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 o No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer," and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):Large Accelerated Filer o Accelerated Filer o Non-Accelerated Filer ý (Do not check if a smaller reporting company) Smaller Reporting Company o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý
Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.The registrant is a membership corporation and has no authorized or outstanding equity securities.
(This page has been left blank intentionally.)
OGLETHORPE POWER CORPORATION
INDEX TO QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED MARCH 31,JUNE 30, 2010
Oglethorpe Power Corporation
Condensed Balance Sheets (Unaudited)March 31,June 30, 2010 and December 31, 2009
(dollars in thousands) | (dollars in thousands) | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Assets | Assets | Assets | ||||||||||||||
Electric plant: | Electric plant: | Electric plant: | ||||||||||||||
In service | $ | 6,640,891 | $ | 6,550,938 | In service | $ | 6,651,340 | $ | 6,550,938 | |||||||
Less: Accumulated provision for depreciation | (3,023,117 | ) | (2,993,215 | ) | Less: Accumulated provision for depreciation | (3,052,840 | ) | (2,993,215 | ) | |||||||
3,617,774 | 3,557,723 | 3,598,500 | 3,557,723 | |||||||||||||
Nuclear fuel, at amortized cost | 249,405 | 215,949 | Nuclear fuel, at amortized cost | 240,233 | 215,949 | |||||||||||
Construction work in progress | 646,857 | 626,824 | Construction work in progress | 870,870 | 626,824 | |||||||||||
4,514,036 | 4,400,496 | 4,709,603 | 4,400,496 | |||||||||||||
Investments and funds: | Investments and funds: | Investments and funds: | ||||||||||||||
Decommissioning fund | 247,472 | 239,746 | ||||||||||||||
Deposit on Rocky Mountain transactions | 117,591 | 115,641 | Decommissioning fund | 234,232 | 239,746 | |||||||||||
Bond, reserve and construction funds | 2,981 | 3,982 | Deposit on Rocky Mountain transactions | 119,542 | 115,641 | |||||||||||
Investment in associated companies | 54,434 | 53,199 | Investment in associated companies | 55,329 | 53,199 | |||||||||||
Long-term investments | 88,309 | 87,129 | Long-term investments | 86,396 | 87,129 | |||||||||||
Other, at cost | 616 | 615 | Other, at cost | 3,598 | 4,597 | |||||||||||
511,403 | 500,312 | 499,097 | 500,312 | |||||||||||||
Current assets: | Current assets: | Current assets: | ||||||||||||||
Cash and cash equivalents, at cost | 302,458 | 579,069 | Cash and cash equivalents, at cost | 362,949 | 579,069 | |||||||||||
Restricted cash, at cost | 145,017 | 22,405 | Restricted cash, at cost | 8,021 | 22,405 | |||||||||||
Restricted short-term investments | 121,392 | 80,590 | Restricted short-term investments | 122,872 | 80,590 | |||||||||||
Receivables | 136,481 | 110,258 | Receivables | 155,793 | 110,258 | |||||||||||
Inventories, at average cost | 203,637 | 209,837 | Inventories, at average cost | 194,684 | 209,837 | |||||||||||
Prepayments and other current assets | 9,120 | 9,393 | Prepayments and other current assets | 11,340 | 9,393 | |||||||||||
918,105 | 1,011,552 | 855,659 | 1,011,552 | |||||||||||||
Deferred charges: | Deferred charges: | Deferred charges: | ||||||||||||||
Premium and loss on reacquired debt, being amortized | 119,336 | 122,847 | Premium and loss on reacquired debt, being amortized | 118,094 | 122,847 | |||||||||||
Deferred amortization of capital leases | 75,220 | 77,755 | Deferred amortization of capital leases | 72,213 | 77,755 | |||||||||||
Deferred debt expense, being amortized | 56,187 | 57,262 | Deferred debt expense, being amortized | 55,915 | 57,262 | |||||||||||
Deferred outage costs, being amortized | 45,543 | 31,319 | Deferred outage costs, being amortized | 40,023 | 31,319 | |||||||||||
Deferred tax assets | 24,000 | 24,000 | Deferred tax assets | 24,000 | 24,000 | |||||||||||
Deferred asset associated with retirement obligations | 26,006 | 31,413 | Deferred asset associated with retirement obligations | 45,126 | 31,413 | |||||||||||
Deferred interest rate swap termination fees, being amortized | 28,298 | 29,296 | Deferred interest rate swap termination fees, being amortized | 27,301 | 29,296 | |||||||||||
Deferred depreciation expense, being amortized | 53,700 | 54,056 | Deferred depreciation expense, being amortized | 53,344 | 54,056 | |||||||||||
Other | 30,891 | 29,926 | Other | 26,934 | 29,926 | |||||||||||
459,181 | 457,874 | 462,950 | 457,874 | |||||||||||||
$ | 6,402,725 | $ | 6,370,234 | $ | 6,527,309 | $ | 6,370,234 | |||||||||
The accompanying notes are an integral part of these condensed financial statements.
Oglethorpe Power Corporation
Condensed Balance Sheets (Unaudited)March 31,June 30, 2010 and December 31, 2009
(dollars in thousands) | (dollars in thousands) | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Equity and Liabilities | Equity and Liabilities | Equity and Liabilities | ||||||||||||||
Capitalization: | Capitalization: | Capitalization: | ||||||||||||||
Patronage capital and membership fees | $ | 576,823 | $ | 562,219 | Patronage capital and membership fees | $ | 584,223 | $ | 562,219 | |||||||
Accumulated other comprehensive deficit | (1,004 | ) | (1,253 | ) | Accumulated other comprehensive deficit | (220 | ) | (1,253 | ) | |||||||
575,819 | 560,966 | 584,003 | 560,966 | |||||||||||||
Long-term debt | 4,146,363 | 4,178,981 | Long-term debt | 4,191,462 | 4,178,981 | |||||||||||
Obligation under capital leases | 206,692 | 208,945 | Obligation under capital leases | 191,446 | 208,945 | |||||||||||
Obligation under Rocky Mountain transactions | 117,591 | 115,641 | Obligation under Rocky Mountain transactions | 119,542 | 115,641 | |||||||||||
5,046,465 | 5,064,533 | 5,086,453 | 5,064,533 | |||||||||||||
Current liabilities: | Current liabilities: | Current liabilities: | ||||||||||||||
Long-term debt and capital leases due within one year | 254,841 | 119,241 | Long-term debt and capital leases due within one year | 146,705 | 119,241 | |||||||||||
Short-term borrowings | 283,840 | 283,634 | Short-term borrowings | 410,879 | 283,634 | |||||||||||
Accounts payable | 7,879 | 24,184 | Accounts payable | 102,528 | 24,184 | |||||||||||
Accrued interest | 40,474 | 50,947 | Accrued interest | 49,589 | 50,947 | |||||||||||
Accrued and withheld taxes | 7,571 | 24,864 | Accrued and withheld taxes | 14,881 | 24,864 | |||||||||||
Members' advances, current | 117,777 | 182,514 | Member power bill prepayments, current | 85,791 | 182,514 | |||||||||||
Other current liabilities | 32,056 | 28,000 | Other current liabilities | 24,610 | 28,000 | |||||||||||
744,438 | 713,384 | 834,983 | 713,384 | |||||||||||||
Deferred credits and other liabilities: | Deferred credits and other liabilities: | Deferred credits and other liabilities: | ||||||||||||||
Gain on sale of plant, being amortized | 30,443 | 31,062 | Gain on sale of plant, being amortized | 29,825 | 31,062 | |||||||||||
Net benefit of Rocky Mountain transactions, being amortized | 53,354 | 54,151 | Net benefit of Rocky Mountain transactions, being amortized | 52,558 | 54,151 | |||||||||||
Asset retirement obligations | 268,850 | 264,635 | Asset retirement obligations | 273,132 | 264,635 | |||||||||||
Accumulated retirement costs for other obligations | 41,521 | 43,955 | Accumulated retirement costs for other obligations | 39,374 | 43,955 | |||||||||||
Long-term contingent liability | 24,000 | 24,000 | Long-term contingent liability | 24,000 | 24,000 | |||||||||||
Members' advances, non-current | 33,992 | 18,000 | Member power bill prepayments, non-current | 24,366 | 18,000 | |||||||||||
Power sale agreement, being amortized | 82,028 | 86,211 | Power sale agreement, being amortized | 77,846 | 86,211 | |||||||||||
Other | 77,634 | 70,303 | Other | 84,772 | 70,303 | |||||||||||
611,822 | 592,317 | 605,873 | 592,317 | |||||||||||||
$ | 6,402,725 | $ | 6,370,234 | $ | 6,527,309 | $ | 6,370,234 | |||||||||
The accompanying notes are an integral part of these condensed financial statements.
