the Level 2 investments above in international equity trust are calculated based on the net asset value per share of the fund. There are no unfunded commitments for the international equity trust and redemption may occur daily with a 3-day redemption notice period.
The following tables present the changes in Level 3 assets measured at fair value on a recurring basis during the three and six months ended March 31,June 30, 2014 and 2013.
Three Months Ended March 31, 2014 | Three Months Ended June 30, 2014 | |||||||
Interest rate options | Interest rate options | |||||||
(dollars in thousands) | (dollars in thousands) | |||||||
Balance at December 31, 2013 | $ | 63,471 | ||||||
Assets (Liabilities): | ||||||||
Balance at March 31, 2014 | $ | 31,463 | ||||||
Total gains or losses (realized/unrealized): | ||||||||
Included in earnings (or changes in net assets) | (32,008 | ) | (12,928 | ) | ||||
| ||||||||
Balance at March 31, 2014 | $ | 31,463 | ||||||
Balance at June 30, 2014 | $ | 18,535 | ||||||
| | |||||||
Three Months Ended June 30, 2013 | ||||
Interest rate options | ||||
(dollars in thousands) | ||||
Assets (Liabilities): | ||||
Balance at March 31, 2013 | $ | 26,539 | ||
Total gains or losses (realized/unrealized): | ||||
Included in earnings (or changes in net assets) | 17,141 | |||
| | | | |
Balance at June 30, 2013 | $ | 43,680 | ||
| | | | |
| | | | |
Six Months Ended June 30, 2014 | ||||
Interest rate options | ||||
(dollars in thousands) | ||||
Assets (Liabilities): | ||||
Balance at December 31, 2013 | $ | 63,471 | ||
Total gains or losses (realized/unrealized): | ||||
Included in earnings (or changes in net assets) | (44,936 | ) | ||
| | | | |
Balance at June 30, 2014 | $ | 18,535 | ||
| | | | |
| | | | |
Three Months Ended March 31, 2013 | Six Months Ended June 30, 2013 | |||||||
Interest rate options | Interest rate options | |||||||
(dollars in thousands) | (dollars in thousands) | |||||||
Assets (Liabilities): | ||||||||
Balance at December 31, 2012 | $ | 25,783 | $ | 25,783 | ||||
Total gains or losses (realized/unrealized): | ||||||||
Included in earnings (or changes in net assets) | 756 | 17,897 | ||||||
| ||||||||
Balance at March 31, 2013 | $ | 26,539 | ||||||
Balance at June 30, 2013 | $ | 43,680 | ||||||
| ||||||||
| | | | |||||
We estimate the value of the interest rate options as the sum of time value and any intrinsic value minus a counterparty credit adjustment. Intrinsic value is the value of the underlying swap, which we are able to calculate based on the forward LIBOR swap rates, the fixed rate on the underlying swap, the time to expiration, the term of the underlying swap and discount rates, all of which we are able to effectively observe. Time value is the additional value of the swaption due to the fact that it is an option. We estimate the time value using an option pricing model which, in addition to the factors used to calculate intrinsic value, also takes into account option volatility, which we estimate based on option valuations we obtain from various sources. We estimate the counterparty credit adjustment by observing credit attributes, including the credit default swap spread of entities similar to the counterparty and the amount of credit support that is available for each swaption. Since the primary component of the LIBOR swaptions' value is time value, which is based on estimated option volatility derived from valuations of comparable instruments that are generally not publicly available, we have categorized these LIBOR swaptions as Level 3. We believe the estimated fair values for the LIBOR swaptions we hold are based on the most accurate information available for these types of derivative contracts. For additional information regarding our interest rate options, see Note C.
The estimated fair values of our long-term debt, including current maturities at March 31,June 30, 2014 and December 31, 2013 were as follows (in thousands):
2014 | 2013 | ||||||||||||
Carrying Value | Fair Value | Carrying Value | Fair Value | ||||||||||
Long-term debt | $ | 6,933,851 | $ | 7,534,625 | $ | 6,954,293 | $ | 7,317,476 | |||||
2014 | 2013 | ||||||||||||
Carrying Value | Fair Value | Carrying Value | Fair Value | ||||||||||
Long-term debt | $ | 7,168,443 | $ | 7,971,425 | $ | 6,954,293 | $ | 7,317,476 | |||||
Long-term debt is classified as Level 2 and is estimated based on observed or quoted market prices for the same or similar issues or on current rates offered to us for debt of similar maturities. The primary sources of our long-term debt consist of first mortgage bonds, pollution control revenue bonds and long-term debt issued by the Federal Financing Bank that is guaranteed by the Rural Utilities Service or the U.S. Department of Energy. We also have small amounts of long-term debt provided by National Rural Utilities Cooperative Finance Corporation (CFC) and by CoBank, ACB. The valuations for the first mortgage bonds and the pollution control revenue bonds were obtained from third party investment banking firms and a third party subscription service, and are based on secondary market trading of our debt. Valuations for debt issued by the Federal Financing Bank are based on U.S. Treasury rates as of March 31,June 30, 2014 plus an applicable spread, which reflects our borrowing rate for new loans of this type from the Federal Financing Bank. We use an interest rate quote sheet provided by CoBank for valuation of the CoBank debt,
which reflects current rates for a similar loan. The rates on the CFC debt are fixed and the valuation is based on rate quotes provided by CFC.
For cash and cash equivalents, restricted cash and receivables, the carrying amount approximates fair value because of the short-term maturity of those instruments.
We are exposed to credit risk as a result of entering into these hedging arrangements. Credit risk is the potential loss resulting from a counterparty's nonperformance under an agreement. We have established policies and procedures to manage credit risk through counterparty analysis, exposure calculation and monitoring, exposure limits, collateralization and certain other contractual provisions.
It is possible that volatility in commodity prices and/or interest rates could cause us to have credit risk exposures with one or more counterparties. We currently have credit risk exposure to our interest rate options counterparties. If such counterparties fail to perform their obligations, we could suffer a financial loss. However, as of March 31,June 30, 2014, all of the counterparties with transaction amounts outstanding under our hedging programs are rated investment grade by the major rating agencies or have provided a guaranty from one of their affiliates that is rated investment grade.
We have entered into International Swaps and Derivatives Association agreements with our natural gas hedge and interest rate option counterparties that mitigate credit exposure by creating contractual rights relating to creditworthiness, collateral, termination and netting (which, in certain cases, allows us to use the net value of affected transactions with the same counterparty in the event of default by the counterparty or early termination of the agreement).
Additionally, we have implemented procedures to monitor the creditworthiness of our counterparties and to evaluate nonperformance in valuing counterparty positions. We have contracted with a third party to assist in monitoring certain of our counterparties' credit standing and condition. Net liability positions are generally not adjusted as we use derivative transactions as hedges and have the ability and intent to perform under each of our contracts. In the instance of net asset positions, we consider general market conditions and the observable financial health and outlook of specific counterparties, forward looking data such as credit default swaps, when available, and historical default probabilities from credit rating agencies in evaluating the potential impact of nonperformance risk to derivative positions.
The contractual agreements contain provisions that could require us or the counterparty to post collateral or credit support. The amount of collateral or credit support that could be required is calculated as the difference between the aggregate fair value of the hedges and pre-established credit thresholds. The credit thresholds are contingent upon each party's credit ratings from the
major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty.
Gas hedges. Under theour 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 March 31,June 30, 2014 and December 31, 2013, the estimated fair valuesvalue of our natural gas contracts were a net asset of approximately $1,960,000$1,250,000 and $1,011,000, respectively.
As of March 31,June 30, 2014 and December 31, 2013, neither we nor any counterparties were required to post credit support or collateral under thethese natural gas swap agreements. If the credit-risk-related contingent features underlying these agreements had been triggered on March 31,June 30, 2014 due to our credit rating being downgraded below investment grade, we would not have been required to post letters of credit with our counterparties.
The following table reflects the volume activity of our natural gas derivatives as of March 31,June 30, 2014 that is expected to settle or mature each year:
Year | Natural Gas Swaps | Natural Gas Swaps | ||||||
2014 | 3.9 | 2.9 | ||||||
2015 | 1.1 | 1.1 | ||||||
2016 | 0.2 | |||||||
| ||||||||
Total | 5.0 | 4.2 | ||||||
Interest rate options. We are exposed to the risk of rising interest rates due to the significant amount of newwhen we incur long-term debt we expect to incur in connection with anticipated capital expenditures, particularly the construction of Vogtle Units No. 3 and No. 4. In the fourth quarter of 2011, we purchased LIBOR swaptions at a cost of $100,000,000 with a total notional amount of approximately $2,200,000,000 to hedge the interest rates on approximately $2.2 billiona portion of the expected debt that will be usedwe are incurring to finance two additional nuclear units at Plant Vogtle. AsSince 2013, swaptions having a notional amount of March 31,approximately $1,100,000,000 have expired and as of June 30, 2014, the remaining notional amount of our outstanding swaptions hedgedwas approximately $1.3 billion of the expected debt for the new Vogtle units.$1,100,000,000.
