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 (Address of principal executive offices) | 30084-5336 (Zip Code) | |
Registrant's telephone number, including area code | (770) 270-7600 |
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o
Indicate by check mark whether the registrant has submitted electronically 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 JUNESEPTEMBER 30, 2012
| | Page No. | ||
---|---|---|---|---|
PART I—FINANCIAL INFORMATION | ||||
Item 1. | Financial Statements | 2 | ||
Unaudited Condensed Balance Sheets as of | 2 | |||
Unaudited Condensed Statements of Revenues and Expenses For the Three and | 4 | |||
Unaudited Condensed Statements of Comprehensive Margin For the Three and | 5 | |||
Unaudited Condensed Statements of Patronage Capital and Membership Fees and Accumulated Other Comprehensive Margin (Deficit) For the | 6 | |||
Unaudited Condensed Statements of Cash Flows For the | 7 | |||
Notes to Unaudited Condensed Financial Statements For the Three and | 8 | |||
Item 2. | Management's Discussion and Analysis of Financial Condition and Results of Operations | 24 | ||
Item 3. | Quantitative and Qualitative Disclosures About Market Risk | |||
Item 4. | Controls and Procedures | 35 | ||
PART II—OTHER INFORMATION | ||||
Item 1. | Legal Proceedings | 36 | ||
Item 1A. | Risk Factors | 36 | ||
Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds | 36 | ||
Item 3. | Defaults Upon Senior Securities | 36 | ||
Item 4. | Mine Safety Disclosures | 36 | ||
Item 5. | Other Information | 36 | ||
Item 6. | Exhibits | 37 | ||
SIGNATURES | 38 |
PART I—FINANCIAL INFORMATION
Item 1. Financial Statements
Oglethorpe Power Corporation
Condensed Balance SheetsJuneSeptember 30, 2012 and December 31, 2011
(dollars in thousands) | (dollars in thousands) | |||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||
(Unaudited) | (Unaudited) | |||||||||||||
Assets | ||||||||||||||
Electric plant: | ||||||||||||||
In service | $ | 7,413,780 | $ | 7,335,866 | $ | 7,426,383 | $ | 7,335,866 | ||||||
Less: Accumulated provision for depreciation | (3,400,211 | ) | (3,328,585 | ) | (3,437,932 | ) | (3,328,585 | ) | ||||||
4,013,569 | 4,007,281 | 3,988,451 | 4,007,281 | |||||||||||
Nuclear fuel, at amortized cost | 295,764 | 284,205 | 295,761 | 284,205 | ||||||||||
Construction work in progress | 1,990,396 | 1,784,264 | 2,108,896 | 1,784,264 | ||||||||||
6,299,729 | 6,075,750 | 6,393,108 | 6,075,750 | |||||||||||
Investments and funds: | ||||||||||||||
Nuclear decommissioning trust fund | 283,676 | 268,597 | 296,623 | 268,597 | ||||||||||
Deposit on Rocky Mountain transactions | 136,501 | 132,048 | 42,932 | 132,048 | ||||||||||
Investment in associated companies | 57,640 | 57,626 | 57,713 | 57,626 | ||||||||||
Long-term investments | 75,357 | 80,055 | 75,910 | 80,055 | ||||||||||
Restricted cash | 20,692 | 43,070 | 7,813 | 43,070 | ||||||||||
Other, at cost | 1,040 | 3,564 | 1,040 | 3,564 | ||||||||||
574,906 | 584,960 | 482,031 | 584,960 | |||||||||||
Current assets: | ||||||||||||||
Cash and cash equivalents | 409,321 | 443,671 | 437,810 | 443,671 | ||||||||||
Restricted cash | 613 | 613 | 156 | 613 | ||||||||||
Restricted short-term investments | 63,075 | 106,676 | 63,868 | 106,676 | ||||||||||
Receivables | 157,373 | 124,650 | 126,805 | 124,650 | ||||||||||
Inventories, at average cost | 239,204 | 246,795 | 235,186 | 246,795 | ||||||||||
Prepayments and other current assets | 18,388 | 15,562 | 15,977 | 15,562 | ||||||||||
887,974 | 937,967 | 879,802 | 937,967 | |||||||||||
Deferred charges: | ||||||||||||||
Deferred debt expense, being amortized | 64,992 | 67,470 | 63,026 | 67,470 | ||||||||||
Regulatory assets | 363,502 | 351,547 | 357,600 | 351,547 | ||||||||||
Other | 35,892 | 61,135 | 67,935 | 61,135 | ||||||||||
464,386 | 480,152 | 488,561 | 480,152 | |||||||||||
$ | 8,226,995 | $ | 8,078,829 | $ | 8,243,502 | $ | 8,078,829 | |||||||
The accompanying notes are an integral part of these condensed financial statements.
Oglethorpe Power Corporation
Condensed Balance SheetsJuneSeptember 30, 2012 and December 31, 2011
(dollars in thousands) | (dollars in thousands) | |||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||
(Unaudited) | (Unaudited) | |||||||||||||
Equity and Liabilities | ||||||||||||||
Capitalization: | ||||||||||||||
Patronage capital and membership fees | $ | 658,087 | $ | 633,689 | $ | 681,830 | $ | 633,689 | ||||||
Accumulated other comprehensive margin | 1,446 | 618 | 1,488 | 618 | ||||||||||
659,533 | 634,307 | 683,318 | 634,307 | |||||||||||
Long-term debt | 5,589,065 | 5,562,925 | 5,591,898 | 5,562,925 | ||||||||||
Obligation under capital leases | 142,682 | 146,781 | 140,067 | 146,781 | ||||||||||
Obligation under Rocky Mountain transactions | 136,501 | 132,048 | 42,932 | 132,048 | ||||||||||
6,527,781 | 6,476,061 | 6,458,215 | 6,476,061 | |||||||||||
Current liabilities: | ||||||||||||||
Long-term debt and capital leases due within one year | 165,909 | 172,818 | 169,282 | 172,818 | ||||||||||
Short-term borrowings | 648,122 | 461,093 | 757,315 | 461,093 | ||||||||||
Accounts payable | 72,318 | 134,095 | 60,711 | 134,095 | ||||||||||
Accrued interest | 83,507 | 91,106 | 71,026 | 91,106 | ||||||||||
Accrued taxes | 16,729 | 21,118 | 25,048 | 21,118 | ||||||||||
Member power bill prepayments, current | 56,763 | 66,819 | 65,573 | 66,819 | ||||||||||
Other current liabilities | 19,024 | 25,080 | 14,992 | 25,080 | ||||||||||
1,062,372 | 972,129 | 1,163,947 | 972,129 | |||||||||||
Deferred credits and other liabilities: | ||||||||||||||
Gain on sale of plant, being amortized | 24,876 | 26,113 | 24,257 | 26,113 | ||||||||||
Asset retirement obligations | 309,640 | 298,758 | 314,378 | 298,758 | ||||||||||
Member power bill prepayments, non-current | 37,225 | 35,500 | 48,973 | 35,500 | ||||||||||
Power sale agreement, being amortized | 47,585 | 54,816 | 43,970 | 54,816 | ||||||||||
Regulatory liabilities | 162,478 | 164,000 | 133,383 | 164,000 | ||||||||||
Other | 55,038 | 51,452 | 56,379 | 51,452 | ||||||||||
636,842 | 630,639 | 621,340 | 630,639 | |||||||||||
$ | 8,226,995 | $ | 8,078,829 | $ | 8,243,502 | $ | 8,078,829 | |||||||
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 SixNine Months Ended JuneSeptember 30, 2012 and 2011
(dollars in thousands) | (dollars in thousands) | |||||||||||||||||||||||||
Three Months | Six Months | Three Months | Nine Months | |||||||||||||||||||||||
2012 | 2011 | 2012 | 2011 | 2012 | 2011 | 2012 | 2011 | |||||||||||||||||||
Operating revenues: | ||||||||||||||||||||||||||
Sales to Members | $ | 310,483 | $ | 327,776 | $ | 605,713 | $ | 597,224 | $ | 338,768 | $ | 349,906 | $ | 944,481 | $ | 947,130 | ||||||||||
Sales to non-Members | 37,220 | 52,027 | 61,214 | 52,353 | 38,628 | 82,624 | 99,842 | 134,977 | ||||||||||||||||||
Total operating revenues | 347,703 | 379,803 | 666,927 | 649,577 | 377,396 | 432,530 | 1,044,323 | 1,082,107 | ||||||||||||||||||
Operating expenses: | ||||||||||||||||||||||||||
Fuel | 136,349 | 161,355 | 243,169 | 233,804 | 167,416 | 188,983 | 410,585 | 422,789 | ||||||||||||||||||
Production | 89,844 | 89,866 | 188,343 | 179,055 | 91,753 | 90,101 | 280,096 | 269,154 | ||||||||||||||||||
Depreciation and amortization | 40,556 | 50,927 | 85,100 | 85,332 | 37,789 | 51,382 | 122,889 | 136,714 | ||||||||||||||||||
Purchased power | 14,660 | 13,600 | 29,183 | 25,155 | 15,158 | 20,925 | 44,341 | 46,080 | ||||||||||||||||||
Accretion | 4,859 | 4,565 | 9,716 | 9,125 | 4,884 | 4,562 | 14,599 | 13,687 | ||||||||||||||||||
Deferral of Hawk Road and Smith Energy Facilities effect on net margin | (2,484 | ) | (2,753 | ) | (14,559 | ) | (11,072 | ) | (655 | ) | 13,240 | (15,214 | ) | 2,168 | ||||||||||||
Total operating expenses | 283,784 | 317,560 | 540,952 | 521,399 | 316,345 | 369,193 | 857,296 | 890,592 | ||||||||||||||||||
Operating margin | 63,919 | 62,243 | 125,975 | 128,178 | 61,051 | 63,337 | 187,027 | 191,515 | ||||||||||||||||||
Other income: | ||||||||||||||||||||||||||
Investment income | 7,760 | 6,926 | 16,015 | 14,320 | 6,435 | 7,147 | 22,450 | 21,467 | ||||||||||||||||||
Gain on termination of Rocky Mountain transactions | 14,719 | — | 14,719 | — | ||||||||||||||||||||||
Other | 3,156 | 3,416 | 6,899 | 6,782 | 2,591 | 3,198 | 9,490 | 9,980 | ||||||||||||||||||
Total other income | 10,916 | 10,342 | 22,914 | 21,102 | 23,745 | 10,345 | 46,659 | 31,447 | ||||||||||||||||||
Interest charges: | ||||||||||||||||||||||||||
Interest expense | 78,839 | 72,279 | 154,846 | 142,945 | 76,443 | 75,704 | 231,290 | 218,649 | ||||||||||||||||||
Allowance for debt funds used during construction | (20,017 | ) | (17,753 | ) | (40,437 | ) | (32,981 | ) | (21,151 | ) | (17,835 | ) | (61,588 | ) | (50,816 | ) | ||||||||||
Amortization of debt discount and expense | 5,135 | 5,341 | 10,082 | 10,488 | 5,761 | 5,405 | 15,843 | 15,893 | ||||||||||||||||||
Net interest charges | 63,957 | 59,867 | 124,491 | 120,452 | 61,053 | 63,274 | 185,545 | 183,726 | ||||||||||||||||||
Net margin | $ | 10,878 | $ | 12,718 | $ | 24,398 | $ | 28,828 | $ | 23,743 | $ | 10,408 | $ | 48,141 | $ | 39,236 | ||||||||||
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 SixNine Months Ended JuneSeptember 30, 2012 and 2011
(dollars in thousands) | (dollars in thousands) | |||||||||||||||||||||||||
Three Months | Six Months | Three Months | Nine Months | |||||||||||||||||||||||
2012 | 2011 | 2012 | 2011 | 2012 | 2011 | 2012 | 2011 | |||||||||||||||||||
Net margin | $ | 10,878 | $ | 12,718 | $ | 24,398 | $ | 28,828 | $ | 23,743 | $ | 10,408 | $ | 48,141 | $ | 39,236 | ||||||||||
Other comprehensive margin: | ||||||||||||||||||||||||||
Unrealized gain on available-for-sale securities | 120 | 613 | 828 | 592 | 42 | 741 | 870 | 1,333 | ||||||||||||||||||
Total comprehensive margin | $ | 10,998 | $ | 13,331 | $ | 25,226 | $ | 29,420 | $ | 23,785 | $ | 11,149 | $ | 49,011 | $ | 40,569 | ||||||||||
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 SixNine Months Ended JuneSeptember 30, 2012 and 2011
(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, 2010 | $ | 595,952 | $ | (469 | ) | $ | 595,483 | $ | 595,952 | $ | (469 | ) | $ | 595,483 | ||||||
Components of comprehensive margin: | ||||||||||||||||||||
Net margin | 28,828 | — | 28,828 | 39,236 | — | 39,236 | ||||||||||||||
Unrealized gain on available-for-sale securities | — | 592 | 592 | — | 1,333 | 1,333 | ||||||||||||||
Balance at June 30, 2011 | $ | 624,780 | $ | 123 | $ | 624,903 | ||||||||||||||
Balance at September 30, 2011 | $ | 635,188 | $ | 864 | $ | 636,052 | ||||||||||||||
Balance at December 31, 2011 | $ | 633,689 | $ | 618 | $ | 634,307 | $ | 633,689 | $ | 618 | $ | 634,307 | ||||||||
Components of comprehensive margin: | ||||||||||||||||||||
Net margin | 24,398 | — | 24,398 | 48,141 | — | 48,141 | ||||||||||||||
Unrealized gain on available-for-sale securities | — | 828 | 828 | — | 870 | 870 | ||||||||||||||
Balance at June 30, 2012 | $ | 658,087 | $ | 1,446 | $ | 659,533 | ||||||||||||||
Balance at September 30, 2012 | $ | 681,830 | $ | 1,488 | $ | 683,318 | ||||||||||||||
The accompanying notes are an integral part of these condensed financial statements.