Oglethorpe Power Corporation
Condensed Statements of Revenues and Expenses (Unaudited)
For the Three and Six Months Ended March 31,June 30, 2010 and 2009
(dollars in thousands) | (dollars in thousands) | |||||||||||||||||||||||
Three Months | Three Months | Six Months | ||||||||||||||||||||||
2010 | 2009 | 2010 | 2009 | 2010 | 2009 | |||||||||||||||||||
Operating revenues: | Operating revenues: | Operating revenues: | ||||||||||||||||||||||
Sales to Members | $ | 303,828 | $ | 281,705 | Sales to Members | $ | 325,963 | $ | 300,527 | $ | 629,791 | $ | 582,232 | |||||||||||
Sales to non-Members | 244 | 308 | Sales to non-Members | 147 | 332 | 392 | 640 | |||||||||||||||||
Total operating revenues | 304,072 | 282,013 | Total operating revenues | 326,110 | 300,859 | 630,183 | 582,872 | |||||||||||||||||
Operating expenses: | Operating expenses: | Operating expenses: | ||||||||||||||||||||||
Fuel | 102,092 | 88,574 | Fuel | 121,459 | 98,545 | 223,551 | 187,119 | |||||||||||||||||
Production | 77,383 | 70,764 | Production | 85,878 | 69,269 | 163,261 | 140,033 | |||||||||||||||||
Purchased power | 17,408 | 25,146 | Purchased power | 18,217 | 34,050 | 35,625 | 59,196 | |||||||||||||||||
Depreciation and amortization | 37,010 | 30,884 | Depreciation and amortization | 36,505 | 32,827 | 73,515 | 63,711 | |||||||||||||||||
Accretion | 4,284 | 4,565 | Accretion | 4,282 | 4,566 | 8,566 | 9,131 | |||||||||||||||||
Total operating expenses | 238,177 | 219,933 | Total operating expenses | 266,341 | 239,257 | 504,518 | 459,190 | |||||||||||||||||
Operating margin | Operating margin | 65,895 | 62,080 | Operating margin | 59,769 | 61,602 | 125,665 | 123,682 | ||||||||||||||||
Other income (expense): | ||||||||||||||||||||||||
Other income: | Other income: | |||||||||||||||||||||||
Investment income | 7,656 | 7,502 | Investment income | 7,497 | 8,561 | 15,153 | 16,063 | |||||||||||||||||
Other | 3,281 | 2,958 | Other | 2,901 | 2,308 | 6,182 | 5,266 | |||||||||||||||||
Total other income | 10,937 | 10,460 | Total other income | 10,398 | 10,869 | 21,335 | 21,329 | |||||||||||||||||
Interest charges: | Interest charges: | Interest charges: | ||||||||||||||||||||||
Interest on long-term debt and capital leases | 64,367 | 56,136 | Interest on long-term debt and capital leases | 63,174 | 59,439 | 127,541 | 115,575 | |||||||||||||||||
Other interest | 1,221 | 617 | Other interest | 2,381 | 587 | 3,602 | 1,204 | |||||||||||||||||
Allowance for debt funds used during construction | (9,462 | ) | (3,805 | ) | Allowance for debt funds used during construction | (8,676 | ) | (4,739 | ) | (18,137 | ) | (8,544 | ) | |||||||||||
Amortization of debt discount and expense | 6,102 | 3,945 | Amortization of debt discount and expense | 5,888 | 4,375 | 11,990 | 8,320 | |||||||||||||||||
Net interest charges | 62,228 | 56,893 | Net interest charges | 62,767 | 59,662 | 124,996 | 116,555 | |||||||||||||||||
Net margin | Net margin | $ | 14,604 | $ | 15,647 | Net margin | $ | 7,400 | $ | 12,809 | $ | 22,004 | $ | 28,456 | ||||||||||
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 Deficit (Unaudited)
For the ThreeSix Months Ended March 31,June 30, 2010 and 2009
(dollars in thousands) | (dollars in thousands) | |||||||||||||||||||||
Patronage Capital and Membership Fees | Accumulated Other Comprehensive (Deficit) | Total | Patronage Capital and Membership Fees | Accumulated Other Comprehensive (Deficit) | Total | |||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Balance at December 31, 2008 | Balance at December 31, 2008 | $ | 535,829 | $ | (1,348 | ) | $ | 534,481 | Balance at December 31, 2008 | $ | 535,829 | $ | (1,348 | ) | $ | 534,481 | ||||||
Components of comprehensive margin: | Components of comprehensive margin: | Components of comprehensive margin: | ||||||||||||||||||||
Net margin | 15,647 | — | 15,647 | Net margin | 28,456 | — | 28,456 | |||||||||||||||
Unrealized gain on available-for-sale securities | — | 175 | 175 | Unrealized loss on available-for-sale securities | — | (79 | ) | (79 | ) | |||||||||||||
Total comprehensive margin | Total comprehensive margin | 15,822 | Total comprehensive margin | 28,377 | ||||||||||||||||||
Balance at March 31, 2009 | $ | 551,476 | $ | (1,173 | ) | $ | 550,303 | |||||||||||||||
Balance at June 30, 2009 | Balance at June 30, 2009 | $ | 564,285 | $ | (1,427 | ) | $ | 562,858 | ||||||||||||||
Balance at December 31, 2009 | Balance at December 31, 2009 | $ | 562,219 | $ | (1,253 | ) | $ | 560,966 | Balance at December 31, 2009 | $ | 562,219 | $ | (1,253 | ) | $ | 560,966 | ||||||
Components of comprehensive margin: | Components of comprehensive margin: | Components of comprehensive margin: | ||||||||||||||||||||
Net margin | 14,604 | — | 14,604 | Net margin | 22,004 | — | 22,004 | |||||||||||||||
Unrealized gain on available-for-sale securities | — | 249 | 249 | Unrealized gain on available-for-sale securities | — | 1,033 | 1,033 | |||||||||||||||
Total comprehensive margin | Total comprehensive margin | 14,853 | Total comprehensive margin | 23,037 | ||||||||||||||||||
Balance at March 31, 2010 | $ | 576,823 | $ | (1,004 | ) | $ | 575,819 | |||||||||||||||
Balance at June 30, 2010 | Balance at June 30, 2010 | $ | 584,223 | $ | (220 | ) | $ | 584,003 | ||||||||||||||
The accompanying notes are an integral part of these condensed financial statements.
Oglethorpe Power Corporation
Condensed Statements of Cash Flows (Unaudited)
For the ThreeSix Months Ended March 31,June 30, 2010 and 2009
(dollars in thousands) | (dollars in thousands) | |||||||||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||||||||
Cash flows from operating activities: | Cash flows from operating activities: | Cash flows from operating activities: | ||||||||||||||||||||
Net margin | $ | 14,604 | $ | 15,647 | Net margin | $ | 22,004 | $ | 28,456 | |||||||||||||
Adjustments to reconcile net margin to net cash provided (used) by operating activities: | Adjustments to reconcile net margin to net cash provided (used) by operating activities: | |||||||||||||||||||||
Depreciation and amortization, including nuclear fuel | 63,172 | 54,405 | Depreciation and amortization, including nuclear fuel | 129,788 | 109,999 | |||||||||||||||||
Accretion cost | 4,284 | 4,565 | Accretion cost | 8,566 | 9,131 | |||||||||||||||||
Amortization of deferred gains | (1,415 | ) | (1,415 | ) | Amortization of deferred gains | (2,830 | ) | (2,830 | ) | |||||||||||||
Allowance for equity funds used during construction | (531 | ) | (795 | ) | Allowance for equity funds used during construction | (994 | ) | (1,406 | ) | |||||||||||||
Deferred outage costs | (22,134 | ) | (13,850 | ) | Deferred outage costs | (25,080 | ) | (18,402 | ) | |||||||||||||
(Gain) Loss on sale of investments | (4,140 | ) | 4,792 | (Gain) loss on sale of investments | (9,015 | ) | 13,981 | |||||||||||||||
Regulatory deferral of costs associated with nuclear decommissioning | 1,610 | (7,747 | ) | Regulatory deferral of costs associated with nuclear decommissioning | 4,422 | (19,413 | ) | |||||||||||||||
Other | (1,135 | ) | 453 | Other | (2,438 | ) | 65 | |||||||||||||||
Change in operating assets and liabilities: | Change in operating assets and liabilities: | |||||||||||||||||||||
Receivables | (17,848 | ) | 4,589 | Receivables | (44,018 | ) | (28,370 | ) | ||||||||||||||
Inventories | 6,200 | (9,300 | ) | Inventories | 15,153 | (15,850 | ) | |||||||||||||||
Prepayments and other current assets | 274 | 1,588 | Prepayments and other current assets | (1,946 | ) | (933 | ) | |||||||||||||||
Accounts payable | (16,218 | ) | (32,541 | ) | Accounts payable | 5,935 | (11,184 | ) | ||||||||||||||
Accrued interest | (10,473 | ) | (1,261 | ) | Accrued interest | (1,358 | ) | 14,745 | ||||||||||||||
Accrued and withheld taxes | (17,293 | ) | (11,830 | ) | Accrued and withheld taxes | (9,982 | ) | (4,885 | ) | |||||||||||||
Other current liabilities | (4,556 | ) | (2,571 | ) | Other current liabilities | (5,197 | ) | 375 | ||||||||||||||
(Decrease) increase in Members' advances | (48,745 | ) | 155,287 | (Decrease) increase in Member power bill prepayments | (90,357 | ) | 180,753 | |||||||||||||||
Total adjustments | (68,948 | ) | 144,369 | Total adjustments | (29,351 | ) | 225,776 | |||||||||||||||
Net cash (used in) provided by operating activities | Net cash (used in) provided by operating activities | (54,344 | ) | 160,016 | Net cash (used in) provided by operating activities | (7,347 | ) | 254,232 | ||||||||||||||
Cash flows from investing activities: | Cash flows from investing activities: | Cash flows from investing activities: | ||||||||||||||||||||
Property additions | (161,815 | ) | (82,186 | ) | Property additions | (335,145 | ) | (270,099 | ) | |||||||||||||
Activity in decommissioning fund—Purchases | (133,043 | ) | (193,608 | ) | Plant acquisition | — | (105,008 | ) | ||||||||||||||
—Proceeds | 131,908 | 192,686 | Activity in decommissioning fund—Purchases | (299,446 | ) | (351,150 | ) | |||||||||||||||
Activity in bond, reserve and construction funds—Purchases | (104 | ) | (2 | ) | —Proceeds | 296,933 | 348,283 | |||||||||||||||
—Proceeds | 1,105 | 1,049 | Activity in bond, reserve and construction funds—Purchases | (104 | ) | (4 | ) | |||||||||||||||
(Increase) decrease in restricted cash and cash equivalents | (122,612 | ) | 10,255 | —Proceeds | 1,105 | 1,049 | ||||||||||||||||
Increase in restricted short-term investments | (40,802 | ) | (80,000 | ) | Decrease in restricted cash and cash equivalents | 14,383 | 10,255 | |||||||||||||||
Increase in investment in associated organizations | (580 | ) | (639 | ) | Increase in restricted short-term investments | (42,282 | ) | (80,756 | ) | |||||||||||||
Activity in other long-term investments—Purchases | (455 | ) | (452 | ) | Activity in investment in associated organizations—Purchases | (4,012 | ) | (11,254 | ) | |||||||||||||
—Proceeds | 700 | — | —Proceeds | 2,505 | 967 | |||||||||||||||||
Other | 66 | 2,011 | Activity in other long-term investments—Purchases | (2,367 | ) | (742 | ) | |||||||||||||||
—Proceeds | 2,700 | 200 | ||||||||||||||||||||
Other | 5,348 | (493 | ) | |||||||||||||||||||
Net cash used in investing activities | Net cash used in investing activities | (325,632 | ) | (150,886 | ) | Net cash used in investing activities | (360,382 | ) | (458,752 | ) | ||||||||||||
Cash flows from financing activities: | Cash flows from financing activities: | Cash flows from financing activities: | ||||||||||||||||||||
Long-term debt proceeds | 133,550 | 408,900 | Long-term debt proceeds | 222,631 | 408,900 | |||||||||||||||||
Long-term debt payments | (32,827 | ) | (30,689 | ) | Long-term debt payments | (200,197 | ) | (65,552 | ) | |||||||||||||
Proceeds from (payment of) notes payable | 206 | (140,000 | ) | Increase in short-term borrowings | 127,245 | 81,974 | ||||||||||||||||
Other | 2,436 | (899 | ) | Other | 1,930 | (6,240 | ) | |||||||||||||||
Net cash provided by financing activities | Net cash provided by financing activities | 103,365 | 237,312 | Net cash provided by financing activities | 151,609 | 419,082 | ||||||||||||||||
Net (decrease) increase in cash and cash equivalents | Net (decrease) increase in cash and cash equivalents | (276,611 | ) | 246,442 | Net (decrease) increase in cash and cash equivalents | (216,120 | ) | 214,562 | ||||||||||||||
Cash and cash equivalents at beginning of period | Cash and cash equivalents at beginning of period | 579,069 | 167,659 | Cash and cash equivalents at beginning of period | 579,069 | 167,659 | ||||||||||||||||
Cash and cash equivalents at end of period | Cash and cash equivalents at end of period | $ | 302,458 | $ | 414,101 | Cash and cash equivalents at end of period | $ | 362,949 | $ | 382,221 | ||||||||||||
Supplemental cash flow information: | Supplemental cash flow information: | Supplemental cash flow information: | ||||||||||||||||||||
Cash paid for— | Cash paid for— | Cash paid for— | ||||||||||||||||||||
Interest (net of amounts capitalized) | $ | 63,651 | $ | 54,209 | Interest (net of amounts capitalized) | $ | 108,629 | $ | 93,489 | |||||||||||||
Supplemental disclosure of non-cash investing and financing activities: | Supplemental disclosure of non-cash investing and financing activities: | Supplemental disclosure of non-cash investing and financing activities: | ||||||||||||||||||||
Plant expenditures included in ending accounts payable | $ | (388 | ) | $ | 21,081 | Plant expenditures included in ending accounts payable | $ | 73,221 | $ | 20,686 | ||||||||||||
Acquired power purchase and sale liability | $ | — | $ | 98,100 |
The accompanying notes are an integral part of these condensed financial statements.