The LIBOR swaptions are each designed to cap our effective interest rate at a specified fixed interest rate on a specified option expiration date. This is accomplished by means of a payment of the cash settlement value our counterparties are obligated to make to us if prevailing fixed LIBOR swap rates exceed the specified fixed rate on the option expiration date. This payment would partially offset our interest costs, thereby reducing our effective interest rate. The cash settlement value would be zero if swap rates are at or below the specified fixed rate on the expiration date. The cash settlement value is calculated based on the value of an underlying swap which we have the right, but not the obligation, to enter into, which would begin on the option expiration date and extend until 2042 and under which we would pay the specified fixed rate and receive a floating LIBOR rate. The fixed rates on the unexpired swaptions we hold average 85107 basis points above the corresponding LIBOR swap rates that were in effect as of March 31,June 30, 2014 and the weighted average fixed rate is 4.12%4.11%. Swaptions having notional amounts totaling $138,317,000$278,145,000 expired without value during the threesix months ended March 31,June 30, 2014. The remaining swaptions expire quarterly through 2017.
We paid all the premiums to purchase these LIBOR swaptions at the time we entered into these transactions and have no additional payment obligations. These derivatives are recorded at fair
value. At March 31,June 30, 2014 and December 31, 2013, the fair value of these swaptions was approximately $31,463,000$18,535,000 and $63,471,000, respectively. To manage our credit exposure to our counterparties, we negotiated credit support provisions that require each counterparty to provide us collateral in the form of cash or securities to the extent that the value of the swaptions outstanding for that counterparty exceeds a certain threshold. The collateral thresholds can range from $0 to $10,000,000 depending on each counterparty's credit rating. As of March 31,June 30, 2014 and December 31, 2013, we held $10,730,000$2,760,000 and $34,970,000 of funds posted as collateral by the counterparties, respectively. The collateral received is recorded as restricted cash on our balance sheet. The liability associated with the collateral is recorded as an offset to the fair values of the swaptions, which are recorded within other deferred charges on the balance sheet, resulting in a net carrying amount of the interest rate options of $20,733,000$15,775,000 and $28,501,000 at March 31,June 30, 2014 and December 31, 2013, respectively.
We are deferring unrealized gains or losses from the change in fair value of each LIBOR swaption and related carrying and other incidental costs in accordance with our rate-making treatment. The realized deferred costs and deferred gains, if any, from the settlement of the interest rate options will be amortized and collected in rates over the life of the $2.2 billion of debt that we hedged with the swaptions.
The following table reflects the remaining notional amount of forecasted debt issuances we have hedged in each year with LIBOR swaptions as of March 31,June 30, 2014.
Year | LIBOR Swaption | LIBOR Swaption | ||||||
2014 | $ | 425,107 | $ | 285,280 | ||||
2015 | 470,625 | 470,625 | ||||||
2016 | 310,533 | 310,533 | ||||||
2017 | 80,169 | 80,169 | ||||||
| ||||||||
Total | $ | 1,286,434 | $ | 1,146,607 | ||||
The table below reflects the fair value of derivative instruments and their effect on our condensed balance sheets at March 31,June 30, 2014 and December 31, 2013.
Balance Sheet Location | Fair Value | ||||||||
2014 | 2013 | ||||||||
(dollars in thousands) | |||||||||
Not designated as hedges: | |||||||||
Assets: | |||||||||
Interest rate options(1) | Other deferred charges | $ | 31,463 | $ | 63,471 | ||||
Liabilities: | |||||||||
Natural gas swaps | Other current liabilities | $ | 1,960 | $ | 1,011 |
Balance Sheet | Fair Value | ||||||||
2014 | 2013 | ||||||||
| (dollars in thousands) | ||||||||
Not designated as hedges: | |||||||||
Assets: |
| ||||||||
Interest rate options(1) | Other deferred charges | $ | 18,535 | $ | 63,471 | ||||
Liabilities: |
| ||||||||
Natural gas swaps | Other current liabilities | $ | 1,250 | $ | 1,011 | ||||
The following table presents the gross realized gains and (losses) on derivative instruments recognized in margin for the three and six months ended March 31,June 30, 2014 and 2013.
Statement of Revenues and | Three months ended March 31, | Statement of | Three months ended | Six months ended | ||||||||||||||||||||
Expenses Location | 2014 | 2013 | Location | 2014 | 2013 | 2014 | 2013 | |||||||||||||||||
(dollars in thousands) | (dollars in thousands) | |||||||||||||||||||||||
Not Designated as hedges: | ||||||||||||||||||||||||
Natural Gas Swaps | Fuel | $ | 279 | $ | 117 | Fuel | $ | 956 | $ | 449 | $ | 1,236 | $ | 566 | ||||||||||
Natural Gas Swaps | Fuel | — | (534 | ) | Fuel | — | (379 | ) | — | (913 | ) | |||||||||||||
| ||||||||||||||||||||||||
$ | 279 | $ | (417 | ) | $ | 956 | $ | 70 | $ | 1,236 | $ | (347 | ) | |||||||||||
| | |||||||||||||||||||||||
The following table presents the unrealized gains and (losses) on derivative instruments deferred on the balance sheet at March 31,June 30, 2014 and December 31, 2013.
Balance Sheet Location | 2014 | 2013 | Balance Sheet | 2014 | 2013 | |||||||||||||
(dollars in thousands) | (dollars in thousands) | |||||||||||||||||
Not designated as hedges: | Not designated as hedges: | Not designated as hedges: | ||||||||||||||||
Natural gas swaps | Regulatory liability | $ | 1,960 | $ | 1,011 | Regulatory liability | $ | 1,250 | $ | 1,011 | ||||||||
Interest rate options | Regulatory asset | (41,720 | ) | (15,003 | ) | Regulatory asset | (48,669 | ) | (15,003 | ) | ||||||||
$ | (39,760 | ) | $ | (13,992 | ) | $ | (47,419 | ) | $ | (13,992 | ) | |||||||
The following table presents the gross amounts of derivatives and their related offset amounts as permitted by their respective master netting agreements and obligations to return cash collateral.
Gross Amounts of Recognized Assets (Liabilities) | Gross Amounts offset on the Balance Sheet | Cash Collateral | Net Amounts of Assets Presented on the Balance Sheet | Gross Amounts of Recognized Assets (Liabilities) | Gross Amounts offset on the Balance Sheet | Cash Collateral | Net Amounts of Assets Presented on the Balance Sheet | |||||||||||||||||||
(dollars in thousands) | (dollars in thousands) | |||||||||||||||||||||||||
March 31, 2014 | ||||||||||||||||||||||||||
June 30, 2014 | ||||||||||||||||||||||||||
Assets: | ||||||||||||||||||||||||||
Natural gas swaps | $ | 2,054 | $ | (94 | ) | $ | — | $ | 1,960 | $ | 1,356 | $ | (106 | ) | $ | — | $ | 1,250 | ||||||||
Interest rate options | $ | 31,463 | $ | — | $ | (10,730 | ) | $ | 20,733 | $ | 18,535 | $ | — | $ | (2,760 | ) | $ | 15,775 | ||||||||
December 31, 2013 | ||||||||||||||||||||||||||
Assets: | ||||||||||||||||||||||||||
Natural gas swaps | $ | 1,069 | $ | (58 | ) | $ | — | $ | 1,011 | $ | 1,069 | $ | (58 | ) | $ | — | $ | 1,011 | ||||||||
Interest rate options | $ | 63,471 | $ | — | $ | (34,970 | ) | $ | 28,501 | $ | 63,471 | $ | — | $ | (34,970 | ) | $ | 28,501 | ||||||||
the regulatory asset for asset retirement obligations. Realized gains and losses on the nuclear
decommissioning trust fundfunds are also recorded to the regulatory asset. All realized and unrealized gains and losses are determined using the specific identification method. Approximately 86%As of June 30, 2014, approximately 90% of these gross unrealized losses were in effect for less than one year.
The following tables summarize the activities for available-for-sale securities as of March 31,June 30, 2014 and December 31, 2013.
Gross Unrealized | Gross Unrealized | |||||||||||||||||||||||||
(dollars in thousands) | (dollars in thousands) | |||||||||||||||||||||||||
March 31, 2014 | Cost | Gains | Losses | Fair Value | ||||||||||||||||||||||
June 30, 2014 | Cost | Gains | Losses | Fair Value | ||||||||||||||||||||||
Equity | $ | 187,463 | $ | 66,283 | $ | (1,190 | ) | $ | 252,556 | $ | 191,821 | $ | 73,297 | $ | (935 | ) | $ | 264,183 | ||||||||
Debt | 165,776 | 8,509 | (7,759 | ) | 166,526 | 163,504 | 10,484 | (7,269 | ) | 166,719 | ||||||||||||||||
Other | 11,607 | 2 | (1 | ) | 11,608 | 14,388 | 2 | (1 | ) | 14,389 | ||||||||||||||||
Total | $ | 364,846 | $ | 74,794 | $ | (8,950 | ) | $ | 430,690 | $ | 369,713 | $ | 83,783 | $ | (8,205 | ) | $ | 445,291 | ||||||||
Gross Unrealized | |||||||||||||
(dollars in thousands) | |||||||||||||
December 31, 2013 | Cost | Gains | Losses | Fair Value | |||||||||
Equity | $ | 182,755 | $ | 68,424 | $ | (1,053 | ) | $ | 250,126 | ||||
Debt | 164,941 | 7,319 | (9,070 | ) | 163,190 | ||||||||
Other | 12,101 | 2 | — | 12,103 | |||||||||
Total | $ | 359,797 | $ | 75,745 | $ | (10,123 | ) | $ | 425,419 | ||||
Our effective tax rate is zero; therefore, all amounts below are presented net of tax.
