Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | |
Dec. 31, 2015 | Jun. 30, 2015 | |
Document and Entity Information | ||
Entity Registrant Name | OGLETHORPE POWER CORP | |
Entity Central Index Key | 788,816 | |
Document Type | 10-K | |
Document Period End Date | Dec. 31, 2015 | |
Amendment Flag | false | |
Current Fiscal Year End Date | --12-31 | |
Entity Well-known Seasoned Issuer | No | |
Entity Voluntary Filers | No | |
Entity Current Reporting Status | Yes | |
Entity Filer Category | Non-accelerated Filer | |
Entity Public Float | $ 0 | |
Entity Common Stock, Shares Outstanding | 0 | |
Document Fiscal Year Focus | 2,015 | |
Document Fiscal Period Focus | FY |
CONSOLIDATED STATEMENTS OF REVE
CONSOLIDATED STATEMENTS OF REVENUES AND EXPENSES - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Operating revenues: | |||
Sales to Members | $ 1,219,052 | $ 1,314,869 | $ 1,166,618 |
Sales to non-Members | 130,773 | 93,294 | 78,758 |
Total operating revenues | 1,349,825 | 1,408,163 | 1,245,376 |
Operating expenses: | |||
Fuel | 441,738 | 515,729 | 442,425 |
Production | 457,264 | 428,801 | 369,730 |
Depreciation and amortization | 168,920 | 166,247 | 158,375 |
Purchased power | 56,925 | 71,799 | 56,084 |
Accretion | 26,108 | 24,616 | 22,900 |
Deferral of Hawk Road and Smith Energy Facilities effect on net margin | (58,588) | (58,426) | (35,662) |
Total operating expenses | 1,092,367 | 1,148,766 | 1,013,852 |
Operating margin | 257,458 | 259,397 | 231,524 |
Other income: | |||
Investment income | 40,424 | 36,791 | 33,558 |
Amortization of deferred gains | 1,788 | 1,788 | 1,788 |
Allowance for equity funds used during construction | 675 | 1,172 | 2,397 |
Other | 9,143 | 6,620 | 5,690 |
Total other income | 52,030 | 46,371 | 43,433 |
Interest charges: | |||
Interest expense | 354,269 | 344,561 | 313,491 |
Allowance for debt funds used during construction | (108,667) | (102,081) | (95,886) |
Amortization of debt discount and expense | 15,545 | 16,653 | 15,872 |
Net interest charges | 261,147 | 259,133 | 233,477 |
Net margin | $ 48,341 | $ 46,635 | $ 41,480 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Margin - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Consolidated Statements of Comprehensive Margin | |||||||||||
Net Margin | $ 6,212 | $ 15,908 | $ 10,852 | $ 15,369 | $ (4,237) | $ 14,453 | $ 17,196 | $ 19,223 | $ 48,341 | $ 46,635 | $ 41,480 |
Other comprehensive margin: | |||||||||||
Unrealized (loss) gain on available-for-sale securities | (410) | 1,017 | (1,452) | ||||||||
Total comprehensive margin | $ 47,931 | $ 47,652 | $ 40,028 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Electric plant: | ||
In service | $ 8,596,148 | $ 8,345,241 |
Less: Accumulated provision for depreciation | (3,925,838) | (3,762,690) |
Total in service | 4,670,310 | 4,582,551 |
Nuclear fuel, at amortized cost | 373,145 | 369,529 |
Construction work in progress | 2,868,669 | 2,374,392 |
Total electric plant | 7,912,124 | 7,326,472 |
Investments and funds: | ||
Nuclear decommissioning trust fund | 363,829 | 366,004 |
Investment in associated companies | 72,010 | 67,368 |
Long-term investments | 86,771 | 85,728 |
Restricted cash and investments | 134,690 | 118,390 |
Other | 19,097 | 17,397 |
Total investments and funds | 676,397 | 654,887 |
Current assets: | ||
Cash and cash equivalents | 213,038 | 237,391 |
Restricted short-term investments | 253,204 | 247,057 |
Receivables | 130,464 | 130,366 |
Inventories, at average cost | 299,252 | 270,849 |
Prepayments and other current assets | 16,913 | 12,667 |
Total current assets | 912,871 | 898,330 |
Deferred charges and other assets: | ||
Regulatory assets | 530,254 | 484,049 |
Prepayments to Georgia Power Company | 17,801 | 73,725 |
Other | 10,336 | 11,357 |
Total deferred charges | 558,391 | 569,131 |
Total assets | 10,059,783 | 9,448,820 |
Capitalization: | ||
Patronage capital and membership fees | 809,465 | 761,124 |
Accumulated other comprehensive margin | 58 | 468 |
Total patronage capital and membership fees and accumulated other comprehensive margin | 809,523 | 761,592 |
Long-term debt | 7,291,154 | 7,015,577 |
Obligations under capital leases | 96,501 | 100,456 |