Oglethorpe Power Corporation
Notes to Unaudited Condensed Financial StatementsMarch 31,June 30, 2010 and 2009
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 for the periods ended March 31,June 30, 2010 and December 31, 2009.
Fair Value Measurements at Reporting Date Using | Fair Value Measurements at Reporting Date Using | |||||||||||||||||||||||||||||
March 31, | Quoted Prices in | Significant Other | Significant | June 30, | Quoted Prices in | Significant Other | Significant | |||||||||||||||||||||||
(dollars in thousands) | (dollars in thousands) | |||||||||||||||||||||||||||||
Decommissioning funds | Decommissioning funds | Decommissioning funds | ||||||||||||||||||||||||||||
Domestic equity | $ | 93,500 | $ | 93,500 | $ | — | $ | — | Domestic equity | $ | 78,865 | $ | 78,865 | $ | — | $ | — | |||||||||||||
Corporate bonds | 49,968 | 49,968 | — | — | Corporate bonds | 50,815 | 50,815 | — | — | |||||||||||||||||||||
International equity | 40,429 | 40,429 | — | — | International equity | 34,388 | 34,388 | — | — | |||||||||||||||||||||
US Treasury and government agency securities | 40,401 | 40,401 | — | — | US Treasury and government agency securities | 46,943 | 46,943 | — | — | |||||||||||||||||||||
Mortgage and asset backed securities | 20,426 | 20,426 | — | — | Mortgage and asset backed securities | 20,015 | 20,015 | — | — | |||||||||||||||||||||
Municipal bonds | 1,330 | 1,330 | — | — | Municipal bonds | 1,704 | 1,704 | — | — | |||||||||||||||||||||
Derivative instruments | (435 | ) | — | — | (435 | ) | Derivative instruments | (311 | ) | — | — | (311 | ) | |||||||||||||||||
Other | 1,853 | 1,853 | — | — | Other | 1,813 | 1,813 | — | — | |||||||||||||||||||||
Bond, reserve and construction funds | Bond, reserve and construction funds | 2,981 | 2,981 | — | — | Bond, reserve and construction funds | 2,982 | 2,982 | — | — | ||||||||||||||||||||
Long-term investments | Long-term investments | 88,309 | 61,933 | — | 26,376 | (1) | Long-term investments | 86,396 | 61,911 | — | 24,485 | (1) | ||||||||||||||||||
Natural gas swaps | Natural gas swaps | (21,427 | ) | — | (21,427 | ) | — | Natural gas swaps | (14,381 | ) | — | (14,381 | ) | — | ||||||||||||||||
Deposit on Rocky Mountain transactions | Deposit on Rocky Mountain transactions | 117,591 | — | — | 117,591 | Deposit on Rocky Mountain transactions | 119,542 | — | — | 119,542 | ||||||||||||||||||||
Investments in associated companies | Investments in associated companies | 54,434 | — | — | 54,434 | Investments in associated companies | 55,329 | — | — | 55,329 | ||||||||||||||||||||
Total | $ | 489,360 | $ | 312,821 | $ | (21,427 | ) | $ | 197,966 | Total | $ | 484,100 | $ | 299,436 | $ | (14,381 | ) | $ | 199,045 | |||||||||||
Fair Value Measurements at Reporting Date Using | |||||||||||||||
December 31, | Quoted Prices in | Significant Other | Significant | ||||||||||||
(dollars in thousands) | |||||||||||||||
Decommissioning funds | |||||||||||||||
Domestic equity | $ | 89,723 | $ | 89,723 | $ | — | $ | — | |||||||
Corporate bonds | 48,317 | 48,317 | — | — | |||||||||||
International equity | 40,951 | 40,951 | — | — | |||||||||||
US Treasury and government agency securities | 35,137 | 35,137 | — | — | |||||||||||
Mortgage and asset backed securities | 21,383 | 21,383 | — | — | |||||||||||
Preferred stock | 1,463 | — | 1,463 | — | |||||||||||
Municipal bonds | 1,267 | 1,267 | — | — | |||||||||||
Derivative instruments | (260 | ) | — | — | (260 | ) | |||||||||
Other | 1,765 | 1,765 | — | — | |||||||||||
Bond, reserve and construction funds | 3,982 | 3,982 | — | — | |||||||||||
Long-term investments | 87,129 | 60,119 | — | 27,010 | (1) | ||||||||||
Natural gas swaps | (12,516 | ) | — | (12,516 | ) | — | |||||||||
Deposit on Rocky Mountain transactions | 115,641 | — | — | 115,641 | |||||||||||
Investments in associated companies | 53,199 | — | — | 53,199 | |||||||||||
Total | $ | 487,181 | $ | 302,644 | $ | (11,053 | ) | $ | 195,590 | ||||||
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 six months ended March 31,June 30, 2010 and 2009, respectively.
Three Months Ended March 31, 2010 | Three Months Ended June 30, 2010 | |||||||||||||||||||||||||||
Decommissioning funds | Long-term investments | Deposit on Rocky Mountain transactions | Investments in associated companies | Decommissioning funds | Long-term investments | Deposit on Rocky Mountain transactions | Investments in associated companies | |||||||||||||||||||||
(dollars in thousands) | (dollars in thousands) | |||||||||||||||||||||||||||
Assets: | Assets: | Assets: | ||||||||||||||||||||||||||
Balance at December 31, 2009 | $ | (260 | ) | $ | 27,010 | $ | 115,641 | $ | 53,199 | |||||||||||||||||||
Balance at March 31, 2010 | Balance at March 31, 2010 | $ | (435 | ) | $ | 26,376 | $ | 117,591 | $ | 54,434 | ||||||||||||||||||
Total gains or losses (realized/unrealized): | Total gains or losses (realized/unrealized): | Total gains or losses (realized/unrealized): | ||||||||||||||||||||||||||
Included in earnings (or changes in net assets) | (175 | ) | — | 1,950 | 1,235 | Included in earnings (or changes in net assets) | 124 | — | 1,951 | 895 | ||||||||||||||||||
Impairment included in other comprehensive deficit | — | 66 | — | — | Impairment included in other comprehensive deficit | — | 109 | — | — | |||||||||||||||||||
Purchases, issuances, liquidations | Purchases, issuances, liquidations | — | (700 | ) | — | — | Purchases, issuances, liquidations | — | (2,000 | ) | — | — | ||||||||||||||||
Balance at March 31, 2010 | $ | (435 | ) | $ | 26,376 | $ | 117,591 | $ | 54,434 | |||||||||||||||||||
Balance at June 30, 2010 | Balance at June 30, 2010 | $ | (311 | ) | $ | 24,485 | $ | 119,542 | $ | 55,329 | ||||||||||||||||||
Three Months Ended March 31, 2009 | ||||||||||||||
Decommissioning funds | Long-term investments | Deposit on Rocky Mountain transactions | Investments in associated companies | |||||||||||
(dollars in thousands) | ||||||||||||||
Assets: | ||||||||||||||
Balance at January 1, 2009 | $ | 6,085 | $ | 29,643 | $ | 108,219 | $ | 43,441 | ||||||
Total gains or losses (realized/unrealized): | ||||||||||||||
Included in earnings (or changes in net assets) | (4,645 | ) | — | 1,825 | 404 | |||||||||
Impairment included in other comprehensive deficit | — | (24 | ) | — | — | |||||||||
Balance at March 31, 2009 | $ | 1,440 | $ | 29,619 | $ | 110,044 | $ | 43,845 | ||||||
Six Months Ended June 30, 2010 | ||||||||||||||
Decommissioning funds | Long-term investments | Deposit on Rocky Mountain transactions | Investments in associated companies | |||||||||||
(dollars in thousands) | ||||||||||||||
Assets: | ||||||||||||||
Balance at January 1, 2010 | $ | (260 | ) | $ | 27,010 | $ | 115,641 | $ | 53,199 | |||||
Total gains or losses (realized/unrealized): | ||||||||||||||
Included in earnings (or changes in net assets) | (51 | ) | — | 3,901 | 2,130 | |||||||||
Impairment included in other comprehensive deficit | — | 175 | — | — | ||||||||||
Purchases, issuances, liquidations | — | (2,700 | ) | — | — | |||||||||
Balance at June 30, 2010 | $ | (311 | ) | $ | 24,485 | $ | 119,542 | $ | 55,329 | |||||
Three Months Ended June 30, 2009 | ||||||||||||||
Decommissioning funds | Long-term investments | Deposit on Rocky Mountain transactions | Investments in associated companies | |||||||||||
(dollars in thousands) | ||||||||||||||
Assets: | ||||||||||||||
Balance at March 31, 2009 | $ | 1,440 | $ | 29,619 | $ | 110,044 | $ | 43,845 | ||||||
Total gains or losses (realized/unrealized): | ||||||||||||||
Included in earnings (or changes in net assets) | 7,221 | — | 1,824 | 9,646 | ||||||||||
Impairment included in other comprehensive deficit | — | (120 | ) | — | — | |||||||||
Purchases, issuances, liquidations | — | (200 | ) | — | — | |||||||||
Balance at June 30, 2009 | $ | 8,661 | $ | 29,299 | $ | 111,868 | $ | 53,491 | ||||||
Six Months Ended June 30, 2009 | ||||||||||||||
Decommissioning funds | Long-term investments | Deposit on Rocky Mountain transactions | Investments in associated companies | |||||||||||
(dollars in thousands) | ||||||||||||||
Assets: | ||||||||||||||
Balance at January 1, 2009 | $ | 6,085 | $ | 29,643 | $ | 108,219 | $ | 43,441 | ||||||
Total gains or losses (realized/unrealized): | ||||||||||||||
Included in earnings (or changes in net assets) | 2,576 | — | 3,649 | 10,050 | ||||||||||
Impairment included in other comprehensive deficit | — | (144 | ) | — | — | |||||||||
Purchases, issuances, liquidations | — | (200 | ) | — | — | |||||||||
Balance at June 30, 2009 | $ | 8,661 | $ | 29,299 | $ | 111,868 | $ | 53,491 | ||||||
Realized gains and losses included in earnings for the period are reported in other income.
The assets included in the "Long-term investments" column in each of the tables above are auction rate securities. As a result of market conditions, including the failure of auctions for the auction rate securities in which we invested, the fair value of these auction rate securities was determined using an income approach based on a discounted cash flow model. The discounted cash flow model utilized projected cash flows at current rates, which was adjusted for illiquidity premiums based on discussions with market participants. At March 31,June 30, 2010, we held auction rate securities with maturity dates ranging from March 15, 2028 to December 1, 2045.
At December 31, 2009, we had a total temporary impairment of $1,690,000 on our auction rate securities. Based on the fair value of these auction rate securities as of March 31,June 30, 2010, we recorded a reduction to the temporary impairment of approximately $66,000 was recorded as an incremental adjustment to the $1,690,000 temporary impairment that was previously recorded at December 31, 2009.$175,000. The temporary impairment is reflected in "Accumulated other comprehensive deficit" on the condensed unaudited balance sheets. The various assumptions we utilizedutilize to determine the fair value of our auction rate securities investments will vary from period to period based on the prevailing economic conditions. If the market for our auction rate securities investments should deteriorate, we may need to increase the illiquidity premium used in preparing a discounted cash flow model for these securities. A 25 basis point increase in the illiquidity premium used to determine the fair value of these investments at March 31,June 30, 2010, would have resulted in a decrease in the fair value of our auction rate securities investments by approximately $1,452,000.$1,327,000.