| Accumulated Other Comprehensive Margin (Deficit) Three Months Ended | Accumulated Other Comprehensive Margin (Deficit) Three Months Ended | ||||||
---|---|---|---|---|---|---|---|---|
(dollars in thousands) | (dollars in thousands) | |||||||
Available-for-sale | Available-for-sale | |||||||
| ||||||||
Balance at December 31, 2012 | $ | 903 | ||||||
Balance at March 31, 2013 | $ | 691 | ||||||
Unrealized (loss) | (148 | ) | (1,074 | ) | ||||
(Gain) reclassified to net margin | (64 | ) | (16 | ) | ||||
| ||||||||
Balance at March 31, 2013 | $ | 691 | ||||||
| | | ||||||
Balance at December 31, 2013 | $ | (549 | ) | |||||
Unrealized gain | 390 | |||||||
Loss reclassified to net margin | 6 | |||||||
Balance at June 30, 2013 | $ | (399 | ) | |||||
| ||||||||
Balance at March 31, 2014 | $ | (153 | ) | $ | (153 | ) | ||
Unrealized gain | 492 | |||||||
(Gain) reclassified to net margin | (61 | ) | ||||||
| ||||||||
Balance at June 30, 2014 | $ | 278 | ||||||
| | | | |||||
| Six Months Ended | |||
---|---|---|---|---|
(dollars in thousands) | ||||
Available-for-sale | ||||
| | | | |
Balance at December 31, 2012 | $ | 903 | ||
Unrealized (loss) | (1,222 | ) | ||
(Gain) reclassified to net margin | (80 | ) | ||
| | | | |
Balance at June 30, 2013 | $ | (399 | ) | |
| | | | |
Balance at December 31, 2013 | $ | (549 | ) | |
Unrealized gain | 881 | |||
(Gain) reclassified to net margin | (54 | ) | ||
| | | | |
Balance at June 30, 2014 | $ | 278 | ||
| | | | |
Management does not anticipate that the liabilities, if any, for any current proceedings against us will have a material effect on our financial condition or results of operations. However, at this time, the ultimate outcome of any pending or potential litigation cannot be determined.
a. Nuclear Construction
In April 2008, Georgia Power Company, acting for itself and as agent for us, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia (collectively, the Co-owners), and Westinghouse Electric Company LLC and Stone & Webster, Inc. (collectively, the Contractor) entered into an engineering, procurement, and construction agreement (Vogtle No. 3 and No. 4 Agreement) to design, engineer, procure, and construct two AP1000 nuclear units with electric generating capacity of approximately 1,100 megawatts each and related facilities, structures, and improvements at Plant Vogtle (Vogtle Units No. 3 and No. 4).
Under the Vogtle Units No. 3 and No. 4 Agreement,agreement, the Co-Owners and the Contractor have established both informal and formal dispute resolution procedures in order to resolve issues arising during the course of constructing a project of this magnitude. Georgia Power, on behalf of the Co-owners, has successfully initiated both formal and informal claims through these procedures, including ongoing claims. When matters are not resolved through these procedures, the parties may proceed to litigation. The Contractor and the Co-owners are involved in litigation with respect to certain claims that have not been resolved through the formal dispute resolution process.
Current litigation relates to costs associated with design changes to the Westinghouse AP1000 Design Control Document (DCD) and costs associated with delays in the project schedule related to the timing of approval of the DCD and issuance of the combined construction permits and operating licenses by the Nuclear Regulatory Commission. In July 2012, the Co-owners and Contractor began negotiations regarding these costs, including the assertion by the Contractor that
the Co-owners are responsible for these costs under the terms of the contract. The portion of the additional costs claimed by the Contractor that would be attributable to us, based on our ownership interest, is approximately $280,000,000 in 2008 dollars with respect to these issues. The Contractor has also asserted that it is entitled to further schedule extensions. Georgia Power, on behalf of the Co-owners, has not agreed with either the proposed cost or schedule adjustments or that the Co-owners have any responsibility for costs related to these issues.agreement. On November 1, 2012, the Co-owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia, seeking a declaratory judgment that the Co-owners are not responsible for these costs. Also on November 1, 2012, the Contractor filed suit against the Co-owners in the U.S. District Court for the District of Columbia alleging the Co-owners are responsible for these costs. In August 2013, the U.S. District Court for the District of Columbia dismissed the Contractor's suit, ruling that proper venue is the U.S. District Court for the Southern District of Georgia. In September 2013, the Contractor appealed the decision to the U.S. Court of Appeals for the District of Columbia.
The portion of the additional costs claimed by the Contractor in its initial complaint that would be attributable to us, based on our ownership interest, was approximately $280 million in 2008 dollars with respect to these issues. The Contractor has also asserted that it is entitled to further schedule extensions. On May 22, 2014, the Contractor filed an amended counterclaim to the lawsuit pending in the Southern District of Georgia alleging that (i) the design changes to the DCD imposed by the Nuclear Regulatory Commission have delayed module production and the impacts to the Contractor are recoverable by the Contractor under the agreement and (ii) the changes to the basemat rebar design required by the Nuclear Regulatory Commission caused additional costs and delays recoverable by the Contractor under the agreement. The Contractor did not specify in its amended counterclaim claimed amounts relating to these new allegations but such claimed amounts could be substantial. Georgia Power, on behalf of the Co-owners, has not agreed with either the proposed cost or schedule adjustments or that the Co-owners have any responsibility for costs related to these issues.
While litigation has commencedis ongoing and Georgia Power and the Co-owners intend to vigorously defend their positions, Georgia Power and the Co-owners also expect negotiations with the Contractor to continue with respect to cost and schedule during which time the parties will attempt to reach a mutually acceptable compromise of their positions.
If any or all of these costs are ultimately imposed on the Co-owners, we will capitalize the costs attributable to us. As of March 31,June 30, 2014, no material amounts have been recorded related to this claim. Additional claims by the Contractor or Georgia Power, on behalf of the Co-owners, are also likely to arise throughout construction.
b. Patronage Capital Litigation
On March 13, 2014, a lawsuit was filed in the Superior Court of DeKalb County, Georgia, against us, Georgia Transmission and three of our member distribution cooperatives. Plaintiffs filed an amended complaint on July 28, 2014. The lawsuitamended complaint challenges the patronage capital distribution practices of Georgia's electric cooperatives and seeks to certify a defendant class of all but one of our 38 members. It was filed by four former consumer-members of four of our members on behalf of themselves and a proposed class of all former consumer-members of our members. Plaintiffs claim that approximately 30% of all the defendants' total allocated patronage capital belongs to former consumer-members. The lawsuitPlaintiffs also allegesallege that patronage capital owed to former consumer-members includes patronage capital allocated by us to our members but not yet distributed to our members. Plaintiffs claim that the patronage capital of former consumer-members held by defendants and the proposed defendant class should be retired immediately when the consumer-members end their membership by terminating service, or alternatively, according to a regular 13-year revolving plan that retires 7.7%schedule of total patronage capital owed to former consumer-members annuallyno longer than 13 years from the date of its allocation and seek relief to effect such retirements within the stated 13 year period.retirements. Plaintiffs further seek to require the defendants to adjust rates in order to establish and maintain reasonable reserves to fund patronage capital retirements on this basis. Plaintiffs also claim that wedefendants and Georgia Transmissionthe proposed defendant class should be required to implementadopt policies to periodically retire the patronage capital of all consumer-members on a rate structure that would allow us and Georgia Transmissionrevolving schedule of no longer than 13 years from the date of its allocation. Our first mortgage indenture restricts our ability to begin retiring 7.7%distribute patronage capital. See "Item 1—BUSINESS—OGLETHORPE POWER CORPORATION—First Mortgage Indenture" in our 2013 Form 10-K. Although not expected, if we were ordered by the Court to make distributions of our allocated patronage capital, annually.our first mortgage indenture would require us to raise our rates to a level sufficient so that we could comply with the current patronage capital restrictions, and the rate increases required to meet the Plaintiffs' demands would be significant for a period of years. We intend to defend vigorously against all claims in this litigation.
c. Environmental Matters
As is typical for electric utilities, we are subject to various federal, state and local environmental laws which represent significant future risks and uncertainties. Air emissions, water discharges and water usage are extensively controlled, closely monitored and periodically reported. Handling and disposal requirements govern the manner of transportation, storage and disposal of various types
of waste. We are also subject to climate change regulations that impose restrictions on emissions of greenhouse gases, including carbon dioxide, for certain new and modified facilities.
In general, these and other types of environmental requirements are becoming increasingly stringent. Such requirements may substantially increase the cost of electric service, by requiring modifications in the design or operation of existing facilities or the purchase of emission allowances. Failure to comply with these requirements could result in civil and criminal penalties and could include the complete shutdown of individual generating units not in compliance. Certain of our debt instruments require us to comply in all material respects with laws, rules, regulations
and orders imposed by applicable governmental authorities, which include current and future environmental laws or regulations. Should we fail to be in compliance with these requirements, it would constitute a default under those debt instruments. We believe that we are in compliance with those environmental regulations currently applicable to our business and operations. Although it is our intent to comply with current and future regulations, we cannot provide assurance that we will always be in compliance.