Other | 17,561 | 16,434 |
Total capitalization | 8,214,739 | 7,894,059 |
Current liabilities: | ||
Long-term debt and capital leases due within one year | 189,840 | 160,754 |
Short-term borrowings | 261,478 | 234,369 |
Accounts payable | 157,432 | 98,337 |
Accrued interest | 58,830 | 58,841 |
Members power bill prepayments, current | 174,743 | 166,013 |
Other current liabilities | 86,746 | 70,748 |
Total current liabilities | 929,069 | 789,062 |
Deferred credits and other liabilities: | ||
Asset retirement obligations | 602,230 | 432,260 |
Member power bill prepayments, non-current | 44,205 | 31,941 |
Contract retainage | 66,515 | 55,015 |
Power sale agreement, being amortized | 12,669 | |
Regulatory liabilities | 166,967 | 194,073 |
Other | 36,058 | 39,741 |
Total deferred credits and other liabilities | 915,975 | 765,699 |
Total equity and liabilities | $ 10,059,783 | $ 9,448,820 |
Commitments and Contingencies (Notes 1, 7, 10, 11, 12 and 13) |
CONSOLIDATED STATEMENTS OF CAPI
CONSOLIDATED STATEMENTS OF CAPITALIZATION - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Secured Long-term debt: | ||
Total Secured Long-term, net | $ 7,575,027 | $ 7,256,995 |
Obligations under capital leases | 100,456 | 121,731 |
Obligation under Rocky Mountain transactions | 17,561 | 16,434 |
Patronage capital and membership fees | 809,465 | 761,124 |
Accumulated other comprehensive margin | 58 | 468 |
Subtotal | 8,502,567 | 8,156,752 |
Less: long-term debt and capital leases due within one year | (189,840) | (160,754) |
Less: unamortized debt issuance costs | (93,651) | (97,423) |
Less: unamortized bond discounts on long-term debt | (4,337) | (4,516) |
Total capitalization | 8,214,739 | 7,894,059 |
Federal Financing Bank | First mortgage notes payable to the Federal Financing Bank at interest rates varying from 2.20% to 8.43% (average rate of 4.19% at December 31, 2015) due in quarterly installments through 2043 | ||
Secured Long-term debt: | ||
Debt Instrument Principal Outstanding | 2,596,912 | 2,582,346 |
Federal Financing Bank | First mortgage notes payable to the Federal Financing Bank at interest rates varying from 2.98% to 3.87% (average rate of 3.60% at December 31, 2015) due in quarterly installments through February 2044 | ||
Secured Long-term debt: | ||
Debt Instrument Principal Outstanding | 1,180,628 | 874,607 |
National Rural Utilities Cooperative Finance Corporation | First mortgage notes payable to National Rural Utilities Cooperative Finance Corporation at interest rates varying from 4.10% to 4.90% (average rate of 4.49% at December 31, 2015) due in quarterly installments through 2020 | ||
Secured Long-term debt: | ||
Debt Instrument Principal Outstanding | 4,238 | 5,085 |
Public | First mortgage bonds payable: Series 2006 First Mortgage Bonds, 5.534%, due 2031 through 2035 | ||
Secured Long-term debt: | ||
Debt Instrument Principal Outstanding | 300,000 | 300,000 |
Public | First mortgage bonds payable: Series 2007 First Mortgage Bonds, 6.191%, due 2024 through 2031 | ||
Secured Long-term debt: | ||
Debt Instrument Principal Outstanding | 500,000 | 500,000 |
Public | First mortgage bonds payable: Series 2009A First Mortgage Bonds, 6.10%, due 2019 | ||
Secured Long-term debt: | ||
Debt Instrument Principal Outstanding | 350,000 | 350,000 |
Public | First mortgage bonds payable: Series 2009B First Mortgage Bonds, 5.95%, due 2039 | ||
Secured Long-term debt: | ||
Debt Instrument Principal Outstanding | 400,000 | 400,000 |
Public | First mortgage bonds payable: Series 2009 Clean renewable energy bond, 1.81%, due 2024 | ||
Secured Long-term debt: | ||
Debt Instrument Principal Outstanding | 9,093 | 10,103 |
Public | First mortgage bonds payable: Series 2010A First Mortgage Bonds, 5.375% due 2040 | ||
Secured Long-term debt: | ||
Debt Instrument Principal Outstanding | 450,000 | 450,000 |
Public | First mortgage bonds payable: Series 2011A First Mortgage Bonds, 5.25% due 2050 | ||
Secured Long-term debt: | ||
Debt Instrument Principal Outstanding | 300,000 | 300,000 |
Public | First mortgage bonds payable: Series 2012A First Mortgage Bonds, 4.20% due 2042 | ||
Secured Long-term debt: | ||