Oglethorpe Power Corporation
Condensed Statements of Cash Flows (Unaudited)
For the SixNine Months Ended JuneSeptember 30, 2012 and 2011
(dollars in thousands) | (dollars in thousands) | |||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||
Cash flows from operating activities: | ||||||||||||||
Net margin | $ | 24,398 | $ | 28,828 | $ | 48,141 | $ | 39,236 | ||||||
Adjustments to reconcile net margin to net cash provided by operating activities: | ||||||||||||||
Depreciation and amortization, including nuclear fuel | 156,664 | 145,590 | 229,787 | 231,716 | ||||||||||
Accretion cost | 9,716 | 9,125 | 14,599 | 13,687 | ||||||||||
Amortization of deferred gains | (2,830 | ) | (2,830 | ) | (35,579 | ) | (4,245 | ) | ||||||
Allowance for equity funds used during construction | (1,432 | ) | (1,404 | ) | (2,123 | ) | (2,034 | ) | ||||||
Deferred outage costs | (13,379 | ) | (36,672 | ) | (22,583 | ) | (43,827 | ) | ||||||
Deferral of Hawk Road and Smith Energy Facilities effect on net margin | (14,559 | ) | (11,072 | ) | (15,214 | ) | 2,168 | |||||||
Gain on sale of investments | (5,625 | ) | (10,324 | ) | (8,001 | ) | (13,306 | ) | ||||||
Regulatory deferral of costs associated with nuclear decommissioning | 165 | 5,553 | (528 | ) | 5,825 | |||||||||
Other | (3,908 | ) | (3,622 | ) | (6,321 | ) | (5,971 | ) | ||||||
Change in operating assets and liabilities: | ||||||||||||||
Receivables | (34,699 | ) | (54,078 | ) | (8,742 | ) | (29,995 | ) | ||||||
Inventories | 7,591 | 1,171 | 11,609 | 2,250 | ||||||||||
Prepayments and other current assets | (2,826 | ) | (1,674 | ) | 206 | (462 | ) | |||||||
Accounts payable | (43,758 | ) | 19,553 | (54,392 | ) | 10,407 | ||||||||
Accrued interest | (7,599 | ) | (22,796 | ) | (20,080 | ) | (30,500 | ) | ||||||
Accrued taxes | (4,389 | ) | (7,920 | ) | 3,930 | (5,197 | ) | |||||||
Other current liabilities | (3,644 | ) | 1,376 | (3,888 | ) | (5,046 | ) | |||||||
Member power bill prepayments | (8,331 | ) | (41,957 | ) | 12,227 | (20,899 | ) | |||||||
Total adjustments | 27,157 | (11,981 | ) | 94,907 | 104,571 | |||||||||
Net cash provided by operating activities | 51,555 | 16,847 | 143,048 | 143,807 | ||||||||||
Cash flows from investing activities: | ||||||||||||||
Property additions | (346,654 | ) | (397,229 | ) | (495,925 | ) | (634,955 | ) | ||||||
Plant acquisition | — | (529,310 | ) | — | (530,293 | ) | ||||||||
Activity in decommissioning fund—Purchases | (418,240 | ) | (557,748 | ) | (536,224 | ) | (828,008 | ) | ||||||
—Proceeds | 415,247 | 554,710 | 532,041 | 823,598 | ||||||||||
Decrease in restricted cash and cash equivalents | 22,378 | 2,530 | 35,714 | 5,687 | ||||||||||
Decrease in restricted short-term investments | 43,601 | 81,660 | ||||||||||||
Increase in investment in associated organizations | (33 | ) | (603 | ) | ||||||||||
Decrease (Increase) in restricted short-term investments | 42,808 | (8,537 | ) | |||||||||||
Activity in investment in associated organizations | (112 | ) | (78 | ) | ||||||||||
Activity in other long-term investments—Purchases | (2,993 | ) | (824 | ) | (4,404 | ) | (1,246 | ) | ||||||
—Proceeds | 10,846 | 700 | 13,689 | 1,100 | ||||||||||
Activity on interest rate options—Purchases/Collateral returned | (43,070 | ) | — | (43,070 | ) | — | ||||||||
—Collateral received | 20,690 | — | 7,810 | — | ||||||||||
Other | 11,740 | (3,955 | ) | (17,086 | ) | (7,822 | ) | |||||||
Net cash used in investing activities | (286,488 | ) | (850,069 | ) | (464,759 | ) | (1,180,554 | ) | ||||||
Cash flows from financing activities: | ||||||||||||||
Long-term debt proceeds | 79,194 | 793,999 | 108,792 | 1,093,399 | ||||||||||
Long-term debt payments | (68,678 | ) | (260,981 | ) | (94,706 | ) | (285,067 | ) | ||||||
Increase in short-term borrowings, net | 187,029 | 47,694 | ||||||||||||
Increase (Decrease) in short-term borrowings, net | 296,222 | (30,202 | ) | |||||||||||
Other | 3,038 | (1,756 | ) | 5,542 | (3,134 | ) | ||||||||
Net cash provided by financing activities | 200,583 | 578,956 | 315,850 | 774,996 | ||||||||||
Net decrease in cash and cash equivalents | (34,350 | ) | (254,266 | ) | (5,861 | ) | (261,751 | ) | ||||||
Cash and cash equivalents at beginning of period | 443,671 | 672,212 | 443,671 | 672,212 | ||||||||||
Cash and cash equivalents at end of period | $ | 409,321 | $ | 417,946 | $ | 437,810 | $ | 410,461 | ||||||
Supplemental cash flow information: | ||||||||||||||
Cash paid for— | ||||||||||||||
Interest (net of amounts capitalized) | $ | 115,719 | $ | 126,758 | $ | 181,675 | $ | 189,258 | ||||||
Supplemental disclosure of non-cash investing and financing activities: | ||||||||||||||
Change in plant expenditures included in accounts payable | $ | (14,733 | ) | $ | 30,335 | $ | (13,069 | ) | $ | (27,810 | ) |
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 SixNine Months ended JuneSeptember 30, 2012 and 2011
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 as of JuneSeptember 30, 2012 and December 31, 2011.
Fair Value Measurements at Reporting Date Using | Fair Value Measurements at Reporting Date Using | |||||||||||||||||||||||||
June 30, | Quoted Prices in | Significant Other | Significant | September 30, | Quoted Prices in | Significant Other | Significant | |||||||||||||||||||
(dollars in thousands) | (dollars in thousands) | |||||||||||||||||||||||||
Decommissioning funds: | ||||||||||||||||||||||||||
Domestic equity | $ | 111,031 | $ | 111,031 | $ | — | $ | — | $ | 117,995 | $ | 117,995 | $ | — | $ | — | ||||||||||
International equity | 41,948 | 41,948 | — | — | 45,610 | 45,610 | — | — | ||||||||||||||||||
Corporate bonds | 48,046 | — | 48,046 | — | 51,269 | — | 51,269 | — | ||||||||||||||||||
US Treasury and government agency securities | 55,231 | 55,231 | — | — | 49,638 | 49,638 | — | — | ||||||||||||||||||
Agency mortgage and asset backed securities | 15,497 | — | 15,497 | — | 25,725 | — | 25,725 | — | ||||||||||||||||||
Other | 11,923 | 11,923 | — | — | 6,386 | 6,386 | — | — | ||||||||||||||||||
Bond, reserve and construction funds | 197 | 197 | — | — | 197 | 197 | — | — | ||||||||||||||||||
Long-term investments: | ||||||||||||||||||||||||||
Corporate bonds | 5,995 | — | 5,995 | — | 6,076 | 6,076 | — | — | ||||||||||||||||||
US Treasury and government agency securities | 6,889 | 6,889 | — | — | 6,811 | 6,811 | — | — | ||||||||||||||||||
Agency mortgage and asset backed securities | 2,670 | — | 2,670 | — | 2,828 | 2,828 | — | — | ||||||||||||||||||
Mutual funds | 59,803 | 59,803 | — | — | 59,970 | 59,970 | — | — | ||||||||||||||||||
Other | 225 | 225 | — | — | ||||||||||||||||||||||
Interest rate options | 39,215 | — | — | 39,215 | (1) | 29,921 | — | — | 29,921 | (1) | ||||||||||||||||
Natural gas swaps | (4,265 | ) | — | (4,265 | ) | — | (13 | ) | — | (13 | ) | — | ||||||||||||||
Fair Value Measurements at Reporting Date Using | |||||||||||||
December 31, | Quoted Prices in | Significant Other | Significant | ||||||||||
(dollars in thousands) | |||||||||||||
Decommissioning funds: | |||||||||||||
Domestic equity | $ | 102,285 | $ | 102,285 | $ | — | $ | — | |||||
International equity | 39,618 | 39,618 | — | — | |||||||||
Corporate bonds | 41,338 | — | 41,338 | — | |||||||||
US Treasury and government agency securities | 41,697 | 41,697 | — | — | |||||||||
Agency mortgage and asset backed securities | 28,519 | — | 28,519 | — | |||||||||
Derivative instruments | (982 | ) | — | — | (982 | ) | |||||||
Other | 16,122 | 16,122 | — | — | |||||||||
Bond, reserve and construction funds | 2,720 | 2,720 | — | — | |||||||||
Long-term investments | 80,055 | 72,342 | — | 7,713 | (2) | ||||||||
Interest rate options | 69,446 | — | — | 69,446 | (1) | ||||||||
Natural gas swaps | (7,220 | ) | — | (7,220 | ) | — | |||||||
The following tables present the changes in our Level 3 assets and liabilities measured at fair value on a recurring basis during the three and sixnine months ended JuneSeptember 30, 2012 and 2011.