At this time, the ultimate impact of any new and more stringent environmental regulations described above is uncertain and could have an effect on our financial condition, results of operations and cash flows as a result of future additional capital expenditures and increased operations and maintenance costs.
Additionally, litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has increased generally throughout the United States. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief, personal injury and property damage allegedly caused by coal combustion residue, greenhouse gas and other emissions have become more frequent.
The following regulatory assets and liabilities are reflected on the unaudited condensed balance sheet as of March 31,June 30, 2014 and December 31, 2013.
2014 | 2013 | 2014 | 2013 | |||||||||||
(dollars in thousands) | (dollars in thousands) | |||||||||||||
Regulatory Assets: | ||||||||||||||
Premium and loss on reacquired debt(a) | $ | 79,804 | $ | 82,499 | $ | 77,110 | $ | 82,499 | ||||||
Amortization on capital leases(b) | 14,756 | 16,124 | 13,347 | 16,124 | ||||||||||
Outage costs(c) | 50,814 | 35,155 | 45,527 | 35,155 | ||||||||||
Interest rate swap termination fees(d) | 12,338 | 13,336 | 11,341 | 13,336 | ||||||||||
Depreciation expense(f) | 48,006 | 48,362 | 47,650 | 48,362 | ||||||||||
Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(g) | 28,675 | 27,678 | 29,894 | 27,678 | ||||||||||
Interest rate options cost(h) | 71,185 | 38,984 | 84,224 | 38,984 | ||||||||||
Deferral of effects on net margin—Smith Energy Facility(i) | 75,168 | 63,491 | 87,335 | 63,491 | ||||||||||
Other regulatory assets(j) | 5,023 | 5,479 | 4,568 | 5,479 | ||||||||||
| ||||||||||||||
Total Regulatory Assets | $ | 385,769 | $ | 331,108 | $ | 400,996 | $ | 331,108 | ||||||
Regulatory Liabilities: | ||||||||||||||
Accumulated retirement costs for other obligations(e) | $ | 23,195 | $ | 24,520 | $ | 22,325 | $ | 24,520 | ||||||
Deferral of effects on net margin—Hawk Road Energy Facility(i) | 25,289 | 23,379 | 26,970 | 23,379 | ||||||||||
Major maintenance reserve(k) | 25,900 | 28,064 | 25,748 | 28,064 | ||||||||||
Deferred debt service adder(l) | 59,617 | 57,223 | 61,995 | 57,223 | ||||||||||
Asset retirement obligations(e) | 19,456 | 19,508 | 32,556 | 19,508 | ||||||||||
Other regulatory liabilities(j) | 6,980 | 6,095 | 6,219 | 6,095 | ||||||||||
| ||||||||||||||
Total Regulatory Liabilities | $ | 160,437 | $ | 158,789 | $ | 175,813 | $ | 158,789 | ||||||
| ||||||||||||||
Net Regulatory Assets | $ | 225,332 | $ | 172,319 | $ | 225,183 | $ | 172,319 | ||||||
| | |||||||||||||
Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005 (the "Title XVII Loan Guarantee Program"), we and the U.S. Department of Energy, acting by and through the Secretary of Energy entered into a Loan Guarantee Agreement on February 20, 2014 (the "Loan Guarantee Agreement") pursuant to which the Department of Energy agreed to guarantee our obligations (the "Department of Energy Guarantee") under the Note Purchase Agreement dated as of February 20, 2014 (the "Note Purchase Agreement"), among us, the Federal Financing Bank and the Department of Energy and the Future Advance Promissory Note No. 1 and the Future Advance Promissory Note No. 2, each dated February 20, 2014, made by us to Federal Financing Bank (the "Federal Financing Bank Notes" and together with the Note Purchase Agreement, the "FFB Credit Facility Documents"). The Federal Financing Bank Credit Facility Documents provide for a multi-advance term loan facility (the "Facility"), under which we may make term loan borrowings through Federal Financing Bank.
Proceeds of advances made under the Facility will be used to reimburse us for a portion of certain costs of construction relating to Vogtle Units No. 3 and No. 4 that are eligible for financing under the Title XVII Loan Guarantee Program ("Eligible Project Costs"). Aggregate borrowings under the Facility may not exceed the lesser of (i) 70% of Eligible Project Costs or (ii) $3,057,069,461, $335,471,604 of which is designated for capitalized interest.
Under the Loan Guarantee Agreement, we are obligated to reimburse the Department of Energy in the event the Department of Energy is required to make any payments to Federal Financing Bank under the Department of Energy Guarantee. Our payment obligations to Federal Financing Bank under the Federal Financing Bank Notes and reimbursement obligations to the Department of Energy under the related reimbursement notes are secured equally and ratably with all of our other notes and obligations issued under our first mortgage indenture by a lien on substantially all of our owned tangible and certain of our intangible assets, including property we acquire in the future.
Advances. Advances may be requested under the Facility on a quarterly basis through December 31, 2020. On February 20, 2014, we made an initial borrowing in the principal amount of $725,000,000 at a fixed interest rate of 3.867% through February 20, 2044. In connection with the receipt of these funds, we repaid a like amount of outstanding short-term obligations, which included a $260,000,000 term loan originally due April 1, 2014 and $465,000,000 of commercial paper. These outstanding obligations were classified as long-term at December 31, 2013.
Future advances are subject to satisfaction of customary conditions, as well as certification of compliance with the requirements of the Title XVII Loan Guarantee Program, accuracy of project-related representations and warranties, delivery of updated project-related information, certification regarding Georgia Power's compliance with certain obligations relating to the Cargo Preference Act, as amended, evidence of compliance with the prevailing wage requirements of the Davis-Bacon Act, as amended, and certification from Department of Energy's consulting engineer that proceeds of the advance are used to reimburse Eligible Project Costs.
Maturity, Interest Rate and Amortization. The final maturity date for each advance under the Facility is February 20, 2044. Interest is payable quarterly in arrears on February 20, May 20, August 20 and November 20 of each year. Principal and interest payments will begin on February 20, 2020. Interest accrued and payable prior to Februarythrough November 20, 2020,2019, up to a maximum of $335,471,604, is reflected as additional borrowings under the Facility. As of June 30, 2014, $10,015,000 of interest is reflected as long-term debt on our condensed balance sheet.
Under Future Advance Promissory Note No. 1, we may select an interest rate period applicable to each advance, with such interest rate periods ranging from three months to the final maturity date. All advances under Future Advance Promissory Note No. 2 will bear a fixed rate of interest through the final maturity date. Under both Federal Financing Bank Notes, the interest rates during the applicable interest rate periods will equal the current average yield on U.S. Treasuries of comparable maturity at the beginning of the interest rate period, plus a spread equal to 0.375%.
In connection with our entry into the Loan Guarantee Agreement and the Federal Financing Bank Credit Facility Documents, we incurred issuance costs of approximately $51,000,000, which will be amortized over the life of the borrowings under the Facility. Issuance costs include fees paid to the Department of Energy, legal and consulting expenses and costs for compliance with certain federal requirements (including compliance with the Davis-Bacon Act).
For the threesix month period ended March 31,June 30, 2014, we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling $9,608,000$20,282,000 for general and environmental improvements at existing plants.
In AprilOn July 30, 2014, we received an additional $10,674,000$7,432,000 in advances on Rural Utilities Service-guaranteed Federal Financing Bank loans for general and environmental improvements at existing plants as well.plants.
On June 12, 2014, we issued $250,000,000 of 4.55% first mortgage bonds, Series 2014A primarily for the purpose of repaying outstanding commercial paper issued for the interim financing of general and environmental capital expenditures at our existing generation facilities and for general corporate purposes. The bonds are secured under our first mortgage indenture.
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
General
We are a Georgia electric membership corporation (an EMC) incorporated in 1974 and headquartered in metropolitan Atlanta. We are owned by our 38 retail electric distribution cooperative members. Our members are consumer-owned distribution cooperatives providing retail electric service in Georgia on a not-for-profit basis. Our principal business is providing wholesale electric power to our members through a combination of our generation assets and, to a lesser extent, power purchased from power marketers and other suppliers. As with cooperatives generally, we operate on a not-for-profit basis.
Results of Operations
For the Three and Six Months Ended March 31,June 30, 2014 and 2013
Net Margin
Our net margin for the three-month periodand six-month periods ended March 31,June 30, 2014 was $19.2$17.2 million and $36.4 million compared to $22.0$24.5 million and $46.5 million for the same periodperiods of 2013. Through March 31,June 30, 2014, we collected approximately 41%78% of our targeted net margin of $47.1$46.8 million for the year ending December 31, 2014. This is typical as our capacity revenues are recorded evenly throughout the year and our management generally budgets conservatively. We anticipate our board of directors will approve a budget adjustment by the end of the year so that net margins will achieve, but not exceed, the targeted margins for interest ratio. For additional information regarding our net margins requirements and policy, see "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Summary of Cooperative Operations—Margins" of our 2013 Form 10-K.