Debt Instrument Principal Outstanding | 250,000 | 250,000 |
Public | First mortgage bonds payable: Series 2014A First Mortgage Bonds, 4.55% due 2044 | ||
Secured Long-term debt: | ||
Debt Instrument Principal Outstanding | 250,000 | 250,000 |
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2003A Burke, Heard, Monroe and 2003B Burke Auction rate bonds, 0.75%, due 2024 | ||
Secured Long-term debt: | ||
Debt Instrument Principal Outstanding | 95,230 | 95,230 |
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2004 Burke and Monroe Auction rate bonds, 0.53%, due 2020 | ||
Secured Long-term debt: | ||
Debt Instrument Principal Outstanding | 11,525 | 11,525 |
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2005 Burke and Monroe Auction rate bonds, 0.64%, due 2040 | ||
Secured Long-term debt: | ||
Debt Instrument Principal Outstanding | 15,865 | 15,865 |
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2008A through 2008C Burke Fixed rate bonds, 5.30% to 5.70%, due 2032 through 2043 | ||
Secured Long-term debt: | ||
Debt Instrument Principal Outstanding | 255,035 | 255,035 |
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2008E Burke Fixed rate bonds, 7.00%, due 2020 through 2023 | ||
Secured Long-term debt: | ||
Debt Instrument Principal Outstanding | 144,750 | 144,750 |
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2009A Heard and Monroe, and 2009B Monroe Weekly rate bonds, 0.01%, due 2030 through 2038 | ||
Secured Long-term debt: | ||
Debt Instrument Principal Outstanding | 112,055 | 112,055 |
Georgia Development Authorities | First mortgage notes issued Series 2010A Burke and Monroe, and 2010B Burke Weekly rate bonds, 0.01%, due 2036 through 2037 | ||
Secured Long-term debt: | ||
Debt Instrument Principal Outstanding | 133,550 | 133,550 |
Georgia Development Authorities | First mortgage notes issued Series 2013A Appling, Burke and Monroe Term rate bonds, 2.40% through April 1, 2020, due 2038 through 2040 | ||
Secured Long-term debt: | ||
Debt Instrument Principal Outstanding | 212,760 | 212,760 |
CoBank | ACB notes payable: Transmission first mortgage notes payable: variable at 2.30% to 3.25% through January 29, 2016, due in bimonthly installments through November 1, 2018 | ||
Secured Long-term debt: | ||
Debt Instrument Principal Outstanding | 595 | 751 |
CoBank | ACB notes payable: Transmission first mortgage notes payable: variable at 2.30% to 3.25% through January 29, 2016, due in bimonthly installments through September 1, 2019 | ||
Secured Long-term debt: | ||
Debt Instrument Principal Outstanding | $ 2,791 | $ 3,333 |
CONSOLIDATED STATEMENTS OF CAP6
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Parenthetical) | Dec. 31, 2015 | Dec. 31, 2014 |
National Rural Utilities Cooperative Finance Corporation | First mortgage notes payable to National Rural Utilities Cooperative Finance Corporation at interest rates varying from 4.10% to 4.90% (average rate of 4.49% at December 31, 2015) due in quarterly installments through 2020 | ||
Secured Long-term debt: | ||
Debt Instrument, Interest Rate Minimum (as a percent) | 4.10% | 4.10% |
Debt Instrument, Interest Rate Maximum (as a percent) | 4.90% | 4.90% |
Debt Instrument, Interest Rate Average (as a percent) | 4.49% | |
Public | First mortgage bonds payable: Series 2006 First Mortgage Bonds, 5.534%, due 2031 through 2035 | ||
Secured Long-term debt: | ||
Debt Instrument, Interest Rate, Stated Percentage (as a percent) | 5.534% | 5.534% |
Public | First mortgage bonds payable: Series 2007 First Mortgage Bonds, 6.191%, due 2024 through 2031 | ||
Secured Long-term debt: | ||
Debt Instrument, Interest Rate, Stated Percentage (as a percent) | 6.191% | 6.191% |
Public | First mortgage bonds payable: Series 2009A First Mortgage Bonds, 6.10%, due 2019 | ||
Secured Long-term debt: | ||
Debt Instrument, Interest Rate, Stated Percentage (as a percent) | 6.10% | 6.10% |
Public | First mortgage bonds payable: Series 2009B First Mortgage Bonds, 5.95%, due 2039 | ||
Secured Long-term debt: | ||
Debt Instrument, Interest Rate, Stated Percentage (as a percent) | 5.95% | 5.95% |
Public | First mortgage bonds payable: Series 2009 Clean renewable energy bond, 1.81%, due 2024 | ||