Three Months Ended September 30, 2012 | ||||||||
Three Months Ended June 30, 2012 | ||||||||
Interest rate options | Interest rate options | |||||||
(dollars in thousands) | (dollars in thousands) | |||||||
Assets (Liabilities): | ||||||||
Balance at March 31, 2012 | $ | 66,860 | ||||||
Balance at June 30, 2012 | $ | 39,215 | ||||||
Total gains or losses (realized/unrealized): | ||||||||
Included in earnings (or changes in net assets) | (27,645 | ) | (9,294 | ) | ||||
Balance at June 30, 2012 | $ | 39,215 | ||||||
Balance at September 30, 2012 | $ | 29,921 | ||||||
Three Months Ended June 30, 2011 | Three Months Ended September 30, 2011 | |||||||||||||
Decommissioning funds | Long-term investments | Decommissioning funds | Long-term investments | |||||||||||
(dollars in thousands) | (dollars in thousands) | |||||||||||||
Assets (Liabilities): | ||||||||||||||
Balance at March 31, 2011 | $ | (548 | ) | $ | 8,408 | |||||||||
Balance at June 30, 2011 | $ | (505 | ) | $ | 8,048 | |||||||||
Total gains or losses (realized/unrealized): | ||||||||||||||
Included in earnings (or changes in net assets) | 43 | 40 | (527 | ) | ||||||||||
Impairment included in other comprehensive deficit | 50 | |||||||||||||
Liquidations | — | (400 | ) | (400 | ) | |||||||||
Balance at June 30, 2011 | $ | (505 | ) | $ | 8,048 | |||||||||
Balance at September 30, 2011 | $ | (1,032 | ) | $ | 7,698 | |||||||||
Six Months Ended June 30, 2012 | Nine Months Ended September 30, 2012 | |||||||||||||||||||
Decommissioning funds | Long-term investments | Interest rate options | Decommissioning funds | Long-term investments | Interest rate options | |||||||||||||||
(dollars in thousands) | (dollars in thousands) | |||||||||||||||||||
Assets (Liabilities): | ||||||||||||||||||||
Balance at December 31, 2011 | $ | (982 | ) | $ | 7,713 | $ | 69,446 | $ | (982 | ) | $ | 7,713 | $ | 69,446 | ||||||
Total gains or losses (realized/unrealized): | ||||||||||||||||||||
Included in earnings (or changes in net assets) | 982 | — | (30,231 | ) | 982 | — | (39,525 | ) | ||||||||||||
Impairment included in other comprehensive margin (deficit) | — | 887 | — | — | 887 | — | ||||||||||||||
Liquidations | — | (8,600 | ) | — | — | (8,600 | ) | — | ||||||||||||
Balance at June 30, 2012 | $ | — | $ | — | $ | 39,215 | ||||||||||||||
Balance at September 30, 2012 | $ | — | $ | — | $ | 29,921 | ||||||||||||||
Six Months Ended June 30, 2011 | Nine Months Ended September 30, 2011 | |||||||||||||
Decommissioning funds | Long-term investments | Decommissioning funds | Long-term investments | |||||||||||
(dollars in thousands) | (dollars in thousands) | |||||||||||||
Assets (Liabilities): | ||||||||||||||
Balance at December 31, 2010 | $ | (452 | ) | $ | 8,671 | $ | (452 | ) | $ | 8,671 | ||||
Total gains or losses (realized/unrealized): | ||||||||||||||
Included in earnings (or changes in net assets) | (53 | ) | 77 | (580 | ) | 127 | ||||||||
Liquidations | — | (700 | ) | — | (1,100 | ) | ||||||||
Balance at June 30, 2011 | $ | (505 | ) | $ | 8,048 | |||||||||
Balance at September 30, 2011 | $ | (1,032 | ) | $ | 7,698 | |||||||||
On February 15, 2012, we sold our remaining $8,600,000 of our auction rate securities, which resulted in a loss of $1,075,000. The loss was recorded as a regulatory asset and is being charged to income over a period of four years.
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 natural gas counterparties, and 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 JuneSeptember 30, 2012, 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 the natural gas swap arrangements, we pay the counterparty a fixed price for specified natural gas quantities and receive a payment for such quantities based on a market price index. These payment obligations are netted, such that if the market price index is lower than the fixed price, we will make a net payment, and if the market price index is higher than the fixed price, we will receive a net payment.
At JuneSeptember 30, 2012 and December 31, 2011 the estimated fair value of our natural gas contracts was an unrealized lossa liability of approximately $4,265,000$13,000 and $7,220,000, respectively.
As of JuneSeptember 30, 2012, neither we nor any counterparties were required to post credit support or collateral under the natural gas swap agreements. If the credit-risk-related contingent features underlying these agreements were triggered on JuneSeptember 30, 2012 due to our credit rating being downgraded below investment grade, we would have been required to post letters of credit totaling up to $5,288,000$159,000 with our counterparties.
The following table reflects the volume activity of our natural gas derivatives as of JuneSeptember 30, 2012 that is expected to settle or mature each year:
Year | Natural Gas Swaps | Natural Gas Swaps | ||||||
2012 | 9.5 | 1.6 | ||||||
2013 | 1.7 | 1.8 | ||||||
2014 | 0.7 | 0.9 | ||||||
Total | 11.9 | 4.3 | ||||||
Interest rate options. We are exposed to the risk of rising interest rates due to the significant amount of new long-term debt we expect to incur in connection with anticipated capital expenditures, particularly the construction of Vogtle Units No. 3 and No. 4. We have entered into a conditional term sheet with the Department of Energy to finance up to $3.057 billion of the cost to construct Vogtle Units No. 3 and No. 4. The term sheet provides for quarterly draws from 2012 through 2017 and interest rates that will be based on U.S. Treasury rates at the time of each draw, plus a fixed spread. In fourth quarter of 2011, we purchased interest rate options at a cost of $100,000,000 to hedge the interest rates on approximately $2.2 billion of the expected Department of Energy-guaranteed loan, representing a substantial portion of the projected borrowings from 2013 through 2017.
The interest rate options, commonly known as LIBOR swaptions, give us the right, but not the obligation, to enter into a swap in which we would pay a fixed rate and receive a floating LIBOR rate. However, the swaptions are required to be cash settled based on their value on the expiration date, thereby effectively capping our interest rates by offsetting the present value cost of an increase in interest rates above the fixed rate. The cash settlement value depends on the extent to which prevailing LIBOR swap rates exceed the fixed rate on the underlying swap, and the value would be zero if swap rates are at or below the fixed rate upon expiration. The fixed rates on the LIBOR swaptions we purchased arewere in the range of 150 to 250 basis points above current LIBOR swap rates in effect as of September 30, 2012 and the weighted average fixed rate is 4.17%. The swaptions' expiration dates, which range from 2013 through 2017, are timed to match the expected quarterly draw dates of the Department of Energy-guaranteed loan advances to be hedged. As the interest rate options' value is independent from the Department of Energy-guaranteed loan, the interest rate options could also serve as a hedge of interest rates on an alternative source of financing.
We paid the entire premiums at the time we entered into these interest rate option transactions and have no additional payment obligations. However, upon expiration of the interest rate options, each counterparty will be obligated to pay us the cash value of the interest rate options, if any. These derivatives are recorded at fair value and hedge accounting is not applied. At JuneSeptember 30, 2012 and December 31, 2011, the fair value of these interest rate options was approximately $39,215,000$29,921,000 and $69,446,000, respectively. To manage our credit exposure to these 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 interest rate options outstanding for that counterparty exceeds a certain threshold. The collateral thresholds range from $0 to $10,000,000 depending on each counterparty's credit rating. As of JuneSeptember 30, 2012 and December 31, 2011, we held $20,690,000$7,810,000 and $43,070,000 of funds posted as collateral by the counterparties, respectively. The collateral received is recorded as long-term restricted cash on our balance sheet. The liability associated with the collateral is recorded as an offset to the fair values of the interest rate options, which are recorded within other deferred charges on the condensed balance sheet, resulting in a net carrying amount of the interest rate options of $18,525,000$22,111,000 and $26,376,000 at JuneSeptember 30, 2012 and December 31, 2011, respectively.
We are deferring gains or losses from the change in fair value of each interest rate option and related carrying and other incidental costs in accordance with our rate-making treatment. The 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 expected Department of Energy-guaranteed loan or alternative financing.
We estimate the value of the LIBOR swaptions utilizing an option pricing model based on several inputs including the notional amount, the forward LIBOR swap rates, the option volatility, the fixed rate on the underlying swap, the time to expiration, the term of the underlying swap and discount rates, as well as credit attributes, including the credit spread of the counterparty and the amount of credit support that is available for each swaption. The fair value of the swaptions is sensitive to certain of these inputs, especially option volatility. We are able to effectively observe all of these factors using a variety of market sources except for the credit spreads of certain counterparties and the option volatility. We are able to estimate option volatility implied by valuations we obtain from various sources, but the valuations, and therefore the implied option volatilities vary considerably from one source to another. Since valuations of comparable instruments are generally not publicly available, we have categorized these LIBOR swaptions as Level 3. We considered both any intrinsic value and the remaining time value associated with the derivatives and considered counterparty credit risk in our determination of all estimated fair values. 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.
The following table reflects the notional amount of forecasted debt issuances we have hedged in each year with LIBOR swaptions as of JuneSeptember 30, 2012.
Year | LIBOR Swaption | |||
2013 | $ | 754,452 | ||
2014 | 563,425 | |||
2015 | 470,625 | |||
2016 | 310,533 | |||
2017 | 80,169 | |||
Total | $ | 2,179,204 | ||
The table below reflects the fair value of derivative instruments and their effect on our unaudited condensed balance sheet as of JuneSeptember 30, 2012.
Balance Sheet Location | Fair Value | Balance Sheet Location | Fair Value | |||||||||
(dollars in thousands) | (dollars in thousands) | |||||||||||
Total designated as hedges under authoritative guidance related to derivatives and hedging activities | ||||||||||||
Designated as hedges: | ||||||||||||
Assets: | ||||||||||||
Natural Gas Swaps | Other current assets | $ | 621 | |||||||||
Liabilities: | ||||||||||||
Natural Gas Swaps | Other current liabilities | $ | 4,265 | Other current liabilities | $ | 634 | ||||||
Total not designated as hedges under authoritative guidance related to derivatives and hedging activities | ||||||||||||
Not designated as hedges: | ||||||||||||
Assets: | ||||||||||||
Interest rate options | Other deferred charges | $ | 39,215 | Other deferred charges | $ | 29,921 | ||||||
The following table presents the realized gains and (losses) on derivative instruments recognized in margin or deferred on the balance sheet for the three and sixnine months ended JuneSeptember 30, 2012.