Operating Revenues
Our operating revenues fluctuate from period to period based on several factors, including fuel costs, weather and other seasonal factors, load requirements in our members' service territories, operating costs, availability of electric generation resources, our decisions of whether to dispatch our owned, purchased or member-owned resources over which we have dispatch rights, and our members' decisions of whether to purchase a portion of their hourly energy requirements from our resources or from other suppliers.
Sales to Members. Total revenues from sales to members increased 16.8%10.4% and 13.5% in the three-month periodand six-month periods ended March 31,June 30, 2014 compared to the same periodperiods of 2013. Megawatt-hour sales to members increased 18.1%9.3% and 13.4% for the three-month periodand six-month periods ended March 31,June 30, 2014 compared to the same periodperiods of 2013. The average total revenue per megawatt-hour from sales to members decreased 1.1%increased 1.0% and 0.1% for the three-month periodand six-month periods ended March 31,June 30, 2014 compared to the same periodperiods of 2013. The increases in revenues from sales to members and in megawatt-hour sales to members in the second quarter of 2014 versus the same quarter of 2013 were driven primarilypartly by theincreased generation at Plant Scherer due to increased member demand and partly due to increased generation at Plant Wansley Unit No. 2 due to extensive testing of Mercury Air Toxic Standards environmental controls that were installed in early 2014. Increased member demand due to extreme cold weather that occurred during the first quarter of 2014.2014 also contributed to the increase in sales to members for the six month period ended June 30, 2014 versus the same period of 2013.
The components of member revenues for the three-month and six-month periods ended March 31,June 30, 2014 and 2013 were as follows (amounts in thousands except for cents per kilowatt-hour):
Three Months Ended March 31, | Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||
2014 | 2013 | 2014 | 2013 | 2014 | 2013 | |||||||||||||||
Capacity revenues | $ | 191,676 | $ | 181,114 | $ | 190,077 | $ | 184,261 | $ | 381,752 | $ | 365,375 | ||||||||
Energy revenues | 143,083 | 105,539 | 148,039 | 121,930 | 291,123 | 227,469 | ||||||||||||||
| ||||||||||||||||||||
Total | $ | 334,759 | $ | 286,653 | $ | 338,116 | $ | 306,191 | $ | 672,875 | $ | 592,844 | ||||||||
| | |||||||||||||||||||
Kilowatt-hours sold to members | 4,905,224 | 4,153,662 | 5,174,273 | 4,732,825 | 10,079,497 | 8,886,487 | ||||||||||||||
Cents per kilowatt-hour | 6.83¢ | 6.90¢ | 6.53¢ | 6.47¢ | 6.68¢ | 6.67¢ | ||||||||||||||
Capacity revenues from members increased 5.8%3.2% and 4.5% for the three-month periodand six-month periods ended March 31,June 30, 2014 compared to the same periodperiods of 2013. Capacity revenues are the revenues we receive for electric service whether or not our generation and purchased power resources are dispatched to produce electricity and are designed to cover the fixed costs associated with our business, including fixed production expenses, depreciation and amortization expenses and interest charges, plus a targeted margin. Each member is required to pay us for capacity furnished under its wholesale power contract according to the individual fixed percentage capacity cost responsibility for each resource in which it participates. Our capacity revenues are based on the costs we expect to incur on an annual basis and are subject to adjustment by our board such that our net margins will achieve, but not exceed, the targeted margins for interest ratio.
Energy revenues were 35.6%21.4% and 28.0% higher for the three-month periodand six-month periods ended March 31,June 30, 2014 compared to the same periodperiods of 2013. Our average energy revenue per megawatt-hour from sales to members increased 14.8%11.1% and 12.8% for the three-month periodand six-month periods ended March 31,June 30, 2014 as compared to the same periodperiods of 2013. ThisThe increase resultedin energy revenues for the comparable three-month periods was primarily fromdue to an increase in higher cost coal-fired generation and higher natural gas prices. In addition to the foregoing, the increase for the comparable six-month periods was due to increased generation during the first quarter of 2014 as a result of extreme cold weather. For a discussion of total fuel costs and total generation, see "—Operating Expenses."
Sales to Non-Members. Sales to non-members for the three-month periodand six-month periods ended March 31,June 30, 2014 were 68.9% higherdecreased 1.6% and increased 34.7% as compared to the same periods of 2013. This increase for year-to-date 2014 as compared to the same period of 2013. This increase2013 was primarily due to sales of natural gas of $10.8 million.million during the first quarter of 2014.
Operating Expenses
Operating expenses for the three-month periodand six-month periods ended March 31,June 30, 2014 increased 24.8%12.5% and 18.4% as compared to the same periodperiods of 2013. This increase was due to higher fuel costs, production costs and depreciation and amortization expenses and purchased power costs as compared to the same periodperiods of 2013.
The following table summarizes our megawatt-hour generation and fuel costs by generating source.
Three Months Ended March 31, | Three Months Ended June 30, | |||||||||||||||||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||||||||||||||||||||||||
Fuel Source | Cost | Generation | Cost per MWh | Cost | Generation | Cost per MWh | Cost | Generation | Cost per MWh | Cost | Generation | Cost per MWh | ||||||||||||||||||||||||||
(thousands) | (MWh) | (thousands) | (MWh) | (thousands) | (MWh) | (thousands) | (MWh) | |||||||||||||||||||||||||||||||
Coal | $ | 56,486 | 1,896,226 | $ | 29.79 | $ | 40,646 | 1,483,954 | $ | 27.39 | $ | 63,661 | 2,017,328 | $ | 31.56 | $ | 45,167 | 1,490,279 | $ | 30.31 | ||||||||||||||||||
Nuclear | 20,765 | 2,225,966 | 9.33 | 18,332 | 2,085,092 | 8.79 | 22,000 | 2,577,243 | 8.54 | 22,598 | 2,574,270 | 8.78 | ||||||||||||||||||||||||||
Gas: | ||||||||||||||||||||||||||||||||||||||
Combined Cycle | 51,201 | 1,138,084 | 44.99 | 40,138 | 1,276,553 | 31.44 | 41,382 | 1,026,369 | 40.32 | 41,532 | 1,142,648 | 36.35 | ||||||||||||||||||||||||||
Combustion Turbine | 3,824 | 21,425 | 178.48 | 1,034 | 16,764 | 61.68 | 6,933 | 96,138 | 72.12 | 3,768 | 47,568 | 79.21 | ||||||||||||||||||||||||||
| ||||||||||||||||||||||||||||||||||||||
$ | 132,276 | 5,281,701 | $ | 25.04 | $ | 100,150 | 4,862,363 | $ | 20.60 | $ | 133,976 | 5,717,078 | $ | 23.43 | $ | 113,065 | 5,254,765 | $ | 21.52 | |||||||||||||||||||
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Six Months Ended June 30, | |||||||||||||||||||
2014 | 2013 | ||||||||||||||||||
Fuel Source | Cost | Generation | Cost per MWh | Cost | Generation | Cost per MWh | |||||||||||||
(thousands) | (Mwh) | (thousands) | (Mwh) | ||||||||||||||||
Coal | $ | 120,148 | 3,913,554 | $ | 30.70 | $ | 85,812 | 2,974,233 | $ | 28.85 | |||||||||
Nuclear | 42,766 | 4,803,209 | 8.90 | 40,930 | 4,659,362 | 8.78 | |||||||||||||
Gas: | |||||||||||||||||||
Combined Cycle | 92,582 | 2,164,453 | 42.77 | 81,670 | 2,419,201 | 33.76 | |||||||||||||
Combustion Turbine | 10,756 | 118,766 | 90.56 | 4,803 | 64,332 | 74.66 | |||||||||||||
| | | | | | | | | | | | | | | | | | | |
$ | 266,252 | 10,999,982 | $ | 24.20 | $ | 213,215 | 10,117,128 | $ | 21.07 | ||||||||||
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| | | | | | | | | | | | | | | | | | | |
For the three-month periodand six-month periods ended March 31,June 30, 2014, total fuel costs increased 32.1%18.5% and 24.9% and megawatt-hour generation increased 8.6%8.8% and 8.7%, respectively, compared to the same periodperiods of 2013. The extreme cold weather in 2014 as compared to 2013 contributed to the increase in megawatt-hours of generation. Average fuel costs per megawatt-hour increased 21.6%8.9% and 14.9% in the three-month periodand six-month periods ended March 31,June 30, 2014 compared to the same periodperiods of 2013. The increase in total fuel costs was partly due to higher generation from our coal-fired plants and nuclear plants and partly due to higher natural gas prices for fuel to run our natural gas-fired facilities.prices. As discussed above, extensive testing of environmental equipment at Plant Wansley which is fueled by higher cost eastern coal, generated 132,000 megawatts hours inUnit No. 2 during the firstsecond quarter of 2014 whereasincreased generation in 2014 by 421,000 megawatt-hours for the six-month period ended June 30, 2014 as compared to the same period of 2013 when it was in reserve shutdown for most of the six month period primarily due to more economical generation from natural gas-fired facilities. Generation from Plant Scherer also increased 18.5%18.2% during the three-monthsix-month period ended March 31,June 30, 2014 as compared to the same period of 2013 due to increased demand from our members. Generation from the nuclear facilities increased 6.8% primarily due to normal fluctuations between fiscal periods related to the timing of scheduled outages as well as an unscheduled outage at Hatch Unit No. 1 in 2013. Generation from our gas-fired facilities decreased in the three-month periodand six-month periods ended March 31,June 30, 2014 versus the same periodperiods of 2013 due primarily to lower utilization of the Smith Energy Facility, although the remainder of our gas-fired facilities experienced a slight increase in generation. The decrease in generation from gas-fired facilitiesFacility; however, this was more than offset by increased natural gas prices in 2014. The extreme cold weather in the first quarter of 2014 thus fuel costs for gas-fired facilities accounted for 43.1%as compared to the first quarter of 2013 also contributed to the overall increase in total fuel costs.megawatt-hours of generation for the six month period ended June 30, 2014 compared to the same period of 2013.