Secured Long-term debt: | ||
Debt Instrument, Interest Rate, Stated Percentage (as a percent) | 1.81% | 1.81% |
Public | First mortgage bonds payable: Series 2010A First Mortgage Bonds, 5.375% due 2040 | ||
Secured Long-term debt: | ||
Debt Instrument, Interest Rate, Stated Percentage (as a percent) | 5.375% | 5.375% |
Public | First mortgage bonds payable: Series 2011A First Mortgage Bonds, 5.25% due 2050 | ||
Secured Long-term debt: | ||
Debt Instrument, Interest Rate, Stated Percentage (as a percent) | 5.25% | 5.25% |
Public | First mortgage bonds payable: Series 2012A First Mortgage Bonds, 4.20% due 2042 | ||
Secured Long-term debt: | ||
Debt Instrument, Interest Rate, Stated Percentage (as a percent) | 4.20% | 4.20% |
Public | First mortgage bonds payable: Series 2014A First Mortgage Bonds, 4.55% due 2044 | ||
Secured Long-term debt: | ||
Debt Instrument, Interest Rate, Stated Percentage (as a percent) | 4.55% | 4.55% |
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2003A Burke, Heard, Monroe and 2003B Burke Auction rate bonds, 0.75%, due 2024 | ||
Secured Long-term debt: | ||
Debt Instrument, Interest Rate, Stated Percentage (as a percent) | 0.75% | 0.75% |
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2004 Burke and Monroe Auction rate bonds, 0.53%, due 2020 | ||
Secured Long-term debt: | ||
Debt Instrument, Interest Rate, Stated Percentage (as a percent) | 0.53% | 0.53% |
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2005 Burke and Monroe Auction rate bonds, 0.64%, due 2040 | ||
Secured Long-term debt: | ||
Debt Instrument, Interest Rate, Stated Percentage (as a percent) | 0.64% | 0.64% |
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2008A through 2008C Burke Fixed rate bonds, 5.30% to 5.70%, due 2032 through 2043 | ||
Secured Long-term debt: | ||
Debt Instrument, Interest Rate Minimum (as a percent) | 5.30% | 5.30% |
Debt Instrument, Interest Rate Maximum (as a percent) | 5.70% | 5.70% |
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2008E Burke Fixed rate bonds, 7.00%, due 2020 through 2023 | ||
Secured Long-term debt: | ||
Debt Instrument, Interest Rate, Stated Percentage (as a percent) | 7.00% | 7.00% |
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2009A Heard and Monroe, and 2009B Monroe Weekly rate bonds, 0.01%, due 2030 through 2038 | ||
Secured Long-term debt: | ||
Debt Instrument, Interest Rate, Stated Percentage (as a percent) | 0.01% | 0.01% |
Georgia Development Authorities | First mortgage notes issued Series 2010A Burke and Monroe, and 2010B Burke Weekly rate bonds, 0.01%, due 2036 through 2037 | ||
Secured Long-term debt: | ||
Debt Instrument, Interest Rate, Stated Percentage (as a percent) | 0.01% | 0.01% |
Georgia Development Authorities | First mortgage notes issued Series 2013A Appling, Burke and Monroe Term rate bonds, 2.40% through April 1, 2020, due 2038 through 2040 | ||
Secured Long-term debt: | ||
Debt Instrument, Interest Rate, Stated Percentage (as a percent) | 2.40% | 2.40% |
CoBank | ACB notes payable: Transmission first mortgage notes payable: variable at 2.30% to 3.25% through January 29, 2016, due in bimonthly installments through November 1, 2018 | ||
Secured Long-term debt: | ||
Debt Instrument, Interest Rate Minimum (as a percent) | 2.30% | 2.30% |
Debt Instrument, Interest Rate Maximum (as a percent) | 3.25% | 3.25% |
CoBank | ACB notes payable: Transmission first mortgage notes payable: variable at 2.30% to 3.25% through January 29, 2016, due in bimonthly installments through September 1, 2019 | ||
Secured Long-term debt: | ||
Debt Instrument, Interest Rate Minimum (as a percent) | 2.30% | 2.30% |
Debt Instrument, Interest Rate Maximum (as a percent) | 3.25% | 3.25% |
Federal Financing Bank | First mortgage notes payable to the Federal Financing Bank at interest rates varying from 2.20% to 8.43% (average rate of 4.19% at December 31, 2015) due in quarterly installments through 2043 | ||
Secured Long-term debt: | ||
Debt Instrument, Interest Rate Minimum (as a percent) | 2.20% | 2.20% |
Debt Instrument, Interest Rate Maximum (as a percent) | 8.43% | 8.43% |
Debt Instrument, Interest Rate Average (as a percent) | 4.19% | |