Effect of Derivative Instruments on the Condensed Statement of Revenues and | ||||||||||||||||||
Statement of | Three months | Six months | ||||||||||||||||
Statement of | Three months | Nine months | ||||||||||||||||
(dollars in thousands) | ||||||||||||||||||
Designated as hedges under authoritative guidance related to derivatives | ||||||||||||||||||
(dollars in thousands) | ||||||||||||||||||
Designated as hedges: | Designated as hedges: | |||||||||||||||||
Natural Gas Swaps | Purchased power | $ | 149 | $ | 149 | Purchased power | $ | 173 | $ | 197 | ||||||||
Natural Gas Swaps | Purchased power | (3,095 | ) | (5,502 | ) | Purchased power | (3,934 | ) | (9,204 | ) | ||||||||
Natural Gas Swaps | Regulatory assets | 990 | 990 | Fuel | 1,327 | 1,452 | ||||||||||||
Natural Gas Swaps | Regulatory assets | (11 | ) | (11 | ) | Fuel | (83 | ) | (315 | ) | ||||||||
Natural Gas Swaps | Receivables | 4,336 | (5,244 | ) | ||||||||||||||
Not designated as hedges under authoritative guidance related to derivatives | ||||||||||||||||||
Interest rate options | Regulatory assets | (27,645 | ) | (60,785 | ) | |||||||||||||
Total losses on derivatives | $ | (25,276 | ) | $ | (70,403 | ) | ||||||||||||
$ | (2,517 | ) | $ | (7,870 | ) | |||||||||||||
The following table presents the unrealized gains and (losses) on derivative instruments deferred on the balance sheet at September 30, 2012.
Balance Sheet Location | ||||||
(dollars in thousands) | ||||||
Designated as hedges: | ||||||
Natural Gas Swaps | Regulatory assets | $ | 621 | |||
Natural Gas Swaps | Receivables | (634 | ) | |||
Total designated as hedges | $ | (13 | ) | |||
Not designated as hedges: | ||||||
Interest rate options | Regulatory assets | $ | (70,079 | ) | ||
The following table summarizes the activities for available-for-sale securities as of JuneSeptember 30, 2012 and December 31, 2011.
Gross Unrealized | ||||||||||||||||||||||||||
(dollars in thousands) | Gross Unrealized | |||||||||||||||||||||||||
June 30, 2012 | Cost | Gains | Losses | Fair Value | ||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(dollars in thousands) | ||||||||||||||||||||||||||
September 30, 2012 | Cost | Gains | Losses | Fair Value | ||||||||||||||||||||||
Equity | $ | 149,018 | $ | 37,560 | $ | (6,900 | ) | $ | 179,678 | $ | 151,786 | $ | 45,123 | $ | (4,909 | ) | $ | 192,000 | ||||||||
Debt | 162,427 | 9,025 | (3,823 | ) | 167,629 | 167,106 | 10,771 | (3,757 | ) | 174,120 | ||||||||||||||||
Other | 11,923 | — | — | 11,923 | 6,610 | — | — | 6,610 | ||||||||||||||||||
Total | $ | 323,368 | $ | 46,585 | $ | (10,723 | ) | $ | 359,230 | $ | 325,502 | $ | 55,894 | $ | (8,666 | ) | $ | 372,730 | ||||||||
Gross Unrealized | |||||||||||||
(dollars in thousands) | |||||||||||||
December 31, 2011 | Cost | Gains | Losses | Fair Value | |||||||||
Equity | $ | 149,263 | $ | 29,789 | $ | (9,996 | ) | $ | 169,056 | ||||
Debt | 160,218 | 18,021 | (11,063 | ) | 167,176 | ||||||||
Other | 15,646 | 1,035 | (1,541 | ) | 15,140 | ||||||||
Total | $ | 325,127 | $ | 48,845 | $ | (22,600 | ) | $ | 351,372 | ||||
In June 2011, the FASB issued "Comprehensive Income (Topic 220) Presentation of Financial Statements" which amended certain provisions of ASC 220 "Comprehensive Income." These provisions change the presentation requirements for other comprehensive income and total comprehensive income and require one continuous statement or two separate but consecutive statements. Presentation of other comprehensive income in the statement of stockholders' equity is no longer permitted. These provisions are effective for fiscal and interim periods beginning after December 15, 2011. The adoption of these provisions did not have a material effect on our condensed financial statements.
In December 2011, the FASB issued "Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities," which modifies the disclosure requirements for offsetting financial instruments and derivative instruments. The update requires an entity to disclose information about offsetting and related arrangements and the effect of those arrangements on its financial position. This guidance is effective for our fiscal year ending December 31, 2013. We do not expect the adoption of this standard to have a material impact on our financial statements.
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 March 31, 2011 | $ | (490 | ) | |||||
Balance at June 30, 2011 | $ | 123 | ||||||
Unrealized gain | 613 | 741 | ||||||
Balance at June 30, 2011 | $ | 123 | ||||||
Balance at September 30, 2011 | $ | 864 | ||||||
Balance at March 31, 2012 | $ | 1,327 | ||||||
Balance at June 30, 2012 | $ | 1,446 | ||||||
Unrealized gain | 119 | 42 | ||||||
Balance at June 30, 2012 | $ | 1,446 | ||||||
Balance at September 30, 2012 | $ | 1,488 | ||||||
| Accumulated Other Comprehensive Margin (Deficit) Six Months Ended | Accumulated Other Comprehensive Margin (Deficit) Nine Months Ended | ||||||
---|---|---|---|---|---|---|---|---|
(dollars in thousands) | (dollars in thousands) | |||||||
Available-for-sale | Available-for-sale | |||||||
Balance at December 31, 2010 | $ | (469 | ) | $ | (469 | ) | ||
Unrealized gain | 592 | 1,333 | ||||||
Balance at June 30, 2011 | $ | 123 | ||||||
Balance at September 30, 2011 | $ | 864 | ||||||
Balance at December 31, 2011 | $ | 618 | $ | 618 | ||||
Unrealized gain | 828 | 870 | ||||||
Balance at June 30, 2012 | $ | 1,446 | ||||||
Balance at September 30, 2012 | $ | 1,488 | ||||||
Nuclear Construction
We, along with Georgia Power, the Municipal Electric Authority of Georgia and the City of Dalton, the "Co-owners," 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.
The Co-owners, Westinghouse Electric Company LLC and Stone & Webster, Inc., together, the "Contractor," and the Co-owners have established both informal and formal dispute resolution procedures in
accordance with the Engineering, Procurement and Construction Contract to design, engineer, procure, construct, and testfor Vogtle Units No. 3 and No. 4 in order to resolve issues arising during the course of constructing a project of this magnitude. Georgia Power, on behalf of the Co-owners, and the Contractor have successfully initiated both formal and informal claims through these procedures, including ongoing claims, to resolve disputes and expect to resolve any existing and future disputes.claims. When matters are not resolved through these procedures, the parties may proceed to litigation. The Contractor and Georgia Power, on behalf of the Co-owners are involved in litigation with respect to certain claims that have not been resolved through the formal dispute resolution process.
During the course of construction activities, issues have arisen that may impact the project budget and schedule. The most significant issues relate 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. Georgia Power, on behalf of the Co-owners, and the Contractor are negotiating these issues, including the assertion by the Contractor that the Co-owners are responsible for these costs under the terms of the contract. Through correspondence sent to the Co-owners, the Contractor provided its proposed adjustment to the contract price and, based on our ownership interest, the Contractor's estimated adjustment attributable to us is approximately $280 million in 2008 dollars with respect to these issues. Georgia Power, on behalf of the Co-owners, has not agreed with the amount of these proposed adjustments or that the Co-owners have responsibility for any costs related to these issues. 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 the costs related to these issues. 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 the costs related to these issues and seeking payment from the Co-owners for the full amount of these costs. While the litigation has commenced, Georgia Power expects 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. Georgia Power and the Co-owners intend to vigorously defend their positions. If these costs are ultimately imposed upon the Co-owners, we will capitalize the costs attributable to us. As of September 30, 2012, 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 expected to arise throughout the construction of Vogtle Units No. 3 and No. 4.
The ultimate outcome of these matters cannot be determined at this time.
Environmental Matters
As is typical for electric utilities, we are subject to various federal, state and local air and water quality requirements which, among other things, regulate emissions of pollutants, such as particulate matter, sulfur dioxide, nitrogen oxides and mercury into the air and discharges of other pollutants, including heat, into waters of the United States, which represent significant future risks and uncertainties. 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. Finally, we are subject to federal, state and local waste disposal requirements that regulate the manner of transportation, storage and disposal of various types of waste.
In general, environmental requirements are becoming increasingly stringent. Any new requirements in the future but not in existence now may substantially increase the cost of electric service by requiring changes in the design or operation of existing facilities or changes or delays in the location, design, construction or operation of new facilities. Failure to comply with any new requirements could result in the imposition of civil and criminal penalties as well as the complete shutdown of individual generating units not in compliance. Certain of our debt instruments and
credit agreements require us to comply in all material respects with laws, rules, regulations and orders imposed by applicable governmental authorities, which include current or future environmental laws and regulations. We believe that we are in compliance with those environmental regulations currently applicable to our business and operations. Should we fail to be in compliance with these requirements, or any new requirements, it would constitute a default under such debt instruments and credit agreements. Although it is our intent to comply with applicable current and future regulations, we cannot provide assurance that we will always be in compliance with such requirements.
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.
We are currently not subject to any environmental loss contingencies for which we believe it is probable or reasonably possible that a loss has been incurred that would be material to our financial position, results of operations or cash flows.
The following regulatory assets and (liabilities) are reflected on the accompanying condensed balance sheet as of JuneSeptember 30, 2012 and December 31, 2011.
2012 | 2011 | 2012 | 2011 | |||||||||||
(dollars in thousands) | (dollars in thousands) | |||||||||||||
Regulatory Assets: | ||||||||||||||
Premium and loss on reacquired debt(a) | $ | 92,428 | $ | 98,538 | $ | 89,373 | $ | 98,538 | ||||||
Amortization on capital leases(b) | 37,615 | 46,627 | 33,055 | 46,627 | ||||||||||
Outage costs(c) | 36,730 | 42,866 | 36,536 | 42,866 | ||||||||||
Interest rate swap termination fees(d) | 19,321 | 21,316 | 18,324 | 21,316 | ||||||||||
Asset retirement obligations(e) | 21,069 | 29,341 | 10,990 | 29,341 | ||||||||||
Depreciation expense(f) | 50,497 | 51,209 | 50,141 | 51,209 | ||||||||||
Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(g) | 21,391 | 17,602 | 23,336 | 17,602 | ||||||||||
Interest rate options cost(h) | 61,774 | 30,735 | 71,324 | 30,735 | ||||||||||
Deferral of effects on net margin—Smith Energy Facility(k) | 13,886 | 3,536 | 15,936 | 3,536 | ||||||||||
Other regulatory assets(i) | 8,791 | 9,777 | 8,585 | 9,777 | ||||||||||
Total Regulatory Assets | $ | 363,502 | $ | 351,547 | $ | 357,600 | $ | 351,547 | ||||||
Regulatory Liabilities: | ||||||||||||||
Accumulated retirement costs for other obligations(e) | $ | 31,829 | $ | 32,687 | $ | 30,071 | $ | 32,687 | ||||||
Net benefit of Rocky Mountain transactions(j) | 46,187 | 47,783 | 14,056 | 47,783 | ||||||||||
Deferral of effects on net margin—Hawk Road Energy Facility(k) | 11,554 | 15,811 | 12,773 | 15,811 | ||||||||||
Major maintenance sinking fund(l) | 28,921 | 28,524 | 30,101 | 28,524 | ||||||||||
Deferred debt service adder(m) | 42,537 | 37,586 | 45,012 | 37,586 | ||||||||||
Other regulatory liabilities(i) | 1,450 | 1,609 | 1,370 | 1,609 | ||||||||||
Total Regulatory Liabilities | $ | 162,478 | $ | 164,000 | $ | 133,383 | $ | 164,000 | ||||||
Net Regulatory Assets | $ | 201,024 | $ | 187,547 | $ | 224,217 | $ | 187,547 | ||||||
At June 30, 2012, we recorded the impact of the lease extensions which resulted in an increase in the capital asset and lease obligation for the Scherer 2 lease. The lease extensions did not have a material effect on our unaudited condensed financial statements. Leasehold improvements will be amortized over the extended lease terms.