Production costs increased 14.1%10.9% and 12.5% for the three-month and six-month periods ended June 30, 2014 as compared to the same periods of 2013. The increase in the second quarter of 2014 versus the same period of 2013 resulted primarily from higher operations and maintenance expenses at our co-owned facilities, primarily Plants Vogtle and Hatch. The increase for the six-month period ended March 31,
June 30, 2014 as compared to the same period of 2013. The increase2013 resulted partly from the cost of gas sold to non-members of $6 million as discussed above and partly from higher operations and maintenance costs at our co-owned facilities, (primarily Plant Vogtle)primarily Plants Vogtle and from higher costs at the Talbot Energy Facility due to planned outage work in 2014.Hatch.
Depreciation and amortization costs increased 9.8%7.3% and 8.5% for the three-month periodand six-month periods ended March 31,June 30, 2014 as compared to the same periodperiods of 2013. The increase in depreciation expense in the first quarter of 2014 as compared to the first quarter of 2013 was primarily due to $291 million of environmental capital improvements at Plant Scherer that were primarily placed into service in May and August of 2013.
Interest charges
Interest expense increased 8.1%12.7% and 10.4% for the three-month periodand six-month periods ended March 31,June 30, 2014 as compared to the same periodperiods of 2013 primarily due to increased debt to finance construction of Vogtle Units No. 3 and No. 4.
Allowance for debt funds used during construction decreased 4.5% in the three-month period ended March 31, 2014 compared to the same period of 2013 primarily due to environmental capital improvements at Scherer being placed into service as discussed above. The decrease was offset somewhat by an increase in construction work in progress for Vogtle No. 3 and No. 4.
Financial Condition
Balance Sheet Analysis as of March 31,June 30, 2014
Assets
Cash used for property additions for the three-monthsix-month period ended March 31,June 30, 2014 totaled $134.4$249.3 million. Of this amount, approximately $74$172 million was associated with construction expenditures for Vogtle Units No. 3 and No. 4, $33$21 million for normal additionsenvironmental control systems being installed primarily at Plant Scherer and replacements to existing generation facilities and $19$35 million for nuclear fuel purchases. The remaining expenditures were for environmental control systems being installed primarily at Plant Scherer.normal additions and replacements to existing generation facilities.
The $289.5$293.8 million of restricted short-term investments at March 31,June 30, 2014 represent funds deposited into a Rural Utilities Service Cushion of Credit Account with the U.S. Treasury andthat earns interest at a guaranteed rate of 5% per annum. The funds, including interest earned thereon, can only be applied to debt service on Rural Utilities Service and Rural Utilities Service-guaranteed Federal Financing Bank notes. Decisions regarding when to apply the funds are guided by the interest rate environment and our anticipated liquidity needs.
Deferred debt expense, being amortized increased $40.7$42.6 million for the threesix months ending March 31,ended June 30, 2014 due to debt related costs associated with a $3.057 billion loan with the Department of Energy, which closed in February 2014, to finance a portion of the costs associated with the Vogtle Units No. 3 and No. 4 construction project.2014. For additional information regarding this loan, see Note K.L.
Regulatory assets increased $69.9 million for the six months ending June 30, 2014. The increase was primarily due to a $45.2 million increase in the deferral of unrealized losses on, and expirations of, our interest rate options. For information regarding our interest rate options, see Note C. In addition, there was a $24.9 million increase in deferred losses related to Smith Energy Facility. The effects on net margin for Smith are being deferred until the end of 2015 at which time the amounts will be amortized over the remaining life of the facility.
Equity and Liabilities
Accounts payable decreased $28.7$24.8 million for the three-monthsix-month period ended March 31, 2014. The December 31, 2013 payable balance includedJune 30, 2014 as a result of a $38.4 million in credits dueapplied to the membersmembers' bills in the first quarter of 2014 for a board approved reduction to 2013 revenue requirements as a result of margins collected in excess of our 2013 target. These credits were applied to the members' bills in the first quarter of 2014. Offsetting the decrease was an $11.3a $12.7 million increase in the payable to Georgia Power for operation and maintenance costs for our co-owned facilities and capital costs associated with Vogtle Units No. 3 and No. 4 construction.natural gas purchases.
Member power bill prepayments represent funds received from the members for the prepayment of their monthly power bills. At March 31,June 30, 2014, $92.5$93.0 million of member power bill prepayments was classified as a current liability and $34.4$36.2 million was classified as a long-term liability. During the three-monthsix-month period ended March 31,June 30, 2014, $20.1$27.1 million of prepayments were received from the members
and $7.9$12.6 million was applied to the members' monthly power bills. For information regarding the power bill prepayment program, see Note J.K.
Capital Requirements and Liquidity and Sources of Capital
Vogtle Units No. 3 and No. 4.
We, along with Georgia Power, the Municipal Electric Authority of Georgia and the City of Dalton are participating in the construction of two Westinghouse AP1000 nuclear generating units at Plant Vogtle, each with a nominally rated generating capacity of approximately 1,100 megawatts. Our ownership interest is 30%, representing 660 megawatts of total capacity. As of March 31,June 30, 2014, our total investment in Vogtle Units No. 3 and No. 4 was $2.1$2.2 billion.
For additional information about the Vogtle construction project, see "Item 1—BUSINESS—OUR POWER SUPPLY RESOURCES—Future Power Resources—Plant Vogtle Units No. 3 and No. 4" and "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Capital Requirements—Capital Expenditures" in our 2013 Form 10-K. Also see Note F of Notes to Unaudited Condensed Financial Statements herein.G and Note L.
Environmental Regulations
The U.S. Environmental Protection Agency, or EPA, continues to develop a number of rules that significantly expand the scope of regulation of air emissions, water and waste management at power plants.
Two recent court decisions each upheld one of EPA's final rules that affect us. On April 15, 2014, the U.S. Court of Appeals for the District of Columbia Circuit upheld the EPA's final Mercury and Air Toxics Standards (MATS) rule, which establishes maximum achievable control technology limits for certain hazardous air pollutants at coal and oil-fired electric generating units. For coal units, the rule sets stringent emission limits to control various hazardous air pollutants such as mercury, non-mercury metals and acid gases and work practice standards to control organics and dioxins. Affected generating units, which include our co-owned units at Plants Wansley and Scherer, have until April 16, 2015 to comply with the rule, although controls Following are currently installed at both of those plants which are expected to meet the new requirements. Whether the Court's decision will be appealed is not known at this time and we cannot predict the outcome of any future litigation.
On April 29, 2014, the U. S. Supreme Court upheld the Cross State Air Pollution Rule (CSAPR), reversing a 2012 decisionsome of the U.S. Court of Appeals for the District of Columbia Circuit which had invalidated the CSAPR. The Supreme Court remanded the case back to Court of Appeals for the D.C. Circuit which could remand the case to EPA for further rulemaking to implement the CSAPR which is unlikely before mid-2015. The final ruledevelopments that may affect future operations at our facilities.
On June 18, 2014, EPA proposed new source performance standards for existing sources the "Clean Power Plan," slated to cut carbon dioxide emissions from existing fossil fuel-fired power plants nationwide by an average of 30% from 2005 levels by 2030, with an additional interim goal for the years 2020 through 2029. For Georgia, however, the proposal would require a 44% reduction in emission rates from 2012 levels. Under the proposal, each state would have to reduce carbon dioxide emissions on a state-wide basis pursuant to state goals, determined through the application of certain "building blocks" that include plant efficiency upgrades, shifting generation from coal plants to natural gas facilities, expansions in renewable and nuclear power sources and implementation of demand-side energy efficiency programs. That same day, EPA also proposed new source performance standards for certain modified or reconstructed fossil fuel-fired power plants which, if finalized, could apply to our coal-fired facilities (Plants Scherer and Wansley) and several of our co-owned units at Plants Scherer and Wansley; however, we do not anticipatenatural gas-fired power plants. EPA is scheduled to finalize the need to purchase allowances givenClean Power Plan as well as the completionstandards for modified or reconstructed sources by June 1, 2015. The outcome of additional pollution control equipment earlier this year.
Also, on April 21, 2014, the EPAClean Power Plan and the U.S. Army Corps of Engineers jointly published a proposed rule to revise the regulatory definition of waters of the U.S.standards for all Clean Water Act (CWA) programs, significantly expanding the scope of federal jurisdiction under the CWA. If finalized as proposed, this rule could significantly increase permitting and regulatory requirements and costs associated with the siting of newmodified or modification to existing generation facilities. In addition, the proposed rule could have significant impacts on economic development projects which could impact demand. The ultimate impact of the rule will depend on the specific requirements of the final rule and the outcome ofreconstructed sources rulemakings, including any legalsubsequent challenges, and cannot be determined at this time.time, but they could result in material compliance costs, including increased operating costs or decreased operations or both at Plants Scherer and Wansley.