These investments were rated either A3 or Aaa by Moody's Investors Service and AAA by Standard and Poor's as of March 31,June 30, 2010. Therefore, it is expected that the investments will not be settled at a price less than par value. Because we have the ability and intent to hold these investments until a recovery ofwe recover our original investment value, we considered the investments to be only temporarily impaired at March 31,June 30, 2010.
credit default swaps which are non-speculative, are utilized to mitigate volatility associated with duration, default, yield curve and the interest rate risks of the portfolio. Consistent with our rate-making treatment, unrealized gains or losses from the decommissioning trust fund are recorded as an increase or decrease to the regulatory asset or liability.
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 March 31,June 30, 2010, the estimated fair value of our natural gas contracts was an unrealized loss of approximately $21,427,000.$14,381,000. See Note B for further discussion on fair value measurements of financial instruments. Consistent with our rate-making for energy costs which are passed through to our members, these unrealized losses are reflected as an unbilled receivable on our balance sheet.
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 manage credit risk with policies and procedures for, among other things, counterparty analysis, exposure measurement, and exposure monitoring and mitigation.
It is possible that volatility in commodity prices could cause us to have credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations, we could suffer a financial loss. However, as of March 31,June 30, 2010, all of the counterparties with transaction amounts outstanding in our hedging portfolio are rated above investment grade by the major rating agencies or have provided a guaranty from one of their affiliates that is rated above investment grade.
We have entered into International Swaps and Derivatives Association Agreements with our natural gas hedge counterparties that mitigate credit exposure by creating contractual rights relating to creditworthiness, collateral, termination and netting (which 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 counterparties' credit standing, including those experiencing financial problems, significant swings in credit default swap rates, credit rating changes by external rating agencies, or changes in ownership. 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 standing and credit ratings from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. We may only post credit support in the form of a letter of credit due to provisions within our Rural Utilities Service Loan Contract; however, we may receive collateral in the form of cash or credit support. As of March 31,June 30, 2010, neither we nor any
counterparties were required to post credit support or collateral under any of these agreements. If the credit-risk-related contingent features underlying these agreements were triggered on March 31,June 30, 2010 due to our credit rating being downgraded below investment grade, we could have been required to post letters of credit totaling up to $21,427,000$14,381,000 with our counterparties.
The following table reflects the volume activity of our natural gas derivatives and derivatives within our nuclear decommissioning trust fund as of March 31,June 30, 2010 that are expected to settle or mature each year:
Year | Natural Gas Swaps | Decommissioning Fund | Natural Gas Swaps | Decommissioning Fund | ||||||||||
2010 | 6.79 | — | 5.39 | $ | 1.60 | |||||||||
2011 | 1.41 | 0.6 | 1.59 | (0.60 | ) | |||||||||
2012 | 0.01 | — | 0.10 | 0.80 | ||||||||||
2013 | — | 1.4 | — | (1.40 | ) | |||||||||
2014 | — | 1.9 | — | (1.92 | ) | |||||||||
2015 | — | 2.2 | — | (2.20 | ) | |||||||||
2016 | — | 0.1 | — | (0.08 | ) | |||||||||
Total | 8.21 | 6.2 | 7.08 | $ | (3.80 | ) | ||||||||
The table below reflects the fair value of derivative instruments and their effect on our condensed unaudited balance sheetssheet for the period ended March 31,June 30, 2010.
Balance Sheet Location | Fair Value | Balance Sheet Location | Fair Value | |||||||||||
(dollars in thousands) | (dollars in thousands) | |||||||||||||
Designated as hedges under authoritative guidance related to derivatives and hedging activities: | Designated as hedges under authoritative guidance related to derivatives and hedging activities: | Designated as hedges under authoritative guidance related to derivatives and hedging activities: | ||||||||||||
Assets | Assets | Assets | ||||||||||||
Natural Gas Swaps | Receivables | $ | 21,427 | Natural Gas Swaps | Receivables | $ | 14,516 | |||||||
Natural Gas Swaps | Receivables | (135 | ) | |||||||||||
Total assets designated as hedges under authoritative guidance related to derivatives and hedging activities | Total assets designated as hedges under authoritative guidance related to derivatives and hedging activities | $ | 21,427 | Total assets designated as hedges under authoritative guidance related to derivatives and hedging activities | $ | 14,381 | ||||||||
Liabilities | Liabilities | Liabilities | ||||||||||||
Natural Gas Swaps | Other current liabilities | $ | 14,516 | |||||||||||
Natural Gas Swaps | Other current liabilities | $ | 21,427 | Natural Gas Swaps | Other current liabilities | (135 | ) | |||||||
Total liabilities designated as hedges under authoritative guidance related to derivatives and hedging activities | Total liabilities designated as hedges under authoritative guidance related to derivatives and hedging activities | $ | 21,427 | Total liabilities designated as hedges under authoritative guidance related to derivatives and hedging activities | $ | 14,381 | ||||||||
Not designated as hedges under authoritative guidance related to derivatives and hedging activities: | Not designated as hedges under authoritative guidance related to derivatives and hedging activities: | Not designated as hedges under authoritative guidance related to derivatives and hedging activities: | ||||||||||||
Assets | Assets | Assets | ||||||||||||
Nuclear decommissioning trust | Decommissioning fund | $ | 9,820 | Nuclear decommissioning trust | Decommissioning fund | $ | 24,601 | |||||||
Nuclear decommissioning trust | Decommissioning fund | (10,255 | ) | Nuclear decommissioning trust | Decommissioning fund | (24,912 | ) | |||||||
Nuclear decommissioning trust | Deferred asset associated with retirement obligations | 9,930 | Nuclear decommissioning trust | Deferred asset associated with retirement obligations | 24,686 | |||||||||
Nuclear decommissioning trust | Deferred asset associated with retirement obligations | (9,855 | ) | Nuclear decommissioning trust | Deferred asset associated with retirement obligations | (24,553 | ) | |||||||
Total not designated as hedges under authoritative guidance related to derivatives and hedging activities | Total not designated as hedges under authoritative guidance related to derivatives and hedging activities | $ | (360 | ) | Total not designated as hedges under authoritative guidance related to derivatives and hedging activities | $ | (178 | ) | ||||||
The following table presents the gains and (losses) on derivative instruments recognized in income for the three and six months ended March 31,June 30, 2010.
Effect of Derivative Instruments on the Condensed Statement of Revenues and Expenses | Effect of Derivative Instruments on the Condensed Statement of Revenues and Expenses | Effect of Derivative Instruments on the Condensed Statement of Revenues and Expenses | |||||||||||||||
Income Statement Location | Three months ended | Income Statement Location | Three months ended | Six months ended | |||||||||||||
(dollars in thousands) | (dollars in thousands) | ||||||||||||||||
Designated as hedges under authoritative guidance related to derivatives and hedging activities | Designated as hedges under authoritative guidance related to derivatives and hedging activities | Designated as hedges under authoritative guidance related to derivatives and hedging activities | |||||||||||||||
|
| $ | (1,247 | ) |
|
| $ | (4,194 | ) | $ | (5,441 | ) | |||||
Not designated as hedges under authoritative guidance related to derivatives and hedging activities | Not designated as hedges under authoritative guidance related to derivatives and hedging activities | Not designated as hedges under authoritative guidance related to derivatives and hedging activities | |||||||||||||||
|
| 461 |
|
| 604 | 1,065 | |||||||||||
|
| (441 | ) |
|
| (608 | ) | (1,049 | ) | ||||||||
Total losses on derivatives | Total losses on derivatives | $ | (1,227 | ) | Total losses on derivatives | $ | (4,198 | ) | $ | (5,425 | ) | ||||||
For those securities considered to be available-for-sale, the following table summarizes the activities for those securities as of June 30, 2010 and December 31, 2009:
(dollars in thousands) | |||||||||||||
Gross Unrealized | |||||||||||||
June 30, 2010 | Cost | Gains | Losses | Fair Value | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Equity | $ | 134,233 | $ | 20,158 | $ | (10,435 | ) | $ | 143,956 | ||||
Debt | 165,840 | 34,872 | (28,121 | ) | 172,591 | ||||||||
Other | 7,043 | 21 | (1 | ) | 7,063 | ||||||||
Total | $ | 307,116 | $ | 55,051 | $ | (38,557 | ) | $ | 323,610 | ||||
Gross Unrealized | |||||||||||||
December 31, 2009 | Cost | Gains | Losses | Fair Value | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Equity | $ | 127,704 | $ | 35,003 | $ | (3,671 | ) | $ | 159,036 | ||||
Debt | 170,033 | 15,685 | (13,089 | ) | 172,629 | ||||||||
Other | (815 | ) | 7 | — | (808 | ) | |||||||
Total | $ | 296,922 | $ | 50,695 | $ | (16,760 | ) | $ | 330,857 | ||||
Effective January 1, 2010, we adopted FASB standard for Accounting for Transfers of Financial Assets—an amendment of Accounting for Transfers for Servicing of Financial Assets and Extinguishments of Liabilities. The standard requires improved disclosures about transfers of financial assets and removes the exception from applying consolidation of variable interest entities to qualifying special purpose entities. The adoption of the standard did not have a material effect on our results of operations, cash flows or financial condition.
Effective January 1, 2010, we adopted FASB standard Amendments to Consolidation of Variable Interest Entities. The standard provides new consolidation guidance for variable interest entities and requires a company to assess the determination of the primary beneficiary of a variable interest entity based on whether the company has the power to direct matters that most significantly impact the activities of the entity, and the obligation to absorb losses or the right to receive benefits of the entity. The standard also requires ongoing reassessments of whether a company is the primary beneficiary of a variable interest entity. The adoption of the standard did not have a material effect on our results of operations, cash flows or financial condition.
In February 2010, the FASB amended its authoritative guidance related to subsequent events to alleviate potential conflicts with current SEC guidance. Effective immediately, these amendments remove the requirement that a SEC filer disclose the date through which it has evaluated subsequent events. The adoption of this guidance did not 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 Deficit | |||||||
Available-for-sale Securities | Total | ||||||
Balance at December 31, 2008 | $ | (1,348 | ) | $ | (1,348 | ) | |
Unrealized gain/(loss) | 175 | 175 | |||||
Balance at March 31, 2009 | $ | (1,173 | ) | $ | (1,173 | ) | |
Balance at December 31, 2009 | $ | (1,253 | ) | $ | (1,253 | ) | |
Unrealized gain/(loss) | 249 | 249 | |||||
Balance at March 31, 2010 | $ | (1,004 | ) | $ | (1,004 | ) | |
| Accumulated Other Comprehensive Deficit Three Months Ended | ||||||
---|---|---|---|---|---|---|---|
Available-for-sale | Total | ||||||
Balance at March 31, 2009 | $ | (1,173 | ) | $ | (1,173 | ) | |
Unrealized loss | (254 | ) | (254 | ) | |||
Balance at June 30, 2009 | $ | (1,427 | ) | $ | (1,427 | ) | |
Balance at March 31, 2010 | $ | (1,004 | ) | $ | (1,004 | ) | |
Unrealized gain | 784 | 784 | |||||
Balance at June 30, 2010 | $ | (220 | ) | $ | (220 | ) | |
| Accumulated Other Comprehensive Deficit Six Months Ended | ||||||
---|---|---|---|---|---|---|---|
Available-for-sale | Total | ||||||
Balance at December 31, 2008 | $ | (1,348 | ) | $ | (1,348 | ) | |
Unrealized loss | (79 | ) | (79 | ) | |||
Balance at June 30, 2009 | $ | (1,427 | ) | $ | (1,427 | ) | |
Balance at December 31, 2009 | $ | (1,253 | ) | $ | (1,253 | ) | |
Unrealized gain | 1,033 | 1,033 | |||||
Balance at June 30, 2010 | $ | (220 | ) | $ | (220 | ) | |
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. We are also subject to federal, state and local waste disposal requirements that regulate the manner of transportation, storage and disposal of various types of waste. In the future, we may become subject to greenhouse gas emission restrictions as a result of regulation aimed at responding to climate change.