In 2007, the U.S. Court of Federal Claims found in favor of Southern Company and awarded damages in the amount of $59,900,000 representing substantially all of the Southern Company system's direct costs of the expansion of spent nuclear fuel storage facilities at Plants Hatch and Plant Vogtle. Our share of the award was $17,980,000. In 2008, the government filed an appeal and, on March 11, 2011, the U.S. Court of Appeals for the Federal Circuit remanded the Georgia Power portion of the proceeding back to the U.S. Court of Federal Claims for reconsideration of the damages amount in light of the spent nuclear fuel acceptance rates adopted in a separate proceeding by the U.S. Court of Appeals for the Federal Circuit.
On April 5, 2012, the U.S. Court of Federal Claims issued a final order for judgment in favor of Georgia Power and awarded $54,017,000 in damages, of which our ownership share was approximately $16,205,000. The effects of the judgment are reflected in the unaudited financial statements for the quarter endedwere recorded at June 30, 2012 and resulted in a $9,679,000 reduction ofin total operating expenses, which included reductions to fuel expense, production costs and depreciation and amortization, as well as a $6,526,000 reduction to plant in service.
In 2008, a second claim against the government was filed for damages incurred after December 31, 2004 (the court-mandated cut-off in the original claim). The complaint does not contain any specific dollar amounts for recovery of damages. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts related to this claim have been recognized in the financial statements as of JuneSeptember 30, 2012.
For a more information regarding the nuclear fuel costs and litigation, see Note 1 of "Item8—FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA—Notes to Consolidated Financial Statements" in our 2011 Form 10-K.
On July 12, 2012, we terminated three of the six lease transactions prior to the end of their lease terms. These three leases were each owned by a separate owner trust for the benefit of one of the three investors, representing approximately 69% of the six original six lease transactions. In connection with the termination,these terminations, we incurred termination costs of approximately $17,200,000 and recognized $31,900,000 of the deferred net benefit associated with the terminated leases, resulting in a net gain on termination of $14,700,000 which we recognized in income in July 2012. The termination of these leases resulted in a $94,500,000 decrease in the Deposit on Rocky Mountain transactions and Obligation under Rocky Mountain transactions in our unaudited condensed balance sheet at September 30, 2012.
On October 18, 2012, we terminated two additional leases, each owned by a separate owner trust for the benefit of one of the other two investors, representing approximately 21% of the six original lease transactions. In connection with these terminations, we incurred termination costs of approximately $5,300,000 and recognized $9,532,000 of the deferred net benefit associated with the terminated leases, resulting in a net gain on termination of $4,232,000, which we recognized in income in October 2012. The termination of these leases also results in a $94,500,000$28,775,000 decrease in the Deposit on Rocky Mountain transactions and Obligation under Rocky Mountain transactions from the amounts reflected in our unaudited condensed balance sheet at JuneSeptember 30, 2012.
For a more detailed discussion of the Rocky Mountain lease transactions, see Note 2 to "Item8—FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA—Notes to Consolidated Financial Statements" in our 2011 on Form 10-K.
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 39 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.
Forward-Looking Statements and Associated Risks
This Quarterly Report on Form 10-Q contains forward-looking statements, including statements regarding, among other items, (i) anticipated financing transactions by us, (ii) our future capital expenditure requirements and funding sources and (iii) achievement of a margins for interest ratio at the minimum requirement contained in our first mortgage indenture and, in the case that our board of directors approves a budget for a particular fiscal year that seeks to achieve a higher margins for interest ratio, such higher board-approved margins for interest ratio. These forward-looking statements are based largely on our current expectations and are subject to a number of risks and uncertainties, some of which are beyond our control. For a discussion of some factors that could cause actual results to differ materially from those anticipated by these forward-looking statements, see "Item1A—RISK FACTORS" in our Annual Report on Form 10-K for the fiscal year ended December 31, 2011. In light of these risks and uncertainties, there can be no assurance that events anticipated by the forward-looking statements contained in this Quarterly Report on Form 10-Q will in fact transpire.
Results of Operations
For the Three and SixNine Months Ended JuneSeptember 30, 2012 and 2011
Net Margin
Throughout the year, we monitor our operating results and, with board approval, make budget adjustments when and as necessary to ensure our targeted margins for interest ratio is achieved. Under our first mortgage indenture, we are required to establish and collect rates that are reasonably expected, together with our other revenues, to yield at least a 1.10 margins for interest ratio in each fiscal year. However, to enhance margin coverage during this period of generation facility construction and acquisition, our board of directors approved budgets for 2011 and 2012 to achieve a 1.14 margins for interest ratio. As our construction and acquisition program evolves, our board of directors will continue to evaluate the level of margin coverage and may choose to change the targeted margins for interest ratio in the future, although not below the 1.10 margins for interest ratio required under our first mortgage indenture.
Our net margin for the three-month and six-monthnine-month periods ended JuneSeptember 30, 2012 was $10.9$23.7 million and $24.4$48.1 million compared to $12.7$10.4 million and $28.8$39.2 million for the same periods of 2011. We expect aThrough September 30, 2012, we collected 122.1% of our targeted net margin of $39.5$39.4 million for the year ending December 31, 2012 which2012. This is typical as our management generally budgets conservatively and adjusts the budget, if necessary, by the end of the year so that net margins will achieve, but not exceed, the targeted margins for interest ratio of 1.14.ratio.
Operating Revenues
Our operating revenues fluctuate from period to period based on several factors, including 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 or
purchased resources or member-owned resources over which we have dispatch rights, and 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 decreased 5.3%3.2% and increased 1.4%0.3% in the three-month and six-monthnine-month periods ended JuneSeptember 30, 2012 compared to the same periods of 2011. Megawatt-hour sales to members increased 4.2%1.3% and 10.1%6.6% for the three-month and six-monthnine-month periods ended JuneSeptember 30, 2012 compared to the same periods of 2011. The average total revenue per megawatt-hour from sales to members decreased 9.1%4.4% and 7.9%6.5% for the three-month and six-monthnine-month periods ended JuneSeptember 30, 2012 compared to the same periods of 2011.
The components of member revenues for the three-month and sixnine month periods ended JuneSeptember 30, 2012 and 2011 were as follows (amounts in thousands except for cents per kilowatt-hour):
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||||
2012 | 2011 | 2012 | 2011 | 2012 | 2011 | 2012 | 2011 | |||||||||||||||||||
Capacity revenues | $ | 173,446 | $ | 171,478 | $ | 347,633 | $ | 343,479 | $ | 171,267 | $ | 171,582 | $ | 518,900 | $ | 515,061 | ||||||||||
Energy revenues | 137,037 | 156,298 | 258,080 | 253,745 | 167,501 | 178,324 | 425,581 | 432,069 | ||||||||||||||||||
Total | $ | 310,483 | $ | 327,776 | $ | 605,713 | $ | 597,224 | $ | 338,768 | $ | 349,906 | $ | 944,481 | $ | 947,130 | ||||||||||
Kilowatt-hours sold to members | 5,563,074 | 5,341,362 | 10,265,873 | 9,324,218 | 6,156,398 | 6,077,054 | 16,422,271 | 15,401,272 | ||||||||||||||||||
Cents per kilowatt-hour | 5.58¢ | 6.14¢ | 5.90¢ | 6.41¢ | 5.50¢ | 5.76¢ | 5.75¢ | 6.15¢ | ||||||||||||||||||
Energy revenues were 12.3%6.1% and 1.5% lower and 1.7% higher for the three-month and six-monthnine-month periods ended JuneSeptember 30, 2012 compared to the same periods of 2011. Our average energy revenue per megawatt-hour from sales to members decreased 15.8%7.3% and 7.6% for the three-month and six-monthnine-month periods ended JuneSeptember 30, 2012 as compared to the same periods of 2011. The decrease in energy revenues for the secondthird quarter of 2012 as compared to the secondthird quarter of 2011 resulted primarily from lower natural gas prices. LowerFor the nine-month period ended September 30, 2012 as compared to the same period of 2011, lower natural gas prices, lower generation at Plant Wansley as well as the recognition of a $4.8 million reduction to nuclear fuel expense for the nuclear fuel disposal settlement with the Department of Energy also contributed to the reduction in total fuel costs. The decrease in total fuel costs was offset somewhat by higher generation from our gas-fired and nuclear facilities. For a discussion of total fuel costs and total generation, see "—Operating Expenses." For a discussion of the Department of Energy nuclear fuel disposal settlement see Note O of Notes to Unaudited Condensed Financial Statements.
Sales to Non-Members. Sales to non-members for the three-month and six-monthnine-month periods ended JuneSeptember 30, 2012 consisted of capacity and energy sales made under an agreement to sell the entire output of Unit No. 1 of the Thomas A. Smith Energy Facility, formerly known as the Murray Energy Facility, to Georgia Power Company through May 31, 2012, as well as energy sales to other non-members from Smith Units No. 1 and No. 2. The decrease duringfor the second quarter ofthree-month and nine-month periods ended September 30, 2012 versusas compared to the same periodperiods of 2011 was primarily due to lower capacity payments from Georgia Power after the agreement described above expired. We acquired Smith in April 2011.
Operating Expenses
Operating expenses for the three-month and six-monthnine-month periods ended JuneSeptember 30, 2012 decreased 10.6%14.3% and increased 3.8%, respectively,3.7% as compared to the same periods of 2011. The decrease in operating expenses during the secondthird quarter of 2012 as compared to the same quarter of 2011 was primarily due to lower fuel, and
depreciation and amortization and purchased power costs. The increasedecrease for the six-monthnine-month period ended JuneSeptember 30, 2012 as compared to the same period of 2011 was primarily due to lower fuel, depreciation and amortization offset somewhat by higher fuel, producuionproduction costs. The deferral of the effect on net margin for the Hawk Road and purchased power costs.
Table of ContentsSmith Energy Facilities also contributed to the decrease in total operating expenses.
The following table summarizes our megawatt-hour generation and fuel costs by generating source and purchased power costs.