Federal Financing Bank | First mortgage notes payable to the Federal Financing Bank at interest rates varying from 2.98% to 3.87% (average rate of 3.60% at December 31, 2015) due in quarterly installments through February 2044 | ||
Secured Long-term debt: | ||
Debt Instrument, Interest Rate Minimum (as a percent) | 2.98% | 2.98% |
Debt Instrument, Interest Rate Maximum (as a percent) | 3.87% | 3.87% |
Debt Instrument, Interest Rate Average (as a percent) | 3.60% |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Cash flows from operating activities: | |||
Net margin | $ 48,341 | $ 46,635 | $ 41,480 |
Adjustments to reconcile net margin to net cash provided by operating activities: | |||
Depreciation and amortization, including nuclear fuel | 313,320 | 313,449 | 296,546 |
Accretion cost | 26,108 | 24,616 | 22,900 |
Amortization of deferred gains | (1,788) | (1,788) | (1,788) |
Allowance for equity funds used during construction | (675) | (1,172) | (2,397) |
Deferred outage costs | (40,803) | (53,823) | (43,302) |
Deferral of Hawk Road and Smith Energy Facilities effect on net margin | (58,588) | (58,426) | (35,662) |
Gain on sale of investments | (34,464) | (18,179) | (24,962) |
Regulatory deferral of costs associated with nuclear decommissioning | 21,532 | 4,564 | 10,181 |
Other | (8,353) | (8,835) | (8,718) |
Change in operating assets and liabilities: | |||
Receivables | (98) | (1,000) | 4,743 |
Inventories | (28,403) | 15,319 | (22,219) |
Prepayments and other current assets | (4,317) | 3,197 | 191 |
Accounts payable | (37,155) | (22,488) | (32,665) |
Accrued interest | (11) | 648 | (456) |
Accrued and withheld taxes | 3,731 | (4,198) | 17,996 |
Other current liabilities | 2,805 | 8,956 | 318 |
Member power bill prepayments | 20,994 | 83,236 | 8,787 |
Total adjustments | 173,835 | 284,076 | 189,493 |
Net cash provided by operating activities | 222,176 | 330,711 | 230,973 |
Cash flows from investing activities: | |||
Property additions | (495,426) | (534,171) | (628,216) |
Activity in nuclear decommissioning trust fund - Purchases | (558,568) | (389,854) | (568,979) |
Activity in nuclear decommissioning trust fund - Proceeds | 553,654 | 385,185 | 563,712 |
Increase in restricted cash and investments | (16,301) | (57,815) | (51,622) |
(Increase) decrease in restricted cash and short-term investments | (6,076) | 48 | (182,415) |
Activity in other long-term investments - Purchases | (89,263) | (54,113) | (40,593) |
Activity in other long-term investments - Proceeds | 86,563 | 53,756 | 41,652 |
Activity on interest rate options - Purchases/Collateral returned | (81,070) | (187,190) | |
Activity on interest rate options - Collateral received | 46,100 | 213,210 | |
Other | (13,068) | (44,893) | 6,626 |
Net cash used in investing activities | (538,485) | (676,827) | (833,815) |
Cash flows from financing activities: | |||
Long-term debt proceeds | 423,637 | 1,135,687 | 888,857 |
Long-term debt payments | (162,903) | (408,377) | (351,273) |
Increase (decrease) in short-term borrowings, net | 27,109 | (510,038) | 174,927 |
Other | 4,113 | (41,958) | (41) |
Net cash provided by financing activities | 291,956 | 175,314 | 712,470 |
Net (decrease) increase in cash and cash equivalents | (24,353) | (170,802) | 109,628 |
Cash and cash equivalents at beginning of period | 237,391 | 408,193 | 298,565 |
Cash and cash equivalents at end of period | 213,038 | 237,391 | 408,193 |
Cash paid for - | |||
Interest (net of amounts capitalized) | 240,817 | 237,107 | 213,404 |
Supplemental disclosure of non-cash investing and financing activities: | |||
Change in asset retirement obligations | 144,161 | ||
Change in accrued property additions | 119,775 | 36,633 | $ (3,473) |
Interest paid-in-kind | $ 36,021 | $ 24,607 |
CONSOLIDATED STATEMENTS OF PATR
CONSOLIDATED STATEMENTS OF PATRONAGE CAPITAL AND MEMBERSHIP FEES AND ACCUMULATED OTHER COMPREHENSIVE MARGIN (DEFICIT) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||
Dec. 31, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Increase (Decrease) in Members' Capital | |||||||
Balance | $ 761,592 | $ 713,940 | $ 761,592 | $ 713,940 | $ 673,912 | ||