In general, environmental requirements are becoming increasingly stringent. New requirements 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. See "ENVIRONMENTAL"BUSINESS—ENVIRONMENTAL AND OTHER REGULATION" in our 2009 Form 10-K for a more detailed discussion of current and potential future regulations. Failure to comply with these 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 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. Should we fail to be in compliance with these requirements, it would constitute a default under such debt instruments. 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.
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 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 or above the minimum requirement contained in our 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 "Item 1A—RISK FACTORS" contained in our Annual Report on Form 10-K for the fiscal year ended December 31, 2009. 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 Six Months Ended March 31,June 30, 2010 and 2009 and 2010
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 the 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 the period of generation facility construction, our board of directors approved a budget for 2010 to achieve a 1.14 margins for interest ratio. As our construction program evolves, our board of directors will continue to evaluate the level of margin coverage and may choose to further increase, or decrease, the margins for interest ratio in the future.
Our net margin for the three-month periodthree- and six-month periods ended March 31,June 30, 2010 was $14.6$7.4 million and $22.0 million compared to $15.6$12.8 million and $28.5 million for the same periodperiods of 2009. We expect aThrough June 30, 2010, we have collected 64% of our expected net margin of approximately $34.3 million for the year ending December 31, 2010, which2010. This is typical as our management generally budgets conservatively and makes adjustments to the budget throughout the year so that net margins will achieve, but not exceed, the targeted margins for interest ratio of 1.14.
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.
Total revenues from sales to members were 7.9%8.5% and 8.2% higher in the three-month periodthree- and six-month periods ended March 31,June 30, 2010 than for the same periodperiods of 2009. Megawatt-hour sales to members increased 4.9%10.7% and 7.9% for the three-month periodthree- and six-month periods ended March 31,June 30, 2010 versus the same periodperiods of 2009. The average total revenue per megawatt-hour from sales to members decreased 2.0% and increased 2.9%0.3% for the three-month periodthree-and six-month periods ended March 31,June 30, 2010 compared to the same periodperiods of 2009.
The components of member revenues for the three-monththree- and six-month period ended March 31,June 30, 2010 and 2009 were as follows (amounts in thousands except for cents per kilowatt-hour):
Three Months Ended March 31, | Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||
2010 | 2009 | 2010 | 2009 | 2010 | 2009 | |||||||||||||||
Capacity revenues | $ | 170,775 | $ | 163,963 | $ | 171,443 | $ | 165,197 | $ | 342,218 | $ | 329,160 | ||||||||
Energy revenues | 133,053 | 117,742 | 154,520 | 135,330 | 287,573 | 253,072 | ||||||||||||||
Total | $ | 303,828 | $ | 281,705 | $ | 325,963 | $ | 300,527 | $ | 629,791 | $ | 582,232 | ||||||||
Kilowatt-hours sold to Members | 5,066,221 | 4,831,378 | ||||||||||||||||||
Kilowatt-hours sold to members | 5,735,490 | 5,181,861 | 10,801,711 | 10,013,239 | ||||||||||||||||
Cents per kilowatt-hour | 6.00¢ | 5.83¢ | 5.68¢ | 5.80¢ | 5.83¢ | 5.81¢ | ||||||||||||||
Capacity revenues for the three-month periodthree- and six-month periods ended March 31,June 30, 2010 increased 4.2%3.8% and 4.0% compared to the same periodperiods of 2009. This increase in capacity revenues partly resulted from higher budgeted fixed operations and maintenance expenses and partly from an increase in the targeted margins for interest ratio to 1.14 in 2010 from 1.12 in 2009. Energy revenues were 13.0%14.2% and 13.6% higher for the three-month periodthree- and six-month periods ended March 31,June 30, 2010 compared to the same periodperiods of 2009. Our average energy revenue per megawatt-hour from sales to members was 7.8%3.2% and 5.3% higher for the three-month periodthree- and six-month periods ended March 31,June 30, 2010 as compared to the same periodperiods of 2009. ThisThe increase in energy revenues was primarily due to the pass-through to our members of higher fuel costs (primarily due to higher coal-fired generation). For a discussion of fuel costs, see "Operating Expenses" below.
Operating Expenses
Operating expenses for the three-month periodthree- and six-month periods ended March 31,June 30, 2010 increased 8.3%11.3% and 9.9% compared to the same periodperiods of 2009. This increase in operating expenses was primarily due to higher fuel costs, higher production expenses and higher depreciation expenses, offset somewhat by a decrease in purchased power costs.
For the three-month periodthree- and six-month periods ended March 31,June 30, 2010, total fuel costs increased 15.3%23.3% and 19.5% and total generation increased 4.6%13.7% and 9.3% compared to the same periodperiods of 2009. Average fuel costs per megawatt-hour increased 10.2%8.4% and 9.3% in the first quarterthree- and six-month periods of 2010 compared to the same periodperiods of 2009. This increase in total fuel costs resulted primarily from higher coal-fired generation at Plant Scherer,Scherer. Additionally, higher nuclear generation at Plant Hatch contributed to the increase in generation during the second quarter of 2010 as compared to same period of 2009. These increases were offset somewhat by lower generation at the natural gas-fired Chattahoochee energy facility. The increase in average fuel costs during the three-month periodthree- and six-month periods ended March 31,June 30, 2010 compared to the same periodperiods of 2009 resulted primarily from a 34.4%28.2% or 841,000 megawatt-hour increase in generation at Plant Scherer primarily due to no scheduled outage in 2010 whereas there was a scheduled outage in 2009. The increase in nuclear generation at Plant Hatch was due to a shorter planned outage in 2010 as compared to the planned outage in 2009. Natural gas-fired
generation at Chattahoochee decreased 42.9%33.9% or 253,000417,000 megawatt-hours for the first quarter ofsix-months ended June 30, 2010 as compared to the same period of 2009 primarily due to a longer planned maintenance outage. The average fuel cost per megawatt-hour of coal-fired generation is substantially higher than that of nuclear generation; thus, the increase in coal-fired generation was the primary contributor to the increase in average fuel costs per megawatt-hour of generation. This increase was offset somewhat by the decrease in average cost of natural gas generation at Chattahoochee.
Production expenses increased 9.4%24.0% and 16.6% for the three-month periodthree- and six-month periods ended March 31,June 30, 2010 compared to the same periodperiods of 2009. This increase is primarilypartly attributable to increased general operations and
maintenance expenses at some of the jointly owned plants (Plants Hatch, Vogtle, Wansley and Wansley)Scherer) during the first quarter of 2010. Additionally,three- and six-month periods ended June 30, 2010 and partly due to operations and maintenance expenses were incurred for the Hawk Road and Hartwell Energy Facilities incurred in the first quarter of 2010; we2010. We acquired these facilities in May and October of 2009, respectively.
Total purchased power costs decreased 30.8%46.5% and 39.8% for the three-month periodthree- and six-month periods ended March 31,June 30, 2010 compared to the same periodperiods of 2009. Purchased megawatt-hours decreased 15.7%61.5% and 45.4% for the three-month periodthree- and six-month periods of 2010 compared to the same periodperiods of 2009. The average cost per megawatt-hour of total purchased power decreased 17.9%increased 39.0% and 10.2% for the three-month periodthree- and six-month periods ended March 31,June 30, 2010 compared to the same periodperiods of 2009.
Purchased power costs were as follows (amounts in thousands except for cents per kilowatt-hour):
Three Months Ended March 31, | Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||
2010 | 2009 | 2010 | 2009 | 2010 | 2009 | |||||||||||||||
Capacity costs | $ | 4,012 | $ | 10,683 | $ | 4,045 | $ | 11,024 | $ | 8,057 | $ | 21,707 | ||||||||
Energy costs | 13,396 | 14,463 | 14,172 | 23,026 | 27,568 | 37,489 | ||||||||||||||
Total | $ | 17,408 | $ | 25,146 | $ | 18,217 | $ | 34,050 | $ | 35,625 | $ | 59,196 | ||||||||
Kilowatt-hours of purchased power | 123,123 | 145,968 | 103,505 | 268,977 | 226,628 | 414,945 | ||||||||||||||
Cents per kilowatt-hour | 14.14¢ | 17.23¢ | 17.60¢ | 12.66¢ | 15.72¢ | 14.27¢ | ||||||||||||||
Purchased power capacity costs decreased 62.4%63.3% and 62.9% in the three-month periodthree- and six-month periods ended March 31,June 30, 2010 compared to the same periodperiods of 2009. Purchased power energy costs for the three-month periodthree- and six-month periods ended March 31,June 30, 2010 decreased 7.4%38.5% and 26.5% compared to the same periodperiods of 2009. The average cost per kilowatt-hour of purchased power energy increased 9.8%60.0% and 34.7% for the three-monththree- and six-month periods ended March 31,June 30, 2010 compared to the same periodperiods of 2009. The decrease in purchased power capacity costs is primarily attributable to the Hartwell acquisition. As part of the acquisition, we acquired an existing power purchase agreement we had in place with the former owners of Hartwell. The decrease in purchased power energy costs resulted from (i) a decrease in megawatt-hours acquired under our energy replacement program, which replaces power from our owned generation facilities with lower price spot market purchased power energy, (ii) lower realized losses incurred for natural gas financial contracts utilized for managing exposure to fluctuations in the market prices of natural gas and (iii) no power purchases under the Hartwell power purchase agreement which was acquired as discussed above.
Depreciation and amortization expense increased 19.8%11.2% and 15.4% in the three-month periodthree- and six-month periods ended March 31,June 30, 2010 as compared to the same periodperiods of 2009. The increase was primarily due to increased depreciation expense for Plants Scherer and Wansley related to capital expenditures for environmental compliance projects. Depreciation expense related to Hawk Road and Hartwell also contributed to the increase.
Other Income
Investment income decreased 12.4% and 5.7% in the three- and six-month periods ended June 30, 2010 compared to the same periods of 2009. A decrease in interest earnings on cash and cash equivalents due to lower market interest rates on those investments and a decrease in net activity in decommissioning trust funds were the primary drivers for the overall decrease. The line item investment income includes activity in the decommissioning trust funds which includes investment income/loss and an adjustment to the regulatory asset or liability for timing difference between accretion expenses recognized under accounting for asset retirement obligations versus the expense recovered for rate-making purposes. These decreases were offset somewhat by increased earnings on the Rural Utilities Service Cushion of Credit Account due to higher balances in this account compared to the same periods of 2009.
Interest charges
Interest on long-term debt and capital leases increased by 14.7%6.3% and 10.4% in the three-month periodthree- and six-month periods ended March 31,June 30, 2010 compared to the same periodperiods of 2009. This increase was primarily due to the issuance in November 2009 of $400 million of taxable fixed rate bonds for the purpose of financing construction of Plant Vogtle Units No. 3 and No. 4.
Allowance for debt funds used during construction increased by 148.7%83.1% and 112.3% in the three-month periodthree- and six-month periods ended March 31,June 30, 2010 compared to the same periodperiods of 2009 primarily due to construction expenditures for Plant Vogtle Units No. 3 and No. 4.