Three Months Ended June 30, | Three Months Ended September 30, | |||||||||||||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||||||||||||
Fuel Source | Cost | Generation | Cost | Generation | Cost | Generation | Cost | Generation | ||||||||||||||||||
(thousands) | (Mwh) | (thousands) | (Mwh) | (thousands) | (Mwh) | (thousands) | (Mwh) | |||||||||||||||||||
Coal | $ | 64,883 | 2,069,400 | $ | 72,342 | 2,315,372 | $ | 68,630 | 2,292,572 | $ | 73,377 | 2,488,052 | ||||||||||||||
Nuclear | 17,702 | 2,612,822 | 18,373 | 2,308,955 | 22,092 | 2,556,238 | 19,869 | 2,486,884 | ||||||||||||||||||
Gas | 53,197 | 2,267,328 | 70,037 | 1,732,957 | 76,356 | 2,754,825 | 94,599 | 2,332,508 | ||||||||||||||||||
Pumped Storage | 567 | 312,473 | 603 | 246,712 | 338 | 345,498 | 1,138 | 346,849 | ||||||||||||||||||
$ | 136,349 | 7,262,023 | $ | 161,355 | 6,603,996 | $ | 167,416 | 7,949,133 | $ | 188,983 | 7,654,293 | |||||||||||||||
Cost | Purchased | Cost | Purchased | Cost | Purchased | Cost | Purchased | |||||||||||||||||||
(thousands) | (Mwh) | (thousands) | (Mwh) | (thousands) | (Mwh) | (thousands) | (Mwh) | |||||||||||||||||||
Purchased Power | $ | 14,660 | 61,400 | $ | 13,600 | 39,471 | $ | 15,158 | 9,034 | $ | 20,925 | 196,147 | ||||||||||||||
Six Months Ended June 30, | Nine Months Ended September 30, | |||||||||||||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||||||||||||
Fuel Source | Cost | Generation | Cost | Generation | Cost | Generation | Cost | Generation | ||||||||||||||||||
(thousands) | (Mwh) | (thousands) | (Mwh) | (thousands) | (Mwh) | (thousands) | (Mwh) | |||||||||||||||||||
Coal | $ | 117,878 | 3,748,595 | $ | 122,906 | 3,997,491 | $ | 186,507 | 6,041,167 | $ | 196,283 | 6,485,543 | ||||||||||||||
Nuclear | 38,033 | 5,046,539 | 34,515 | 4,705,954 | 60,126 | 7,602,777 | 54,385 | 7,192,838 | ||||||||||||||||||
Gas | 86,075 | 3,663,540 | 75,128 | 1,755,868 | 162,430 | 6,418,365 | 169,727 | 4,088,376 | ||||||||||||||||||
Pumped Storage | 1,183 | 512,973 | 1,255 | 429,864 | 1,522 | 858,471 | 2,394 | 776,713 | ||||||||||||||||||
$ | 243,169 | 12,971,647 | $ | 233,804 | 10,889,177 | $ | 410,585 | 20,920,780 | $ | 422,789 | 18,543,470 | |||||||||||||||
Cost | Purchased | Cost | Purchased | Cost | Purchased | Cost | Purchased | |||||||||||||||||||
(thousands) | (Mwh) | (thousands) | (Mwh) | (thousands) | (Mwh) | (thousands) | (Mwh) | |||||||||||||||||||
Purchased Power | $ | 29,183 | 106,504 | $ | 25,155 | 60,678 | $ | 44,341 | 44,555 | $ | 46,080 | 256,825 | ||||||||||||||
For the three-month and six-monthnine-month periods ended JuneSeptember 30, 2012, total fuel costs decreased 15.5%11.4% and increased 4.0%2.9% and total megawatt-hour generation increased 10.0%3.9% and 19.1%12.8%, respectively, compared to the same periods of 2011. Average fuel costs per megawatt-hour decreased 23.2%14.7% and 12.7%13.9% in the three-month and six-monthnine-month periods ended JuneSeptember 30, 2012 compared to the same periods of 2011. The decreaseThese decreases in total fuel costs during the three-month period ended June 30, 2012 compared to the same period of 2011 waswere primarily due to lower natural gas prices and lower generation at Plant Wansley. The lower generation at Plant Wansley was primarily driven by the availability of more economical generation from our natural gas-fired facilities. The recognition of a $4.8 million expense reduction related to the nuclear fuel disposal settlement also contributed to lower fuel costs for the period though this reduction was substantially offset by higher nuclear generation. The increasedecrease in total fuel costs for the six-month period ended June 30, 2012 compared to the same period of 2011 was primarilyoffset somewhat due to an increase in natural gas-fired generation of 1,907,0000 megawatt-hours. The increase in generation422,000 megawatt-hours and 2,330,000 megawatt-hours for the three-month and six-monthnine-month periods ended JuneSeptember 30, 2012 as compared to the same periods of 2011 2011. This increase in generation
resulted from increased natural gas-fired generation fromat Smith which was sold to non-members and generation fromat the Chattahoochee Energy Facility which was sold to our members. As discussed previously, we acquired Smith was acquired in April 2011 and Chattahoochee was unavailable during the first quarter of 2011. An increase in nuclear generation also contributed to the year-to-date higher total
fuel costs. The decrease in average fuel costs per megawatt-hour of generation for 2012 compared to 2011 has been driven primarily by a significant decline in natural gas prices, which has made natural gas-fired generation resources a more economical and cost-effective source of energy generation than in prior years. The increase in nuclear generation, which is our most economical energy generation, contributed to the decline as well.
Total production costs decreased 0.02%increased 1.8% and increased 5.2%4.1% for the three-month and six-monthnine-month periods ended JuneSeptember 30, 2012 compared to the same periods of 2011. WhileThe increase in production costs varied only slightly for the second quarter of 2012 compared to the same period 2011, higher general operation maintenance costs at Plants Vogtle and Hatch were offset by recognition of a $3.0 million expense reduction from the nuclear fuel disposal settlement. The increase for the six-month period ended June 30, 2012 compared to the same period of 2011 was primarily due to operation and maintenance expenses incurred at Smith and increased general operationsoperation and maintenance expenses at Plants Vogtle and Hatch and higher operations and maintenance expenses at Chattahoochee.Hatch. These increases were offset somewhat by lower production costs forat the Hawk Road Energy Facility as production costs for Hawk Road in the first quarter of 2011 included expenses for planned outage work and for repair of a damaged transformer. Also, the higher general operation maintenance costs at Plants Vogtle and Hatch were offset somewhat by the recognition of a $3.0 million expense reduction from the nuclear fuel disposal settlement. For a discussion of the Department of Energy nuclear fuel disposal settlement see Note O of Notes to Unaudited Condensed Financial Statements.
Depreciation and amortization costs decreased 20.4%26.5% and 0.3%10.1% for the three-month and six-monthnine-month periods ended JuneSeptember 30, 2012 respectively,as compared to the same periods of 2011. The decrease for the second quarter ofthree-month period ended September 30, 2012 as compared to the same period of 2011 resulted primarily from lower amortization costs in 2012 for the intangible asset associated with the purchase and sale agreement with Georgia Power acquired as part of the Smith acquisition. For the six-monthnine-month period ended JuneSeptember 30, 2012 compared to the same period of 2011, the decrease in amortization costs due to the expiration of the Georgia Power agreement was mostlypartially offset by sixnine months of Smith depreciation expense in 2012 versus threesix months of depreciation expense inthrough September 30, 2011.
Total purchased power costs increased 7.8%decreased 27.6% and 16.0%3.8%, respectively, for the three-month and six-monthnine-month periods ended JuneSeptember 30, 2012 compared to the same periods of 2011. The increasedecrease in purchased power costs during the third quarter of 2012 as compared to the same period of 2011 was primarily due to lower megawatt-hours acquired under the our energy replacement program, which replaces power from our owned generation facilities with energy purchased at lower prices in the spot market. For the nine-months ended September 30, 2012 as compared to the same period of 2011 the decrease in energy replacement costs was mostly offset by higher realized losses incurred for natural gas financial contracts utilized for managing exposure to fluctuations in the market prices of natural gas.
The effect on net margin for Hawk Road and Smith is being deferred until 2016 at which time the amounts will be amortized over the remaining life of the plants. In implementing the deferral plans, we assumed that our members would generally not require energy from the plants until 2016. If any of our members who subscribed to Smith elect to take energy from Smith prior to 2016, the deferral of the effect on net margin would terminate for that member and the amortization of that member's deferral would commence immediately. The changes in cost deferrals in 2012 compared to 2011 resulted from the Hawk Road and Smith production and depreciation and amortization costs are discussed above.
Other Income
Investment income decreased 10.0% and increased 12.0% and 11.8%4.6% for the three-month and six-monthnine-month periods ended JuneSeptember 30, 2012 as compared to the same periods of 2011. The decrease in the third quarter of 2012 as compared to the same period of 2011 was primarily due to the decrease in interest income
from deposits related to the Rocky Mountain lease transactions, a portion of which were terminated in July 2012. See Note P of Notes to Unaudited Condensed Financial Statements for further discussion. For the nine-months ended September 30, 2012 as compared to the same period of 2011, the increased investment income resultingresulted primarily from a higher funds deposited infund balance. See Note I of Notes to Unaudited Condensed Financial Statements regarding the Rural Utilities Service Cushion of Credit Account.
The gain on termination of Rocky Mountain transactions represents the net gain resulting from the July 2012 termination of three of six leases. The net gain includes termination costs of $17.2 million as well as recognizing $31.9 million of the deferred net benefit associated with the terminated leases resulting in a net gain of $14.7 million.
Interest charges
Interest expense increased by 9.1%1.0% and 8.3%5.8% in the three-month and six-monthnine-month periods ended JuneSeptember 30, 2012 compared to the same periods of 2011. This increase isThese increases are primarily due to the increased debt issued to finance the construction of Vogtle Units No. 3 and No. 4.
Allowance for debt funds used during construction increased by 12.8%18.6% and 22.6%21.2% in the three-month and six-monthnine-month periods ended JuneSeptember 30, 2012 compared to the same periods of 2011 primarily due to construction expenditures for Vogtle Units No. 3 and No. 4.
Financial Condition
Balance Sheet Analysis as of JuneSeptember 30, 2012
Assets
Cash used for property additions for the six-monthnine-month period ended JuneSeptember 30, 2012 totaled $346.7$495.9 million. Of this amount, approximately $164$238 million was associated with construction expenditures for Vogtle Units No. 3 and No. 4. The remaining expenditures were for purchases of nuclear fuel, environmental control systems being installed primarily at Plant Scherer and for normal additions and replacements to existing generation facilities.
The $63.1deposit on Rocky Mountain transactions and the associated obligation under Rocky Mountain transactions decreased $89.1 million due to the July 2012 termination of three of the six lease transactions prior to the end of the lease terms. For information regarding the lease terminations, see Note P of Notes to Unaudited Condensed Financial Statement.
The long-term portion of restricted cash decreased $35.3 million due to a reduction in counterparty collateral postings required in connection with our interest rate options. The swap agreements with the counterparties contain support provisions that require each counterparty to provide collateral in the form of cash or securities to the extent that the value of the options outstanding for the counterparty exceeds a certain threshold. For information regarding our interest rate options, see Note C of Notes to Unaudited Condensed Financial Statements.
The $63.9 million of restricted short-term investments at JuneSeptember 30, 2012 representedrepresent funds deposited into a Rural Utilities Service Cushion of Credit Account with the U.S. Treasury and 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.
Receivables increased by $32.7 million as of June 30, 2012 compared to December 31, 2011. The December 31, 2011 receivables balance included $17.7 million of credits available to the members for a board approved reduction to 2011 revenue requirements as a result of margins collected in excess of our 2011 target. A portion of the increase in receivables was due to these credits being utilized by the members during the first quarter of 2012. The receivable for amounts billed or billable to the members for their monthly power bills also increased by $18.5 million in June 2012 compared to December 2011 due to higher energy costs in June 2012, which was a result of increased generation. In addition, power sales to non-members contributed to $7.4 million of the increase in receivables. Offsetting the increase was a decrease in the receivable balance for certain project costs written off in December 2011, for which a receivable from the members was recorded at December 31, 2011.