Components of comprehensive margin: | |||||||
Net margin | $ 6,212 | 15,369 | $ (4,237) | 19,223 | 48,341 | 46,635 | 41,480 |
Unrealized gain (loss) on available-for-sale securities | (410) | 1,017 | (1,452) | ||||
Total comprehensive margin | 47,931 | 47,652 | 40,028 | ||||
Balance | 809,523 | 761,592 | 809,523 | 761,592 | 713,940 | ||
Patronage Capital and Membership Fees | |||||||
Increase (Decrease) in Members' Capital | |||||||
Balance | 761,124 | 714,489 | 761,124 | 714,489 | 673,009 | ||
Components of comprehensive margin: | |||||||
Net margin | 48,341 | 46,635 | 41,480 | ||||
Balance | 809,465 | 761,124 | 809,465 | 761,124 | 714,489 | ||
Accumulated Other Comprehensive Margin (Deficit) | |||||||
Increase (Decrease) in Members' Capital | |||||||
Balance | $ 468 | $ (549) | 468 | (549) | 903 | ||
Components of comprehensive margin: | |||||||
Unrealized gain (loss) on available-for-sale securities | (410) | 1,017 | (1,452) | ||||
Balance | $ 58 | $ 468 | $ 58 | $ 468 | $ (549) |
Summary of significant accounti
Summary of significant accounting policies: | 12 Months Ended |
Dec. 31, 2015 | |
Summary of significant accounting policies: | |
Summary of significant accounting policies: | 1. Summary of significant accounting policies: a. Business description Oglethorpe Power Corporation is an electric membership corporation incorporated in 1974 and headquartered in metropolitan Atlanta, Georgia that operates on a not-for-profit basis. We are owned by 38 retail electric distribution cooperative members in Georgia. We provide wholesale electric power from a combination of owned and co-owned generating units of which our ownership share totals 7,067 megawatts of summer planning reserve capacity. We also manage and operate Smarr EMC which owns 718 megawatts of summer planning reserve capacity. Georgia Power Company is a co-owner and the operating agent of our nuclear and coal-fired generating units. Our members in turn distribute energy on a retail basis to approximately 4.2 million people. b. Basis of accounting Our consolidated financial statements include our accounts and the accounts of our majority-owned and controlled subsidiary. We have determined that there are no accounts of variable interest entities for which we are the primary beneficiary. We have eliminated any intercompany profits and transactions in consolidation. We follow generally accepted accounting principles in the United States. We maintain our accounts in accordance with the Uniform System of Accounts of the Federal Energy Regulatory Commission as modified and adopted by the Rural Utilities Service. We also apply the accounting guidance for regulated operations. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of December 31, 2015 and 2014 and the reported amounts of revenues and expenses for each of the three years in the period ended December 31, 2015. Actual results could differ from those estimates. Certain reclassifications have been made to prior periods to conform to the current period presentation. For the year ended December 31, 2014, we made an adjustment of $24,607,000 in the Consolidated Statement of Cash Flows to decrease other adjustments to reconcile net margin to net cash provided by operating activities and decrease cash paid for property additions. This adjustment reflects the non-cash nature of the allowance for debt funds used during construction related to interest paid-in-kind associated with loans under our Department of Energy Loan Guarantee. The change properly reflects an immaterial adjustment to cash flows provided by operations and cash used in investing activities, and is consistent with the 2015 presentation. c. Patronage capital and membership fees We are organized and operate as a cooperative. Our members paid a total of $190 in membership fees. Patronage capital includes retained net margin. Any excess of revenues over expenditures from operations is treated as an advance of capital by our members and is allocated to each member on the basis of their fixed percentage capacity cost responsibilities in our generation. Any distributions of patronage capital are subject to the discretion of our board of