Amortization of debt discount and expense increased 34.6% and 44.1% in the three- and six-month periods ended June 30, 2010 compared to the same periods of 2009 primarily due to amortization of issuance costs associated with transactions that closed in May and August 2009 to provide supplemental credit enhancement for the Rocky Mountain lease arrangements.
Balance Sheet Analysis as of March 31,June 30, 2010
Assets
Nuclear fuel, which is recorded at amortized cost, increased by a net $33.5 million in the three-month period ended March 31, 2010. The increase was due to a combination of factors, including the timing of expenditures, the costs of uranium and fabrication and an increase in the nuclear fuel inventory level.
Cash and cash equivalents decreased by $276.6 million in the three-month period ended March 31, 2010 and can be largely attributed to expenditures of approximately $161.8 million for property additions and a net application of $48.7 million of the members' prepayments of their power bills. Other significant uses of cash include principal and interest payments, investment in restricted short-term investments and payments to Georgia Power Company for operation and maintenance costs.
Cash paid for property additions for the three-monthsix-month period ended March 31,June 30, 2010 totaled $161.8$335.1 million. Of this amount, approximately $69$189 million was for expenditures associated with the construction of new generation facilities, primarily for Plant Vogtle Units No. 3 and No. 4. The remaining expenditures were primarily for environmental control systems being installed at Plant Scherer, normal additions and replacements to existing generation facilities and purchases of nuclear fuel.
Nuclear fuel, which is recorded at amortized cost, increased by a net $24.3 million in the six-month period ended June 30, 2010. The increase was due to a combination of factors, including the timing of expenditures, the costs of uranium and enrichment services and an increase in the nuclear fuel inventory level.
Cash and cash equivalents decreased by $216.1 million in the six-month period ended June 30, 2010 and can be largely attributed to expenditures of approximately $335.1 million for property additions and a net application of $90.4 million of the members' prepayments of their power bills. Other significant uses of cash include principal and interest payments, investment in restricted short-term investments and payments to Georgia Power Company for operation and maintenance costs.
The $8.0 million restricted cash balance at March 31,June 30, 2010 consisted of $133.6 million obtained from a March 2010 bond refinancing and $11.5 millionthe remaining proceeds obtained from the issuance of clean renewable energy bonds in December 2009. The refinancing proceeds which were on deposit with a trustee at March 31,from the clean renewable energy bonds are restricted in use for certain qualifying expenditures. The decrease for the six-month period ended June 30, 2010 were subsequently utilized on April 1, 2010was due in part to redeem the pollution control revenue bonds refinanced in March 2010. During the first quarterexpenditure of 2010,$3.4 million for such qualifying costs. In addition, $10.9 million of restricted cash, the proceeds from a December 2009 bond
refinancing, was utilized to payoff the principal of the refinanced pollution control revenue bonds that matured in January 2010. For information regarding the March 2010 bond refinancing, see Note J of Notes to Unaudited Condensed Financial Statements and see "Financial Condition—Capital Requirements and Liquidity and Sources of Capital—Financings" herein.
Restricted short-term investments at March 31,June 30, 2010 represented funds deposited into a Rural Utilities Service Cushion of Credit Account with the U.S. Treasury that 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 notes and Rural Utilities Service-guaranteed Federal Financing Bank notes. For information regarding the Rural Utilities Service Cushion of Credit Account, see Note HI of Notes to Unaudited Condensed Financial Statements and "Financial Condition—Capital Requirements and Liquidity and Sources of Capital—Liquidity" herein.
Receivables increased by $26.2$45.5 million in the three-monthsix-month period ended March 31,June 30, 2010. The increase was partially due to an $8.9 million increase in the receivable from the members associated with the natural gas derivatives and partially due to an $8.6 million increase in the receivable from Georgia Power. For information regarding the natural gas contracts, see Note C of Notes to Unaudited Condensed Financial Statements. The Georgia Power receivable represents the portion of estimated payments made to it for plant expenditures that exceeded actual amounts incurred. The December 31, 2009 receivables balance included approximately $20.7 million of creditcredits available to the members for a board approved reduction to 2009 revenue requirements as a result of margins collected in excess of our 2009 target 1.12 margins for interest ratio. The increase in receivables was also partiallylargely due to these credits being utilized by the members during the first quarter of 2010. Somewhat offsetting the forgoing was a decrease of approximately $11.4 millionThe receivable for normal monthly amounts billed or billable to the members for their monthly power bills also increased by approximately $16.6 million in MarchJune 2010 as compared to December 2009. This decreaseincrease was primarily due to lowerhigher energy costs in MarchJune 2010, which was a result of decreasedincreased generation. Receivables from Smarr EMC for costs incurred for operation of its facilities also increased by $5.6 million. A $1.9 million increase in the receivable from the members associated with natural gas derivatives also contributed to the overall increase in receivables. For information regarding the natural gas contracts, see Note C of Notes to Unaudited Condensed Financial Statements.
Deferred outage costs increased $14.2$8.7 million (net of amortization) during the first quarter ofsix-month period ended June 30, 2010 as a result of the deferral of approximately $22.3$24.9 million of outage related costs. Plant Hatch Unit No. 1, Plant Vogtle Unit No. 2 and Plant Wansley Unit No. 1 were in refueling and/or major maintenance outages for varying lengths of time during the first quarter of 2010. Deferred outage costs are amortized over each plant's operating cycle.
The $5.4$13.7 million decreaseincrease in the deferred asset associated with retirement obligations in the three-monthsix-month period ended March 31,June 30, 2010 was primarily due to a $3.6an $18.5 million increasedecrease in the unrealized gains associated with the nuclear decommissioning fund. Consistent with our ratemaking policy,
unrealized gains or losses from the nuclear decommissioning fund are deducted from or added to the deferred asset associated with retirement obligations. The increasedecrease in the nuclear decommissioning fund unrealized gains therefore decreasedincreased the deferred asset by $3.6$18.5 million. The deferred asset also increases or decreases to the extent of timing differences between recognized accretion expense associated with nuclear decommissioning and the amounts recovered through decommissioning fund earnings. Nuclear decommissioning accretion expenseand related expenses of approximately $3.9$7.5 million and decommissioning fund net earnings of approximately $5.5$11.9 million resulted in the deferred charge decreasing by $1.6$4.4 million in the three-monthsix-month period ended March 31,June 30, 2010.
Equity and Liabilities
The $127.2 million increase in short-term borrowings was primarily for borrowings to fund construction of Plant Vogtle Units No. 3 and No. 4.
Long-term debt and capital leases due within one year increased by $135.6$27.5 million in the three-month period ended March 31, 2010 as a result of scheduled debt maturities and the $133.6 million refinancing transaction that occurred in March 2010. The principal payments for the refinanced bonds were not made until April 1, 2010 and these balances were therefore classified as current asconsequent reclassification of March 31, 2010. For information regarding the March 2010 bond refinancing, see Note J of Notes to Unaudited Condensed Financial Statements and see "Financial Condition—Capital Requirements and Liquidity and Sources of Capital—Financings" herein.certain long-term debt.
Accounts payable decreased $16.3increased $78.3 million in the three-monthsix-month period ended March 31,June 30, 2010 largelyprimarily due to a $14.2$60.6 million decreaseincrease in the payable to Georgia Power for operation, maintenance and capital costs. At March 31, 2010, there was a net receivable fromThe increase in the payable to Georgia Power is primarily associated with construction costs for Plant Vogtle Units No. 3 and it was recorded accordingly.No. 4. In addition, there was a $7.8$13.7 million decreaseincrease in the payable for natural gas that
gas. This increase was primarily due to a decrease inincreased generation at Chattahoochee, which wasthe natural gas fired plants in a maintenance outage during March 2010. Other purchase power payables also decreased by $2.2 million during the first quarter ofJune 2010 largely due to a decrease in spot market purchases of energy.
The $10.5 million decrease in accrued interest for the three-month period ended March 31, 2010 was primarily due to normal timing differences between interest payments and interest expense accruals.compared with December 2009.
Accrued and withheld taxes decreased $17.3$10.0 million in the three-monthsix-month period ended March 31,June 30, 2010 as a result of payments made (when due) for 2009 property taxes, which exceeded the normal monthly property tax accruals.
Members' advancesMember power bill prepayments represent funds received from the members for prepayment of their monthly power bills. At March 31,June 30, 2010, $117.8$85.8 million of member advancespower bill prepayments was classified as a current liability and $34.0$24.4 million of member advancespower bill prepayments was classified as a long-term deferred liability. During the first quarterhalf of 2010, approximately $31.5$49.9 million of prepayments were received from the members and approximately $80.2$140.3 million was applied to the members' monthly power bills. The cash outflow from operations is primarily attributable to the application of member prepayments received in the prior year to the current year's power bills.bills was a significant contributor to the cash outflow from operations. For information regarding the power bill prepayment program, see Note IJ of Notes to Unaudited Condensed Financial Statements and see "Financial Condition—Capital Requirements and Liquidity and Sources of Capital—Liquidity" herein.
Primarily due to an $8.9 million increase in the liability associated with natural gas derivatives, otherOther current liabilities increaseddecreased by $4.1$3.4 million during the first quarterhalf of 2010. This increase was partially offset by2010, primarily due to a $2.7$3.9 million decrease in accruedaccruals for other miscellaneous payables. Accrued payroll charges also decreased by $1.7 million, which was a result of the payout of 2009 performance pay. AccrualsPartially offsetting this decrease was a $1.9 million increase in the liability associated with natural gas derivatives.
Primarily as a result of incurring approximately $5.4 million of removal costs for miscellaneousthe retirement of certain assets, accumulated retirement costs for other costs alsoobligations decreased by $2.2$4.6 million.
Other deferred credits and liabilities increased $7.3$14.5 million in the three-monthsix-month period ended March 31,June 30, 2010 partially due to a $3.1$6.1 million increase in the regulatory liability established forto defer the deferral ofeffects on net margin that result from Hawk Road Energy Facility margins.operations. Also contributing to the increase was a $2.5$5.0 million increase in funding received from the members for future debt payments related to the Talbot and Chattahoochee Energy Facilities. During the first quarterhalf of 2010, funding for the future overhaul of the combustion turbine plants also increased by $1.5$2.8 million.
Financial Condition
OverviewCapital Requirements and Liquidity and Sources of Capital
Our financial condition remains stable.Future Power Resources
To meet the energy needs of our members, we have embarked on a generation expansion program. In addition to the Hawk Road and Hartwelltwo acquisitions in 2009 (the 500 megawatt Hawk Road Energy Facility and the 300 megawatt Hartwell Energy Facility), members have subscribed to three projects currently under development, including Plant Vogtle Units No. 3 and No. 4 a wood-burning(our 30% share is 660 megawatts), the 100 megawatt Warren County biomass plant and a 605 megawatt gas-fired combined cycle plant. For a further discussion of the new generation projects under development, see "BUSINESS—OUR POWER SUPPLY RESOURCES—Future Power Resources"Resources" in our 2009 Form 10-K.
Capital RequirementsTable of Contents
The projected commercial operation date for the Warren County biomass plant was initially 2014. However, we have extended the projected commercial operation date to 2015 due to uncertainties related to proposed emissions standards for industrial boilers, including those for biomass plants, and Liquiditythe availability of related emissions control technologies. We are also considering the potential impact of uncertainties related to regulatory and Sourceslegislative issues, including whether certain biomass electricity production will (i) qualify under any renewable electricity standard that may be established or (ii) be subject to the U.S. Environmental Protection Agency, or EPA, greenhouse gas regulations. Despite these uncertainties, we continue to move forward with many of Capitalthe activities associated with the biomass plant, including environmental evaluations, air permitting and other governmental approvals and negotiations with boiler and equipment manufacturers. For further discussion of environmental considerations that may affect the design and construction of this plant, see "—Environmental Regulations" below and "BUSINESS—ENVIRONMENTAL AND OTHER REGULATION" in our 2009 Form 10-K.