Other deferred charges decreased $25.2 million as of June 30, 2012 compared to December 31, 2011 due to an $8.8 million decrease in Georgia Power related deferred equipment prepayments that were expensed or capitalized in connection with a planned outage at Hatch Unit No. 1 that occurred in the first quarter of 2012 and an $8.4 million decrease in the amortized value of the intangible asset associated with the purchase and sale agreement with Georgia Power acquired as part of the 2011 Smith acquisition. Also contributing to the decrease was a $7.8 million decrease in the carrying amount of our interest rate hedges, which was impacted by a $30.2 million increase in the unrealized loss associated with the hedges and an offsetting $22.4 million decrease in counterparty collateral postings as of June 30, 2012 versus December 31, 2011.
Equity and Liabilities
Short-term borrowings for the six-monthnine-month period ended JuneSeptember 30, 2012 increased $187.0$296.2 million. The increase was primarily due to the issuance of commercial paper to fund capital expenditures related to Vogtle Units No. 3 and No. 4.
Accounts payable decreased $61.8$73.4 million as of JuneSeptember 30, 2012 compared to December 31, 2011 primarily due to a $75.8an $81 million decrease in the payable to Georgia Power for operation and maintenance costs for our co-owned plants and capital costs associated with Vogtle Units No. 3 and No. 4 construction. Offsetting the decrease was a $12.4$7.7 million increase in theaccruals for energy related costs in June 2012 as a result of increased generation.generation in September 2012 as compared to December 2011.
Other current liabilities decreased $10.1 million during the nine-month period ended September 30, 2012 primarily due to a $6.6 million decrease in the unrealized loss associated with our natural gas hedges and a $2.3 million decrease in other accrued expenses.
Member power bill prepayments represent funds received from the members for prepayment of their monthly power bills. At JuneSeptember 30, 2012, $56.8$65.6 million of member power bill prepayments was classified as a current liability and $37.2$49 million was classified as a long-term liability. During the six-monthnine-month period ended JuneSeptember 30, 2012, approximately $17.6$61.8 million of prepayments were received from the
members and approximately $26.0$49.6 million was applied to the members' monthly power bills. For information regarding the power bill prepayment program, see Note K of Notes to Unaudited Condensed Financial Statements and "—Capital Requirements and Liquidity and Sources of Capital—Liquidity."
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, the "Co-owners," 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. 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 2011 Form 10-K.
Westinghouse Electric Company LLC and Stone & Webster, Inc., together, the "Contractor," and the Co-owners have established both informal and formal dispute resolution procedures in accordance with the Engineering, Procurement and Construction Contract to design, engineer, procure, construct, and testfor Vogtle Units No. 3 and No. 4 in order to resolve issues arising during the course of constructing a project of this magnitude. Georgia Power, on behalf of the Co-owners, and the Contractor have successfully initiated both formal and informal claims through these procedures, including ongoing claims, to resolve disputes and expect to resolve any existing and future disputes.claims. When matters are not resolved through these procedures, the parties may proceed to litigation. The Contractor and Georgia Power, on behalf of the Co-owners are involved in litigation with respect to certain claims that have not been resolved through the formal dispute resolution process.
During the course of construction activities, issues have arisen that may impact the project budget and schedule. The most significant issues relate to costs associated with design changes to the Westinghouse AP1000 Design CertificationControl 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. Georgia Power, on behalf of the Co-owners, and the Contractor have begun negotiations regardingare negotiating these issues, including the assertion by the Contractor that the Co-owners are responsible for these costs under the terms of the contract. Through correspondence sent to the Co-owners, the Contractor provided its initial estimate of its proposed adjustment to the contract price and, has initiated the formal dispute resolution process. Basedbased on our ownership interest, the Contractor's estimated adjustment attributable to us regarding these issues is approximately $280 million in 2008 dollars with respect to these issues. Georgia Power, on behalf of the Co-owners, has not agreed with the amount of these proposed adjustments or that the Co-owners have responsibility for any costs related to these issues. 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 the costs related to these issues. 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 the costs related to these issues and seeking payment from the Co-owners for the full amount of these costs. While the formal dispute resolution processlitigation has been initiated,commenced, Georgia Power expects negotiations with the Contractor to continue over the next several months with respect to cost and schedule during which time the parties will attempt to reach a mutually acceptable compromise of their positions. If a compromise cannot be reached, formal dispute resolution, including litigation, may follow. Georgia Power on behalf ofand the Co-owners intendsintend to vigorously defend itstheir positions. If these costs are ultimately imposed upon the Co-owners, we will capitalize the costs attributable to us. In connection with these negotiations, the Co-owners are evaluating whether maintaining the currently scheduled commercial operation dates of 2016 and 2017 remains in the best interest of their customers. Additional claims by the Contractor or Georgia Power, on behalf of the Co-owners, are expected to arise throughout the construction of Vogtle Units No. 3 and No. 4.
In addition, there are processes in place that are designed to assure compliance with the design requirements specified in the DCD and the combined licenses, including rigorous inspection by Southern Nuclear Operating Company and the Nuclear Regulatory Commission that occurs throughout construction. During a
routine inspection in April 2012, the Nuclear Regulatory Commission identified that certain details of the rebar construction in the Vogtle Unit No. 3 nuclear island were not consistent with the DCD. In May 2012, Southern Nuclear received an official notice of violation relating to these findings from the Nuclear Regulatory Commission. The design changes were determined to have minimal safety significance and, on August 1,October 18, 2012, Southernthe Nuclear filedRegulatory Commission approved a license amendment request with the Nuclear Regulatory Commission to clarify that the nuclear island concrete and rebar construction will conform to Nuclear Regulatory Commission requirements. On August 2, 2012, the Nuclear Regulatory Commission accepted the filing as sufficient to allow review, and has indicated it has no objection with Southern Nuclear proceeding with installation as proposed in the amendment request, on an at-risk basis pending the outcome of a detailed review. Various inspection and other issues are expected to arise from time to time as construction proceeds, which may result in additional license amendments or require other resolution.
On February 16, 2012, a group of four plaintiffs who had intervened in the Nuclear Regulatory Commission's combined license proceedings for Vogtle Units No. 3 and No. 4 filed a petition in the U.S. Court of Appeals for the District of Columbia Circuit seeking judicial review and a stay of the Commission's issuance of the combined licenses. In addition, on February 16, 2012, a group of nine plaintiffs filed a petition with the U.S. Court of Appeals for the District of Columbia Circuit seeking judicial review of the Commission's certification of the DCD. On April 3, 2012, the Court granted a motion filed by these two groups to consolidate their challenges. On April 18, 2012, another group of petitioners filed a motion to stay the effectiveness of the order issuing the combined licenses for Vogtle Units No. 3 and No. 4 with the U.S. District Court for the District of Columbia. On July 11, 2012, the U.S. Court of Appeals for the District of Columbia Circuit denied the petitioners' motion to stay the effectiveness of the combined licenses. Georgia Power, on behalf of the Co-owners, has intervened and intends to vigorously contest these petitions.
There are other pending technical and procedural challenges to the construction and licensing of Vogtle Units No. 3 and No. 4. Similar additional challenges at both the state and federal level are expected as construction proceeds.
The ultimate outcome of these matters cannot be determined at this time. See "Item 1A—RISK FACTORS" in our 2011 Form 10-K for a discussion of certain risks associated with the licensing, construction and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world.
As of JuneSeptember 30, 2012, our total capitalized costs to date for Vogtle Units No. 3 and No. 4 were $1.5 billion.
Nuclear Regulation
On March 12, 2012, the Nuclear Regulatory Commission issued three orders and a request for information based on the Nuclear Regulatory Commission task force report recommendations that included, among other items, additional mitigation strategies for beyond-design-basis events, enhanced spent fuel pool instrumentation capabilities, hardened vents for certain classes of containment structures, including the one in use at Plant Hatch, site specific evaluations for seismic and flooding hazards, and various plant evaluations to ensure adequate coping capabilities during station blackout and other conditions. On August 29, 2012, the Nuclear Regulatory Commission staff issued the final interim staff guidance document, which offers acceptable approaches to meeting the requirements of the Nuclear Regulatory Commission's orders before the December 31, 2016 compliance deadline. The interim staff guidance is not mandatory, but licensees would be required to obtain Nuclear Regulatory Commission approval for taking an approach other than as outlined in the interim staff guidance. The final form and the resulting impact of any changes to safety requirements for nuclear reactors will be dependent on further review and action by the Nuclear Regulatory Commission and cannot be determined at this time. See "Item 1—BUSINESS—ENVIRONMENTAL AND OTHER REGULATION—Nuclear Regulation" in our 2011 Form 10-K for additional information. See "Item 1A—RISK FACTORS" in our 2011 Form 10-K for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world.
Environmental Regulations
The Environmental Protection Agency, or EPA, continues to develop a number of rules that significantly expand the scope of regulation of air emissions, water intake and waste management at power plants.
On February 16, 2012, EPA issued the final Mercury and Air Toxics Standards (MATS) rule for new and existing coal and oil-fired electric utility steam generating units, which is somewhat less stringent than proposed. The MATS rule establishes limits for emissions of heavy metals, including mercury. In order to comply with the MATS rule, the potential need to install baghouses at Plant Wansley at an approximate cost of $150 million was considered. See "Item 1—BUSINESS—ENVIRONMENTAL AND OTHER REGULATION—Air Quality—Mercury and Air Toxics Standards and State Mercury Rule" and "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Capital Requirements—Capital Expenditures" in our 2011 Form 10-K. Additional evaluation has shown that compliance with the MATS rule can be achieved using an alternative mercury emissions control technology. We anticipate using this alternative technology, which will decrease projected capital expenditures by more than $100 million over the next
four years. Although challenges to the MATS rule have been filed, we cannot predict the outcome of any litigation in this matter, including whether such outcome will further affect operations at Plants Wansley or Scherer.
On June 26,August 21, 2012, the U.S. Court of Appeals for the District of Columbia Circuit ruled in favorstruck down the Cross State Air Pollution Rule, finding that EPA had improperly interpreted the "good neighbor" provision of the Clean Air Act to determine upwind States' obligations to reduce their own significant contributions to a downwind state's nonattainment, and that EPA onhad not given states the principal litigation challenging several of EPA's greenhouse gas (GHG) rules. This decision will become final unlessinitial opportunity to implement the emissions reductions required under the provision. As a result, the Court agreesvacated the rule in its entirety and remanded it back to aEPA for further action consistent with the opinion. Subsequently, EPA and other parties requested rehearing or rehearingen banc of the U.S. Supremedecision. The Court agrees to its review. It ishas not known whether such actions will be requested,ruled on those motions, and we cannot predict thetheir ultimate outcome ofor any appeal that might be filed. Therefore, wefiled in this matter. At present, our operations continue to be regulated under EPA's Prevention of Significant Deterioration regulations for emissions of GHGs and any major modifications at our facilities will needClean Air Interstate Rule (which the Cross State Air Pollution Rule was meant to be permitted under these requirements.replace) until further action by the court or by EPA.
On JuneAugust 29, 2012, EPA proposed revisions to certain national ambient air quality standards (NAAQS)revise the New Source Performance Standards (NSPS) for fine particulate matter and plans to finalizestationary combustion turbines originally promulgated in 1979. Among other things, the standards by December 14, 2012. The proposed standards are more stringent than the existing fine particulate matter NAAQS and one of them would target improving visibility in urban areas. The impact of such standards,proposal, if finalized, would alter certain emissions standards for nitrogen oxides (NOx) for new, modified or reconstructed combustion turbines, and could in the future affect operations at our power plants that use such equipment, should they be modified or reconstructed. We cannot predict the content of the final standards or the effect they may have on our owned and co-owned power plants cannot be determined at this time.operations in the future.