Separately,On June 23, 2014, the dates for finalizing several other rules have recently been delayed. For example, the deadline for finalizationU.S. Supreme Court issued a decision on an appeal of the Coal Combustion Residuals Rule has slipped to December 19, 2014,original greenhouse gas rules EPA began promulgating in 2009. Among other things, those rules imposed new source review requirements on emissions of greenhouse gases, including carbon dioxide, through the Effluent Limitation Guidelines rule finalization deadline has slipped to September 30, 2015Prevention of Significant Deterioration (PSD) Preconstruction Permitting Program and the CoolingTitle V Operating Permit Program. The rules directly regulated new or modified larger sources of greenhouse gases, including fossil-fueled power plants. Concluding that portions of the rules were invalid, the Court ruled that EPA could not impose PSD or Title V permitting requirements on sources solely due to emissions of greenhouse gases, and that instead, EPA could regulate greenhouse gas emissions pursuant to PSD or Title V only when new or modified source emissions trigger PSD or Title V regulation for other regulated pollutants. We cannot predict the ultimate outcome of this litigation as the decision may undergo further appeal, and EPA may need to conduct further rulemaking in response to the Court's decision.
On February 12, 2013, EPA proposed a rule that would require many states, including Georgia, to revise those portions of their State Implementation Plans (SIPs) that relate to the regulation of excess emissions at industrial facilities, including fossil fuel-fired electric generating units, during periods of startup, shut-down or malfunction (SSM). EPA's proposed determination, if finalized, would require revisions to all affected SIPs within 18 months. Recently, in litigation over this rulemaking, EPA delayed final action on the proposal until May 22, 2015. If finalized as proposed, these new rules could result in additional compliance and operational costs at our power plants.
Section 316(b) of the Clean Water Intake orAct requires that the location, design, construction and capacity of cooling water intake structures reflect the best technology available for minimizing adverse environmental impacts on fish and other aquatic life. EPA issued its final section 316(b) rule finalization deadline has slipped torequirements for existing power plants and manufacturing facilities on May 16,19, 2014. The impactsfinal rule applies to all existing facilities that withdraw at least two million gallons of water per day and that use at least 25% of such water exclusively for cooling purposes. We are in the process now of determining what modifications, if any, need to be made to our four co-owned power plants that meet the cooling water use threshold (Plants Scherer, Wansley, Vogtle and Hatch) to meet the new standards. Capital requirements for any additional controls that might be needed for compliance at any of these rulemakingsplants cannot be determined at this time, and will depend onthe result of any litigation challenging the final regulations and any ensuing litigation.rules cannot be predicted.
For further discussion regarding potential effects on our business from environmental regulations, including potential capital requirements, see "Item 2—Management's Discussion and Analysis of Financial Condition and Results of Operations—Financial Condition—Capital Requirements and Liquidity and Sources of Capital—Environmental Regulations" in our quarterly report on Form 10-Q for the quarterly period ending March 31, 2014 and "Item 1—BUSINESS—REGULATION—Environmental," "Item 1A—RISK FACTORS" and "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Capital Requirements—Capital Expenditures" in our 2013 Form 10-K.
Liquidity
At March 31,June 30, 2014, we had $1.6$1.8 billion of unrestricted available liquidity to meet our short-term cash needs and liquidity requirements. This amount included $218$330 million in cash and cash equivalents and $1.4$1.5 billion of unused and available committed credit arrangements.
At March 31,June 30, 2014, we had in excess of $1.9 billion of committed credit arrangements in place and $1.4$1.5 billion available under these facilities. These six separate facilities are reflected in the table below:
Committed Credit Facilities | Committed Credit Facilities | Committed Credit Facilities | ||||||||||||||
Authorized | Available | Expiration Date | Authorized | Available | Expiration Date | |||||||||||
(dollars in millions) | (dollars in millions) | |||||||||||||||
Unsecured Facilities: | ||||||||||||||||
Syndicated Line of Credit led by Bank of America | $ | 1,265 | $ | 860 | (1) | June 2015 | $ | 1,265 | $ | 934 | (1) | June 2015 | ||||
Syndicated Line of Credit led by CoBank | 150 | 150 | September 2014 | 150 | 150 | September 2014 | ||||||||||
CFC Line of Credit | 110 | 110 | September 2016 | 110 | 110 | September 2016 | ||||||||||
CFC Line of Credit | 210 | 210 | December 2018 | 210 | 210 | December 2018 | ||||||||||
JPMorgan Chase Line of Credit | 150 | 34 | (3) | December 2018 | 150 | 34 | (4) | December 2018 | ||||||||
Secured Facilities: |
|
| ||||||||||||||
CFC Term Loan | 250 | 250 | December 2018 | 250 | 250 | December 2018 |
As of March 31,June 30, 2014, we were using our commercial paper program to provide interim funding for 1) the monthly payments related to the construction of Vogtle Units No. 3 and No. 4 prior to receiving advances of permanent funding under the Department of Energy-guaranteed Federal Financing Bank loan, which can be requested no more frequently than quarterly and for2) the upfront premium payments made in connection with our interest rate hedging program. Between our credit arrangements and projected cash on hand, we believe we have sufficient liquidity to cover our normal operations and to provide for the interim financings described above.
Under our commercial paper program, we are authorized to issue commercial paper in amounts that do not exceed the amount of any committed backup lines of credit, thereby providing 100% dedicated support for any commercial paper outstanding.
Under our unsecured committed lines of credit, we have the ability to issue letters of credit totaling $1.045 billion in the aggregate, of which $794 million remained available at March 31,June 30, 2014. However, amounts related to issued letters of credit reduce the amount that would otherwise be available to draw for working capital needs. Also, due to the requirement to have 100% dedicated backup for any commercial paper outstanding, any amounts drawn under our committed credit facilities for working capital or related to issued letters of credit will reduce the amount of commercial paper that we can issue. The majority of our outstanding letters of credit are for the purpose of providing credit enhancement on variable rate demand bonds.
Between our credit arrangements and projected cash on hand, we believe we have sufficient liquidity to cover our normal operations and to provide interim financing for construction of Vogtle Units No. 3 and No. 4.
Several of our credit facilities contain a financial covenant that requires us to maintain minimum levels of patronage capital. At March 31,June 30, 2014, the required minimum level was $675 million and our actual patronage capital was $734$751 million. Additional covenants contained in several of our credit facilities limit the amount ofour secured indebtedness and unsecured indebtedness, we can have outstanding. At
March 31, 2014,both as defined in the most restrictive of these covenants limits our secured indebtednesscredit agreements, to $12.0 billion and our unsecured indebtedness to $4.0 billion.billion, respectively. At March 31,June 30, 2014, we had $7.1$7.3 billion of secured indebtedness and $269.7$196 million of unsecured indebtedness outstanding, which was well within the covenant thresholds.
At March 31,June 30, 2014, our current assets included $289.5$293.9 million of restricted short-term investments pursuant to deposits made into a Rural Utilities Service Cushion of Credit Account. See "—Balance Sheet Analysis as of March 31,June 30, 2014—Assets" for more information regarding this account.
Financing Activities
First Mortgage Indenture. At March 31,June 30, 2014, we had $6.9$7.2 billion of long-term debt outstanding under our first mortgage indenture secured equally and ratably by a lien on substantially all of our owned tangible and certain of our intangible property, including property we acquire in the future. See "Item 1—BUSINESS—OGLETHORPE POWER CORPORATION—First Mortgage Indenture" in our 2013 Form 10-K for further discussion of our first mortgage indenture.
Rural Utilities Service-Guaranteed Loans. We currently have four approved Rural Utilities Service-guaranteed loans, totaling $871 million, which are being funded through the Federal Financing Bank and are in various stages of being drawn down, with $448$441 million remaining to be advanced. When advanced, the debt will be secured under our first mortgage indenture.
Department of Energy-Guaranteed Loan. OnIn February 20, 2014, we closed on a loan with the Department of Energy that will fund up to the lesser of $3.057 billion or 70% of eligible project costs related to the
cost to construct our 30% undivided share of Vogtle Units No. 3 and No. 4. TheThis loan is being funded by the Federal Financing Bank and is backed by a federal loan guarantee provided by the Department of Energy. At March 31,
As of June 30, 2014, $2.3our total investment in Vogtle Units No. 3 and No. 4 was $2.2 billion and we have incurred $2.1 billion of debt to provide long-term financing for this investment. This long-term debt includes $1.4 billion of taxable first mortgage bonds we previously issued and $735 million, including capitalized interest, under the Department of Energy loan remainsfacility. The facility may be used until no later than December 2020 to be advanced. Allprovide long-term funding for up to 70% of eligible project costs after they are incurred. As of June 30, 2014, we have the capacity to fund an additional $730 million under the facility based on the amount of eligible project costs we have incurred to date. We anticipate making draws under the facility on at least a semi-annual basis to meet our funding requirements as construction progresses. When advanced, the debt under this loan will be secured under our first mortgage indenture. For additional information regarding this loan, see Note L.
Bond Financing.
In MayOn June 12, 2014, we plan to issue up toissued $250 million of taxableSeries 2014A first mortgage bonds to provide long-term financing for general and environmental improvements to certain of our existing facilities.facilities and for general corporate purposes.