Environmental Capital Requirements and RegulationsExpenditures
Our futureThe table below details our revised forecast of capital expenditures for 2010 through 2012. As reported in our 2009 Form 10-K, our estimated cost to construct the Warren County biomass plant, which assumed a commercial operation date of 2014, was $477 million, including allowance for funds during construction. Based on the factors discussed above, we anticipate the delay in commercial operation will result in less than a 5% increase in the estimated cost of the biomass plant. However, the delay will shift a significant amount of expenditures beyond 2012, the final year reflected in the capital expenditure table in our 2009 Form 10-K. In addition to reflecting revisions to the Warren County biomass plant expenditure schedule, the table also reflects revised capital expenditures for 2010 through 2012 for Vogtle Units No. 3 and No. 4 and the combined cycle plant; although, the overall budgets for each of these two projects remain largely the same.
Capital Expenditures(1)
(dollars in millions)
| 2010 | 2011 | 2012 | Total | |||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Future Generation(2) | $ | 491 | $ | 553 | $ | 784 | $ | 1,828 | |||||
Existing Generation(3) | 75 | 88 | 95 | 258 | |||||||||
Environmental Compliance(4) | 106 | 182 | 238 | 526 | |||||||||
Nuclear Fuel | 103 | 102 | 113 | 318 | |||||||||
General Plant | 3 | 2 | 2 | 7 | |||||||||
Total | $ | 778 | $ | 927 | $ | 1,232 | $ | 2,937 | |||||
In addition to the amounts reflected in the table above, we expect to spend approximately $3.2 billion by 2017 to complete construction of the future generation facilities currently under development. In addition to the deferral of expenditures past 2012, this figure also increased from the amount reported in our 2009 Form 10-K due to the inclusion of amounts inadvertently omitted. For information about our financing plans for these projects, see "—Financing Activities."
Our capital expenditures relating to environmental compliance depend in part on implementation of new or existing laws, regulations, judicial decisions, and how we and the other co-owners of coal-fired Plants Scherer and Wansley choose to comply with these regulations once finalized. Regulations adopted by the Georgia Environmental Protection Division specify certain environmental control equipment that must be added to Georgia electric generating units by specific dates, including Plants Scherer and Wansley. The last of the Plant Wansley projects was completed and placed in service in July 2009. As describedIn addition to the environmental compliance expenditures listed in "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Capital Requirements" in our 2009 Form 10-K,the table above, we forecastedforecast expenditures of $644approximately $100 million in the period 2010 through 2014 to complete environmental compliancethe projects underway at Plant Scherer. Completion of the projects atScherer by 2014. The Plant Scherer projects will require extended unit outages in 2011, although not during peak energy use periods. As the construction environment, including the changing cost of materials and labor, continues to evolve, the estimated cost to install these retrofits continues to be refined. Large construction projects such as these entail certain risks, as described in "Item 1A—RISK FACTORS" in our 2009 Form 10-K. TheseThe forecasted expenditures are based on information available to us on the date of this Quarterly Report on Form 10-Q; however, there can be no assurance that the cost of compliance with these regulations will not be higher, nor that future regulations will not require additional reductions in emissions or earlier compliance. See Note FG of the Notes to Unaudited Condensed Financial Statements for more information on environmental compliance matters.
Actual expenditures may vary from the estimates because of factors such as changes in business conditions, design changes and rework required by regulatory bodies, delays in obtaining necessary regulatory approvals, construction delays, changing environmental requirements, and changes in cost of capital, equipment, material and labor. Large construction projects such as the future generation and environmental compliance projects entail certain risks, as described in "Item 1A—RISK FACTORS" in our 2009 Form 10-K.
Environmental Regulations
In AprilJune 2010, the U.S. Environmental Protection Agency, or EPA signed a rule establishingproposed several national emission standards for certain greenhouse gases, including carbon dioxide,hazardous air pollutants for new light-duty vehicles.commercial, industrial and institutional boilers, which would tighten emission limits for various pollutants regulated under section 112 of the Clear Air Act. Also in AprilJune 2010, EPA finalizedissued a final rule establishing whentightening its national ambient air quality standard for sulfur dioxide, replacing the annual and 24-hour standards with a pollutant (suchnew, more stringent, 1-hour standard. On August 2, 2010, EPA proposed a new rule, known as a greenhouse gas like carbon dioxide) becomes "subjectthe Transport Rule, to regulation" underreplace the Clean Air Act. In MayAct Interstate Rule (CAIR). Similar to the CAIR, this new Transport Rule would regulate emissions of sulfur dioxide and nitrogen oxides by certain Eastern and Midwestern states, including Georgia, deemed to be contributing significantly to nonattainment of the national ambient air quality standards for fine particulates and ozone. The final rule revising the sulfur dioxide standard will likely be challenged, while the proposed rules could undergo substantial revision prior to finalization (at which time they might be challenged). We cannot predict at this time whether any of these developments will ultimately result in the further regulation of emissions from our existing or Junefuture fossil fuel-fired or biomass-fired power plants, or the effects of 2010, any such regulation, including any resulting capital requirements.
EPA is expected to finalize significance thresholds proposed in October 2009 for greenhouse gas emissions, toalso recently issued three rules that together determine when new or modified stationary sources could trigger new source review. EPA takes the position that these rules will begin the process of regulating emissions of greenhouse gases from both mobile(GHGs) (which include carbon dioxide) become regulated under the Prevention of Significant Deterioration (PSD) and Title V operating permit programs. These rules establish a three-step schedule for application of PSD and Title V to stationary sources. The first two steps of regulation begin January 2, 2011 and July 1, 2011 for larger sources with the trigger dateof GHGs, while a possible third step for regulation of thesesmaller GHG sources to occur no earlier than January 1, 2011. Finally,may begin April 30, 2016. Also, EPA has stated its intention to issue a revised New Source Performance Standard for steam generating units operated by electric utilities (and other industrial and commercial facilities) in 2010. Several of the final rules discussed above are subject to numerous petitions for review, and challenges to the remaining rules may be brought in the near future. We cannot predict at this time whether these developments will ultimately result in the
regulation of greenhouse gasGHG emissions from our existing or future fossil fuel-fired or biomass-fired power plants, or the effects of any such regulation, including capital requirements.
In addition, the possibility of new federal legislation that could lead to regulation of emissions of greenhouse gasesGHGs from stationary sources continues. In June 2009, the House of Representatives passed
the American Clean EnergyLegislation is pending in Congress that includes GHG emissions caps and Security Act of 2009 (H.R. 2454), which would establish, among other things, a cap-and-trade system for greenhouse gas emissions in the U.S. H.R. 2454 also includes a national renewable electricity standard, which would initially apply to two of our members. In the Senate, the Kerry-Lieberman American Power ActHowever, recent developments indicate that has been introduced into Congress and otherwill not be moving forward with climate legislation could produce results similar to H.R. 2454. We cannot predict at this time whether these or other legislative actions will result in the regulation of greenhouse gasthat would include GHG emissions from our power plantscaps or a renewable electricity standard applicable to our members.
On May 4, 2010, EPA proposed new rules for regulating the management and disposal of coal ash from power plants. Two primary options of regulating coal wastes under the Resource Conservation and Recovery Act are proposed: (1) creation of a comprehensive program of federally enforceable requirements under Subtitle C (hazardous) or (2) establishment of performance standards under Subtitle D (non-hazardous). While there are significant differences between the two approaches, in either case a finalized program would likely include increased groundwater monitoring, more stringent siting requirements and closure of existing coal waste management facilities not meeting minimum standards. It is likely that these regulations, if finalized, will impact capital requirements associated with changes in methods of ash disposal utilized at our plants; however, wethis time. We cannot predict, however, whether legislative action will be taken in the extent of the impact at this time.future that would regulate GHG emissions from our existing or future fossil fuel-fired power plants or impose a renewable electricity standard on our members.
Liquidity
At March 31,June 30, 2010, we had $1.029 billion$963 million of unrestricted available liquidity to meet our short-term cash needs and liquidity requirements. This amount included $302$363 million in cash and cash equivalents and $727$600 million of unused and available committed short-term credit arrangements. As discussed above, cash and cash equivalents decreased by approximately $216 million during the six-month period ended June 30, 2010 mainly due to expenditures for property additions and the application of member power bill prepayments to power bills.
Our short-term credit facilities are shown in the table below. We expect to renew these short-term credit facilities, as needed, prior to their respective expiration dates.
Committed Short-Term Credit Facilities
| | Authorized Amount | Available 03/31/2010 | Expiration Date | | Authorized Amount | Available 6/30/2010 | Available 8/13/2010 | Expiration Date | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
(dollars in millions) | (dollars in millions) | ||||||||||||||||||||
Unsecured Facilities: | Unsecured Facilities: | Unsecured Facilities: | |||||||||||||||||||
Commercial Paper Backup Line of Credit | $ | 475 | $ | 191 | (1) | July 2012 | Commercial Paper Backup Line of Credit | $ | 475 | $ | 64 | (1) | $ | 1 | (1) | July 2012 | |||||
CoBank Line of Credit | 50 | 50 | December 2010 | CoBank Line of Credit | 50 | 50 | 34 | December 2010 | |||||||||||||
CFC Line of Credit | 50 | 50 | October 2011 | CFC Line of Credit | 50 | 50 | 50 | October 2011 | |||||||||||||
JPMorgan Chase Line of Credit | 150 | 36 | (2) | December 2012 | JPMorgan Chase Line of Credit | 150 | 36 | (2) | 36 | (2) | December 2012 | ||||||||||
Secured facilities: | Secured facilities: | Secured facilities: | |||||||||||||||||||
CoBank Line of Credit | 150 | 150 | November 2012 | CoBank Line of Credit | 150 | 150 | 150 | November 2012 | |||||||||||||
CFC Line of Credit | 250 | 250 | December 2013 | CFC Line of Credit | 250 | 250 | 250 | December 2013 | |||||||||||||
Total | Total | $ | 1,125 | $ | 727 | Total | $ | 1,125 | $ | 600 | $ | 521 |
We have used or plan to use commercial paper and short-term credit facilities to provide temporary funding for (i) payments related to construction of Plant Vogtle Units No. 3 and No. 4, (ii) acquisitions of Hawk Road and Hartwell, and (iii) initial engineering and design work related to the Warren County biomass facilityplant and our plannedthe combined cycle facility,plant, as well as to provide credit support for
variable rate pollution control revenue bonds. For a discussion of our plans regarding permanent financing of these generation facilities, see "—Financing Activities."
In order to further enhance our liquidity position during the peak years of new generation construction, we currently anticipate a restructuring and related upsizing of certain of our short-term credit facilities,
including the commercial paper backup credit facility, sometime in 2011. The exact timing, size and term of the restructured credit facilities will be influenced by many factors, including the ultimate size of the construction program, the timing of permanent financing for new generation facilities and overall market conditions.
Under the commercial paper program, we are authorized to issue commercial paper in amounts that do not exceed the amount of any committed backup lines of credit in place, thereby providing 100% dedicated backup support for any paper outstanding. We periodically assesses our needs in order to determine the appropriate amount of commercial paper backup to maintain and currently have in place a $475 million committed backup credit facility provided by eight participant banks, with Bank of America serving as administrative agent for this facility.