For further discussion regarding potential effects on our business from environmental regulations, including potential capital requirements, see "Item 1—BUSINESS—ENVIRONMENTAL AND OTHER REGULATION," "Item 1A—RISK FACTORS" and "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Capital Requirements—Requirements—Capital Expenditures" in our 2011 Form 10-K.
Liquidity
At JuneSeptember 30, 2012, we had $1.4 billion of unrestricted available liquidity to meet our short-term cash needs and liquidity requirements. This amount included $409.3$438 million in cash and cash equivalents and $1.0 billion$915 million of unused and available committed credit arrangements.
On JuneSeptember 30, 2012, we had in excess of $1.9 billion of committed credit arrangements in place comprised of the five separate facilities 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(1) | $ | 1,265 | $ | 481 | (2) | June 2015 | $ | 1,265 | $ | 372 | (2) | June 2015 | ||||
CFC Line of Credit | 110 | 110 | September 2016 | 110 | 110 | September 2016 | ||||||||||
JPMorgan Chase Line of Credit | 150 | 34 | (3) | December 2013 | 150 | 33 | (3) | December 2013 | ||||||||
Secured facilities: | ||||||||||||||||
CoBank Line of Credit | 150 | 150 | November 2012 | 150 | 150 | November 2012 | ||||||||||
CFC Line of Credit | 250 | 250 | December 2013 | 250 | 250 | December 2013 | ||||||||||
Total | $ | 1,925 | $ | 1,025 | $ | 1,925 | $ | 915 |
Between projected cash on hand and these credit arrangements, 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.
We are currently negotiating with CoBank, ACB to replace our existing $150 million secured line of credit with a $150 million unsecured line of credit led by CoBank and syndicated among a group of participant banks. We expect to have the new facility in place prior to the expiration of the existing facility in late November 2012.
Due to the significant expenditures related to environmental compliance projects and new generation facilities, we have been funding our capital requirements through a combination of funds generated from operations and interim and long-term borrowings. In particular, we are using commercial paper, backed by the syndicated line of credit, to provide interim financing for: (i) the construction of Vogtle Units No. 3 and No. 4, (ii) a portion of the cost to acquire Smith, and (iii) the upfront payments made in connection with our interest rate hedging program, until long-term financing for these items is put in place.
We have the flexibility to use the syndicated line of credit for several purposes, including borrowing for general corporate purposes, issuing letters of credit and backing up outstanding commercial paper. Pursuant to our board authorization, we can issue commercial paper in amounts that do not exceed the amount of our committed backup line of credit, thereby providing 100% dedicated support for any commercial paper outstanding.
Like the syndicated line of credit, funds may be advanced under the $110 million line of credit with National Rural Utilities Cooperative Finance Corporation (CFC) and under the lines of credit with JPMorgan Chase Bank and CoBank for general working capital purposes. In addition, under those same credit facilities we have the ability to issue letters of credit totaling $910 million in the aggregate, of which $658$663 million remained available at JuneSeptember 30, 2012. However, amounts related to issued
letters of credit reduce the amount that would otherwise be available to draw for working capital needs. Also, any amounts drawn under the syndicated line for working capital or related to issued letters of credit will reduce the amount of commercial paper that we can issue.
Several of our credit facilities contain a financial covenant that requires us to maintain minimum levels of patronage capital. At JuneSeptember 30, 2012, the required minimum level was $598 million and our actual patronage capital was $658$682 million. Additional covenants contained in several of our credit facilities limit the amount of secured indebtedness and unsecured indebtedness we can have outstanding. At JuneSeptember 30, 2012, the most restrictive of these covenants limits our secured indebtedness to $8.5 billion and our unsecured indebtedness to $4.0 billion. At JuneSeptember 30, 2012, we had $5.6 billion of secured indebtedness and $1.0$1.1 billion of unsecured indebtedness outstanding, which was well within the covenant thresholds.
We also have a power bill prepayment program that provides us with an additional source of liquidity. Under the program, members can prepay their power bills from us at a discount for an agreed upon number of months in advance, after which the prepayments are credited against the participating members' monthly power bills. The discount is comparable to our avoided cost of borrowing. As of JuneSeptember 30, 2012, the balance of member prepayments received but not yet credited to their power bills was $94.0$114.5 million. We expect to apply the prepayments against the participating members' power bills through November 2017, with the majority of the remaining balance scheduled to be applied by the end of 2013. For more information regarding the power bill prepayment program, see Note K of Notes to Unaudited Condensed Financial Statements.
At JuneSeptember 30, 2012, current assets included $63.1$63.9 million of restricted short-term investments pursuant to deposits made to a Rural Utilities Service Cushion of Credit Account. Deposits in theSee Balance Sheet Analysis herein for more information regarding our Rural Utilities Service Cushion of Credit Account are made voluntarily and earn a guaranteed rate of interest of 5% per annum. The funds in the account, including interest thereon, can only be applied to debt service on Rural Utilities
Service notes and Rural Utilities Service-guaranteed Federal Financing Bank notes.Account. Our decisions regarding when to apply the funds are guided by the interest rate environment and our anticipated liquidity needs.
Financing Activities
First Mortgage Indenture. At JuneSeptember 30, 2012, we had $5.5 billion of long-term debt outstanding under our first mortgage indenture secured equally and ratably by a lien on substantially all of our tangible and some of our intangible assets, including those we acquire in the future. See "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Financing Activities—First Mortgage Indenture" in our 2011 Form 10-K for a further discussion of our first mortgage indenture.
Bond Financing. On April 2,Later in 2012, we closed a $32.4 million financing transaction that included two components. In one component the Development Authorityare planning an issuance of Monroe County issued, on our behalf, $10.1up to $250 million of term rate pollution control revenuetaxable first mortgage bonds for permanent financing of Vogtle Units No. 3 and No. 4 related costs and the purposeportion of refinancing a like amountthe acquisition cost of pollution control revenue bonds previously issued bySmith that the authority on our behalf that had matured. This tax-exempt debtRural Utilities Service is secured under our first mortgage indenture. The second component entailed a remarketing of $22.3 million of pollution control bonds issued previously on our behalf by the Development Authority of Burke County due to a mandatory tender of these bonds which were originally issued in a term rate period that ended March 31, 2012. Both components now bear interest in a term rate period that ends on February 28, 2013.
In a separate transaction on April 2, 2012, Georgia Transmission Corporation refinanced $40.2 million of pollution control bonds for which we were secondarily obligated. Upon this refinancing, we were no longer obligated for these bonds or any other of Georgia Transmission's debt obligations. For further discussion regarding our prior obligations related to Georgia Transmission, see "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION—Financial Condition—Off-Balance Sheet Arrangements—Georgia Transmission Debt Assumption" and Note 10 to "Item 8—FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA—Notes to Consolidated Financial Statements" in our 2011 Form 10-K.not financing.
Rural Utilities Service-Guaranteed Loans. We have six approved Rural Utilities Service-guaranteed loans, totaling $1.7 billion, which are being funded through the Federal Financing Bank totaling $1.7 billion thatand are in various stages of being drawn down, with $1.0 billion remaining to be advanced. When advanced, the debt will be secured under our first mortgage indenture.
Department of Energy-Guaranteed Loan. In May 2010, we signed a conditional term sheet with the Department of Energy that sets forth the general terms of a loan and related loan guarantee that would fund 70% of the estimated $4.2 billion cost to construct our 30% undivided share of Vogtle Units No. 3 and No. 4, not to exceed $3.057 billion. We continue to work with the Department of Energy on this proposed financing; however, final approval and issuance of a loan guarantee is subject to negotiation of definitive agreements, completion of due diligence and satisfaction of other conditions. Therefore, there can be no assurance that the Department of Energy will ultimately issue
the loan guarantee to us. We anticipate that any project costs not funded under the Department of Energy loan guarantee program would be financed through the issuance of taxable bonds.
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.Activities"
Table of Contents in our 2011 Form 10-K.
Off-Balance Sheet Arrangements
Rocky Mountain Lease Arrangements. As discussed in our 2011 Form 10-K, in December 1996 and January 1997, we entered into six long-term lease transactions relating to our 74.61% undivided interest in the Rocky Mountain Pumped-Storage Hydroelectric Plant. In each transaction, we leased a portion of our undivided interest to six separate owner trusts for the benefit of three investors for a term equal to 120% of the estimated useful life of Rocky Mountain.
On July 12, 2012, we terminated three of the six lease transactions prior to the end of their lease terms. TheseThe three leases were each owned by a separate owner trust for the benefit of one of the three investors, and represented approximately 69% of the six original lease transactions. On October 18, 2012, we terminated two additional leases, each owned by a separate owner trust for the benefit of one of the other two investors, representing another approximately 21% of the six original lease transactions. Subsequent to the above terminations, only one of the original lease arrangements remains in place, representing approximately 10% of the original lease transactions. The termination of these threefive leases significantly reduced our exposure to the four credit counterparties participating in the lease transactions.leases. Our negotiated cost to terminate the five leases represented a substantial discount to the amounts due pursuant to an early termination event under the operative lease documents.
As a result of these five lease terminations:
The termination of these leases had substantially no effect on our ownership, possession or use of Rocky Mountain. For additional information regarding the Rocky Mountain lease transactions, see "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Off-Balance Sheet Arrangements—Rocky Mountain Lease Arrangements" in our 2011 Form 10-K and Note P of Notes to Unaudited Condensed Financial Statements.
Newly Adopted or Issued Accounting Standards
For a discussion of recently issued or adopted accounting pronouncements, see Note E of Notes to Unaudited Condensed Financial Statements.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Not Applicable.
Item 4. Controls and Procedures
As of JuneSeptember 30, 2012, 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 September 30, 2012 that have materially affected, or are reasonably likely to affect, our internal control over financial reporting.
WeSee "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—FINANCIAL CONDITION—Capital Requirements and Liquidity and Sources of Capital—Vogtle Units No. 3 and No. 4" for a discussion of legal proceedings related to our participation in the construction of two additional nuclear units at Plant Vogtle. In addition to the aforementioned litigation, we are a party to various other actions and proceedings incidental to our normal business. Liability in the event of final adverse determination in any of these other matters is either covered by insurance or, in the opinion of our management, after consultation with counsel, should not in the aggregate have a material adverse effect on our financial position, results of operations or cash flows.
There have not been any material changes in our risk factors from those reported in "Item 1A—RISK FACTORS" of our 2011 Form 10-K.
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.
Not Applicable.Our President and Chief Executive Officer, Thomas A. Smith, is currently battling a serious illness. During his illness, Mr. Smith remains involved in our management and strategic direction and he continues to act in his capacity as President and Chief Executive Officer. In order to provide Mr. Smith additional flexibility to focus on treating his health concerns, our Executive Vice Presidents have expanded their roles and responsibilities in our day-to-day management and operations. Our board of directors is actively monitoring our leadership and management. Our board has a succession plan in place and is prepared to implement the plan, if necessary, to ensure that we continue to be managed in the best interests of our members.
Number | Description | ||
---|---|---|---|
31.1 | Rule 13a-14(a)/15d-14(a) Certification, by Thomas A. 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 Thomas A. 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/ Thomas A. Smith Thomas A. Smith President and Chief Executive Officer (Principal Executive Officer) | ||
Date: | /s/ Elizabeth B. Higgins Elizabeth B. Higgins Executive Vice President and Chief Financial Officer (Principal Financial Officer) |