directors, subject to first mortgage indenture requirements. Under our first mortgage indenture, we are prohibited from making any distribution of patronage capital to our members if, at the time of or after giving effect to, (i) an event of default exists under the indenture, (ii) our equity as of the end of the immediately preceding fiscal quarter is less than 20% of our total long-term debt and equities, or (iii) the aggregate amount expended for distributions on or after the date on which our equity first reaches 20% of our total long-term debt and equities exceeds 35% of our aggregate net margins earned after such date. This last restriction, however will not apply if, after giving effect to such distribution, our equity as of the end of the immediately preceding fiscal quarter is not less than 30% of our long-term debt and equities. d. Accumulated other comprehensive margin (deficit) The table below provides detail regarding the beginning and ending balance for each classification of other comprehensive margin (deficit) along with the amount of any reclassification adjustments included in net margin for each of the years presented in the Statement of Patronage Capital and Membership Fees and Accumulated Other Comprehensive Margin (Deficit). Our effective tax rate is zero; therefore, all amounts below are presented net of tax. ​ ​ ​ ​ ​ Accumulated Other Comprehensive Margin (Deficit) (dollars in thousands) Available-for-sale Securities ​ ​ ​ ​ ​ Balance at December 31, 2012 $ Unrealized loss ) (Gain) reclassified to net margin ) ​ ​ ​ ​ ​ Balance at December 31, 2013 ) Unrealized gain (Gain) reclassified to net margin ) ​ ​ ​ ​ ​ Balance at December 31, 2014 Unrealized gain (Gain) reclassified to net margin ) ​ ​ ​ ​ ​ Balance at December 31, 2015 $ ​ ​ ​ ​ ​ e. Margin policy We are required under our first mortgage indenture to produce a margins for interest ratio of at least 1.10 for each fiscal year. For the years 2015, 2014 and 2013, we achieved a margins for interest ratio of 1.14. f. Operating revenues Electricity revenues are recognized when capacity and energy are provided. Operating revenues from sales to members consist primarily of electricity sales pursuant to long-term wholesale power contracts which we maintain with each of our members. These wholesale power contracts obligate each member to pay us for capacity and energy furnished in accordance with rates we establish. Capacity revenues recover our fixed costs plus a targeted margin and are charged regardless of whether our generation and purchased power resources are dispatched to produce electricity. Capacity revenues are based on an annual budget and, notwithstanding budget adjustments to meet our targeted margin, are recorded in approximately equal amounts throughout the year. Energy revenues recover variable costs, such as fuel, incurred to generate or purchase electricity and are recorded such that energy revenues equal the actual energy costs incurred. Operating revenues from sales to non-members consist primarily of capacity and energy sales at Smith. Energy sales accounted for a substantial portion of our sales to non-members in 2015, 2014 and 2013. The following table reflects members whose revenues accounted for 10% or more of our total operating revenues in 2015, 2014 or 2013: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2015 2014 2013 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Cobb EMC % % % Sawnee EMC % % % Jackson EMC % % % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ We have two rate management programs that allow us to expense and recover certain costs on a current basis that would otherwise be deferred or capitalized. The subscribing members of Smith and/or Vogtle Units No. 3 and No. 4, can elect to participate in one, both or neither of these two programs on an annual basis. The Smith program allows for the accelerated recovery of deferred net costs related to Smith. The Vogtle program allows for the recovery of financing costs associated with the construction of Vogtle Units No. 3 and No. 4 on a current basis. Under these programs, amounts billed to participating members in 2015, 2014 and 2013 