Along with the lines of credit from CoBank, the National Rural Utilities Cooperative Finance Corporation (CFC) and JPMorgan Chase Bank, funds may also be advanced under the backup line of credit supporting commercial paper for general working capital purposes. In addition, under certain of our committed credit facilities we have the ability to issue letters of credit totaling $450 million in the aggregate, of which $336 million remains available.remained available at June 30, 2010. However, any amounts related to issued letters of credit will reduce the amount available to draw as working capital under those facilities. Also, due to the requirement to have 100% dedicated backup for any commercial paper outstanding, any amounts drawn under the commercial paper backup line for working capital or related to issued letters of credit will reduce the amount of commercial paper that we can issue.
Under the $250 million line of credit with CFC, we have the option of converting any amounts outstanding under the line of credit to a term loan with a maturity no later than December 31, 2043. Any amounts drawn under the $250 million CFC line of credit, as well as any amounts converted to a term loan, will be secured under our indenture.
Several of our line of credit facilities contain a similar financial covenant that requires us to maintain minimum levels of patronage capital. At March 31,June 30, 2010, the required minimum level was $545 million and our actual patronage capital was $577$584 million. An additional covenant contained in several of our credit facilities limits our secured indebtedness to $8.5 billion and our unsecured indebtedness to $4.0 billion. At March 31,June 30, 2010, we had approximately $4.6$4.5 billion of secured indebtedness outstanding and $435$521 million of unsecured indebtedness outstanding.
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 advancesprepayments are credited against the participating members' monthly power bills. The discount is comparable to our avoided cost of borrowing. As of March 31,June 30, 2010, the balance of member advancesprepayments received but not yet credited to their power bills was $152$110 million, which represented advancesprepayments from fifteensixteen members participating in the program. We began applying the advancesprepayments against participating members' power bills in 2009 and expect towill continue doing so through September 2013,May 2015, with the majority scheduled to be applied in 2010. For more information regarding the power bill prepayment program, see Note IJ of Notes to Unaudited Condensed Financial Statements.
At March 31,June 30, 2010, we had $121current assets included $123 million of restricted short-term investments pursuant to deposits made to a Rural Utilities Service Cushion of Credit Account. The deposits with the U.S. Treasury were made voluntarily and earn interest at a guaranteed rate of 5% per annum. The funds in the account, including interest thereon, can only be applied to debt service payments on Rural Utilities Service notes and Rural Utilities Service-guaranteed Federal Financing Bank notes. We intendThe amount on deposit in this account is less than one year's debt service payments owed to apply all of the funds in the account against Rural Utilities Service and Federal Financing Bank debt service payments due in 2010.Bank. Our decisions regarding how to apply the funds are guided by the interest rate environment and our anticipated liquidity needs.
Financing Activities
Bond Financings. On March 30, 2010, the Development Authority of Burke County (Georgia) and the Development Authority of Monroe County (Georgia) issued, on our behalf, $133.6 million in aggregate principal amount of tax-exempt pollution control revenue bonds for the purpose of refunding certain pollution control revenue bonds previously issued by the development authorities on our behalf to finance or refinance the costs of our undivided interests in certain air or water pollution control and sewage or solid waste disposal facilities. The bonds were issued as variable rate demand bonds backed by an irrevocable direct-pay letter of credit for each series of bonds issued by Bank of America. The bonds are secured under our indenture.
In the fourth quarter of 2010, we anticipate issuing approximately $400 million of taxable first mortgage bonds for the purpose of funding a portion of the cost of constructing Plant Vogtle Units No. 3 and No. 4. A portion of the proceeds will be used to repay outstanding short-term borrowings in connection with payments previously made for construction of this facility. The first mortgage bonds will be secured under our indenture.
We also anticipate a tax-exempt issuance of pollution control revenue bonds in the fourth quarter of 2010 in the amount of approximately $12 million in connection with the refinancing of a like amount of outstanding pollution control revenue bond principalbonds that isare scheduled to mature on January 1, 2011. This tax-exempt issuance may be increased to include a modest amount of new tax-exempt debt related to pollution control equipment being installed at Plant Scherer, but the timing and exact amount of this new debt, if any, is uncertain at this time. We expect that this tax-exempt debt will be secured under our indenture.
Rural Utilities Service-Guaranteed Loans. We currently have three approvedtwo Rural Utilities Service-guaranteed loans, funded through the Federal Financing Bank, totaling $844$534 million that are in various stagesthe process of being drawn down, with $683$284 million remaining to be advanced. We have one general and environmental improvements loan for approximately $310 million that was approved in July 2009 that is expected to close in the third quarter of 2010. We also have threefive loan applications, totaling approximately $1.72 billion, pending with the Rural Utilities Service, that we anticipate action on in 2010 or 2011, including two applications related to the Hawk Road and Hartwell acquisitions (action anticipated in the third quarter of 2010) and, a loan application related to the Warren County biomass facilityplant (action anticipated in 2011), a loan application related to general improvements at existing generation facilities (action anticipated later in 2010 or in 2011) and a loan application related to the gas-fired combined cycle plant (action not anticipated prior to 2012).
The However, the President's budget proposal for fiscal year 2011 (which begins October 1, 2010) would prohibit Rural Utilities Service funding for 1)(i) improvements to existing fossil-fueled generation facilities unless the improvements are related to carbon-capture projects, and 2)(ii) construction of new fossil-fueled generation facilities. Nonetheless, in the third quarter of 2010 we anticipate submitting to the Rural Utilities Service a $128 million loan application related to general improvements at our existing generation facilities, including improvements at our fossil-fueled generation facilities, and another $750 million loan application related to our planned natural gas-fired combined cycle facility. Further, should members subscribe to any additional natural-gas firedgas-fired combined cycle or combustion turbine facilities, we anticipate filing loan applications for those facilities as well, to the extent Rural Utilities Service regulations in place at that time allow us to do so. See "BUSINESS—OGLETHORPE POWER CORPORATION—Relationship with the Rural Utilities Service" in our 2009 Form 10-K for a more detailed discussion of the Rural Utilities Service's current position relating to funding of new generation facilities.
All of the approved Rural Utilities Service loans will be funded through the Federal Financing Bank and guaranteed by the Rural Utilities Service, and the debt will be secured under theour indenture.
Department of Energy-Guaranteed Loans. We have 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 approximately 70% of the estimated $4.2 billion cost to construct our 30% undivided share in two new nuclear units proposed at Plant Vogtle, not to exceed $3.057 billion. The loan structure would entail a loan funded through the Federal Financing Bank carrying a federal loan guarantee provided by the Department of Energy, with the debt secured under our indenture.
We are working with the Department of Energy to finalize the loan guarantee. However, final approval and issuance of a loan guarantee by the Department of Energy is subject to receipt of the combined
construction permits and operating licenses for Plant Vogtle Units No. 3 and No. 4 from the Nuclear Regulatory Commission, negotiation of definitive agreements, completion of due diligence by the Department of Energy and satisfaction of other conditions. Therefore, there can be no assurance that the Department of Energy will ultimately issue the loan guarantee to us.
For any Plant Vogtle project costs not funded by the Department of Energy, we plan to issue taxable bonds and tax-exempt bonds for any equipment that may qualify for tax-exempt financing. Of the $1.2 billion of estimated project costs that are not expected to be financed by the Department of Energy, if the Department of Energy issues the loan guarantee to us, we have already financed $400 million through the issuance of taxable first mortgage bonds in November 2009, and we have plans to issue an additional approximately $400 million of taxable first mortgage bonds for this purpose in the fourth quarter of 2010.
For more detailed information regarding our financing plans, see "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Financing Activities" in our 2009 Form 10-K.
Our Indenture
In May 2010, we became the direct owner of the Hawk Road Energy Facility and the Hartwell Energy Facility, which were formerly held by two of our wholly owned subsidiaries. These facilities are now included in the mortgaged property and therefore subject to the lien of our indenture. For further discussion, see "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Financing Activities—Our Indenture" in our 2009 Form 10-K.
Newly Adopted or Issued Accounting Standards
For a discussion of "Fair Value Measurements and Disclosures," "Accounting for Transfers of Financial Assets—an amendment of Accounting for Transfers for Servicing of Financial Assets and Extinguishments of Liabilities", "Amendments to Consolidation of Variable Interest Entities," and "Subsequent Events—Amendments to Certain Recognition and Disclosure Requirements"Disclosures" see Note DE of Notes to Unaudited Condensed Financial Statements herein.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Our market risks have not changed materially from the risks reported in our 2009 Form 10-K.
Item 4. Controls and Procedures
As of March 31,June 30, 2010, 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 our internal control over financial reporting or other factors that occurred during the quarter ended March 31,June 30, 2010 that have materially affected, or are reasonably likely to affect, our internal control over financial reporting.
We are a party to various actions and proceedings incidental to our normal business. Liability in the event of final adverse determination in any of these 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 or results of operations.
There have not been any material changes in our risk factors from those reported in "Item 1A-RISK1A—RISK FACTORS" of our Annual Report on Form 10-K for the fiscal year ended December 31, 2009.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Not Applicable.
Item 3. Defaults upon Senior Securities
Not Applicable.
Not Applicable.
Number | Description | ||
---|---|---|---|
3.1 | Bylaws of Oglethorpe, as amended and restated, as of May 1, 2008 (updated on May 1, 2010 to reflect SMG membership change). | ||
4.1 | Fifty-Third Supplemental Indenture, dated as of March 1, 2010, made by Oglethorpe to U.S. Bank National Association, as trustee, relating to the Series 2010A (Burke) Note, Series 2010B (Burke) Note and Series 2010A (Monroe) Note. | ||
10.1 | (1) | Amendment No. 2, dated as of January 15, 2010, to the Engineering, Procurement and Construction Agreement, dated as of April 8, 2008, between Georgia Power, for itself and as agent for Oglethorpe, Municipal Electric Authority of Georgia, and Dalton Utilities, as owners, and a consortium consisting of Westinghouse and Stone & Webster, as contractor, for Units 3 & 4 at the Vogtle Electric Generating Plant Site. (Incorporated by reference to Exhibit 10(c)(1) of Georgia Power Company's Form 10-Q for the quarterly period ended March 31, 2010, filed with the SEC on May 7, 2010.) | |
10.2 | (1) | Amendment No. 3, dated as of February 23, 2010, to the Engineering, Procurement and Construction Agreement, dated as of April 8, 2008, between Georgia Power, for itself and as agent for Oglethorpe, Municipal Electric Authority of Georgia, and Dalton Utilities, as owners, and a consortium consisting of Westinghouse and Stone & Webster, as contractor, for Units 3 & 4 at the Vogtle Electric Generating Plant Site. (Incorporated by reference to Exhibit 10(c)(2) of Georgia Power Company's Form 10-Q for the quarterly period ended March 31, 2010, filed with the SEC on May 7, 2010.) | |
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). | ||
99.1 | Member Financial and Statistical Information (for calendar years 2007-2009). |
Number | Description | ||
4.1 | Fifty-Fourth Supplemental Indenture, dated as of May 21, 2010, made by Oglethorpe to U.S. Bank National Association, as trustee, confirming the lien of the Indenture with respect to certain After-Acquired Property (relating to the Hawk Road and Hartwell Energy Facilities). | ||
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). |
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 | ||
Date: | /s/ Elizabeth B. Higgins Elizabeth B. Higgins Executive Vice President and Chief Financial Officer (Principal Financial Officer) |