For more detailed information regarding our financing plans, see "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Financing Activities" in our 2013 Form 10-K.
Newly Adopted or Issued Accounting Standards
Not Applicable.For a discussion of recently issued or adopted accounting pronouncements, see Note E of Notes to Unaudited Condensed Financial Statements.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
There have not been any material changes to market risks from those reported in "Item 7A—QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK" of our 2013 Form 10-K.
Item 4. Controls and Procedures
As of March 31,June 30, 2014, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended. Based on this evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures are effective.
There have been no changes in internal control over financial reporting or other factors that occurred during the quarter ended March 31,June 30, 2014 that have materially affected, or are reasonably likely to affect, our internal control over financial reporting.
Vogtle Units No. 3 and No. 4
In April 2008, Georgia Power Company, acting for itself and as agent for us, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia (collectively, the Co-owners), and Westinghouse Electric Company LLC and Stone & Webster, Inc. (collectively, the Contractor) entered into an engineering, procurement, and construction agreement to design, engineer, procure, and construct two AP1000 nuclear units with electric generating capacity of approximately 1,100 megawatts each and related facilities, structures, and improvements at Plant Vogtle (Vogtle Units No. 3 and No. 4).
Under the agreement, the Co-Owners and the Contractor have established both informal and formal dispute resolution procedures in order to resolve issues arising during the course of constructing a project of this magnitude. Georgia Power, on behalf of the Co-owners, has successfully initiated both formal and informal claims through these procedures, including ongoing claims. When matters are not resolved through these procedures, the parties may proceed to litigation. The Contractor and the Co-owners are involved in litigation with respect to certain claims that have not been resolved through the formal dispute resolution process.
Current litigation relates to costs associated with design changes to the Westinghouse AP1000 Design Control Document (DCD) and costs associated with delays in the project schedule related to the timing of approval of the DCD and issuance of the combined construction permits and operating licenses by the Nuclear Regulatory Commission. In July 2012, the Co-owners and Contractor began negotiations regarding these costs, including the assertion by the Contractor that the Co-owners are responsible for these costs under the terms of the agreement. On November 1, 2012, the Co-owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia, seeking a declaratory judgment that the Co-owners are not responsible for these costs. Also on November 1, 2012, the Contractor filed suit against the Co-owners in the U.S. District Court for the District of Columbia alleging the Co-owners are responsible for these costs. In August 2013, the U.S. District Court for the District of Columbia dismissed the Contractor's suit, ruling that proper venue is the U.S. District Court for the Southern District of Georgia. In September 2013, the Contractor appealed the decision to the U.S. Court of Appeals for the District of Columbia.
The portion of the additional costs claimed by the Contractor in its initial complaint that would be attributable to us, based on our ownership interest, was approximately $280 million in 2008 dollars with respect to these issues. The Contractor has also asserted that it is entitled to further schedule extensions. On May 22, 2014, the Contractor filed an amended counterclaim to the lawsuit pending in the Southern District of Georgia alleging that (i) the design changes to the DCD imposed by the Nuclear Regulatory Commission have delayed module production and the impacts to the Contractor are recoverable by the Contractor under the agreement and (ii) the changes to the basemat rebar design required by the Nuclear Regulatory Commission caused additional costs and delays recoverable by the Contractor under the agreement. The Contractor did not specify in its amended counterclaim claimed amounts relating to these new allegations but such claimed amounts could be substantial. Georgia Power, on behalf of the Co-owners, has not agreed with either the proposed cost or schedule adjustments or that the Co-owners have any responsibility for costs related to these issues.
While litigation is ongoing and Georgia Power and the Co-owners intend to vigorously defend their positions, Georgia Power and the Co-owners also expect negotiations with the Contractor to continue with respect to cost and schedule during which time the parties will attempt to reach a mutually acceptable compromise of their positions. Management does not anticipate that the liabilities, if any, for these proceedings will have a material effect on our financial condition or results of operations. However, at this time, the ultimate outcome of this litigation cannot be determined. Additional claims
by the Contractor or Georgia Power, on behalf of the Co-owners, are also likely to arise throughout construction.
For further information regarding the two additional units at Plant Vogtle, see "Item 1—BUSINESS—OUR POWER SUPPLY RESOURCES—Future Power Resources—Plant Vogtle Units No. 3 and No. 4" in our 2013 Form 10-K and "Management's Discussion and Analysis of Financial Condition and Results of Operations and Financial Condition—Capital Requirements and Liquidity and Sources of Capital—Vogtle Units No. 3 and No. 4" in our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2014, filed with the SEC on May 12, 2014.
Patronage Capital Litigation
On March 13, 2014, a lawsuit was filed in the Superior Court of DeKalb County, Georgia, against us, Georgia Transmission and three of our member distribution cooperatives. Plaintiffs filed an amended complaint on July 28, 2014. The lawsuitamended complaint challenges the patronage capital distribution practices of Georgia's electric cooperatives and seeks to certify a defendant class of all but one of our 38 members. It was filed by four former consumer-members of four of our members on behalf of themselves and a proposed class of all former consumer-members of our members. Plaintiffs claim that approximately 30% of all the defendants' total allocated patronage capital belongs to former consumer-members. The lawsuitPlaintiffs also allegesallege that patronage capital owed to former consumer-members includes patronage capital allocated by us to our members but not yet distributed to our members. Plaintiffs claim that the patronage capital of former consumer-members held by defendants and the proposed defendant class should be retired immediately when the consumer-members end their membership by terminating service, or alternatively, according to a regular 13-year revolving plan that retires 7.7%schedule of total patronage capital owed to former consumer-members annuallyno longer than 13 years from the date of its allocation and seek relief to effect such retirements within the stated 13 year period.retirements. Plaintiffs further seek to require the defendants to adjust rates in order to establish and maintain reasonable reserves to fund patronage capital retirements on this basis. Plaintiffs also claim that wedefendants and Georgia Transmissionthe proposed defendant class should be required to implementadopt policies to periodically retire the patronage capital of all consumer-members on a rate structure that would allow us and Georgia Transmissionrevolving schedule of no longer than 13 years from the date of its allocation. Our first mortgage indenture restricts our ability to begin retiring 7.7%distribute patronage capital. See "Item 1—BUSINESS—OGLETHORPE POWER CORPORATION—First Mortgage Indenture" in our 2013 Form 10-K. Although not expected, if we were ordered by the Court to make distributions of our allocated patronage capital, annually. our first mortgage indenture would require us to raise our rates to a level sufficient so that we could comply with the current patronage capital restrictions, and the rate increases required to meet the Plaintiffs' demands would be significant for a period of years.
We intend to defend vigorously against all claims in this litigation.
The While the ultimate outcome of this litigation cannot be predicted at this time; however,time, management does not anticipate that the ultimate liabilities, if any, arising from this proceeding would have a material effect on our financial condition or results of operations. See Note F of Notes to Unaudited Condensed Financial Statements for information about other loss contingencies.
ThereExcept as discussed below, there have not been anyno material changes in our risk factors from those reportedthe risks disclosed in "Item 1A—RISK FACTORS" of our 2013 Form 10-K.
We cannot predict the outcome of legal proceedings related to our business activities.
From time to time we are subject to litigation from various parties, the most significant of which are described under the heading "Legal Proceedings" in this quarterly report. Our business, financial condition, and results of operations may be materially affected by adverse results of certain litigation. Unfavorable resolution of legal proceedings in which we are involved or other future legal proceedings could require significant expenditures that could have the effect of increasing the cost of electric service
we provide to our members and, as a result, affect our members' ability to perform their contractual obligations to us.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Not Applicable.
Item 3. Defaults upon Senior Securities
Not Applicable.
Item 4. Mine Safety Disclosures
Not Applicable.
On May 12, 2014, our board of directors appointed Mr. Ernest Adelburt Jakins III to serve as a director for member group 5. Mr. Jakins' appointment fills the vacancy created when Mr. G. Randall Pugh retired as President and Chief Executive Officer of Jackson Electric Membership Corporation and became ineligible to serve on our board of directors in March 2014. Mr. Jakins' present term will extend until our members elect a new member director for group 5 at our annual meeting of members in March 2015.Not Applicable.
For additional information regarding our board of directors and election procedures, see "Item 10—DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE" of our 2013 Form 10-K.
Number | Description | ||
---|---|---|---|
Rule 13a-14(a)/15d-14(a) Certification, by Michael L. Smith (Principal Executive Officer). | |||
31.2 | Rule 13a-14(a)/15d-14(a) Certification, by Elizabeth B. Higgins (Principal Financial Officer). | ||
32.1 | Certification Pursuant to 18 U.S.C. 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Michael L. Smith (Principal Executive Officer). | ||
32.2 | Certification Pursuant to 18 U.S.C. 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Elizabeth B. Higgins (Principal Financial Officer). | ||
101 | XBRL Interactive Data File. |
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Oglethorpe Power Corporation (An Electric Membership Corporation) | ||||
Date: | By: | /s/ Michael L. Smith Michael L. Smith President and Chief Executive Officer | ||
Date: | /s/ Elizabeth B. Higgins Elizabeth B. Higgins Executive Vice President and Chief Financial Officer (Principal Financial Officer) |