were $25,375,000, $14,991,000 and $13,962,000, respectively. g. Receivables A substantial portion of our receivables are related to electricity sales to our members. These receivables are recorded at the invoiced amount and do not bear interest. Our members are required through the wholesale power contracts to reimburse us for all costs. Member receivables at December 31, 2015 and 2014 were $108,729,000 and $114,808,000, respectively. The remainder of our receivables is primarily related to transactions with affiliated companies, electricity sales to non-members and to interest income on investments. Uncollectible amounts, if any, are identified on a specific basis and charged to expense in the period the amounts are determined to be uncollectible. h. Nuclear fuel cost The cost of nuclear fuel is being amortized to fuel expense based on usage. The total nuclear fuel expense for 2015, 2014 and 2013 amounted to $78,762,000, $85,166,000, and $86,828,000, respectively. Contracts with the U.S. Department of Energy have been executed to provide for the permanent disposal of spent nuclear fuel produced at Hatch and Vogtle. The Department of Energy failed to begin disposing of spent fuel in January 1998 as required by the contracts, and Georgia Power, as agent for the co-owners of the plants has pursued and continues to pursue legal remedies against the Department of Energy for breach of contract. On December 14, 2014, the U.S. Court of Federal Claims issued a judgment in favor of Georgia Power, as agent for the co-owners, to recover spent nuclear fuel storage costs at Hatch and Vogtle Units No. 1 and No. 2 covering the period of 2005 through 2010. Our ownership share of the $36,474,000 total award was $10,949,000, which was received in April 2015. The effects of the award were recorded during the first quarter of 2015 and resulted in a $7,320,000 reduction in total operating expenses, including reductions to fuel expense and production costs, as well as a $3,629,000 reduction to plant in service. On March 4, 2014, Georgia Power, as agent for the co-owners, filed a separate claim seeking damages for spent nuclear fuel storage costs at Hatch and Vogtle Units No. 1 and No. 2 covering a period of January 1, 2011 through December 31, 2013. The damage period was subsequently amended and now extends through December 31, 2014. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the financial statements as of December 31, 2015 for this claim. The final outcome of these matters cannot be determined at this time. Both Plants Hatch and Vogtle have on-site dry spent storage facilities in operation. Facilities at both plants can be expanded to accommodate spent fuel through the expected life of each plant. i. Asset retirement obligations and other retirement costs Asset retirement obligations are legal obligations associated with the retirement of long-lived assets. These obligations represent the present value of the estimated costs for an asset's future retirement discounted using a credit-adjusted risk-free rate, and are recorded in the period in which the liability is incurred. The liabilities we have recognized primarily relate to the decommissioning of our nuclear facilities. In addition, we have retirement obligations related to coal ash ponds, gypsum cells, powder activated carbon cells, landfill sites and asbestos removal. Under the accounting provision for regulated operations, we record a regulatory asset or liability to reflect the difference in timing of recognition of the costs related to nuclear and coal ash related decommissioning for financial statement purposes and for ratemaking purposes. Periodically, we obtain revised cost studies associated with our nuclear and fossil plants' asset retirement obligations. Actual retirement costs may vary from these estimates. The estimated costs of nuclear and coal ash pond decommissioning are based on the most recent studies performed in 2015. The following table reflects the details of the Asset Retirement Obligations included in the consolidated balance sheets for the years 2015 and 2014. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Nuclear Coal Ash Pond Other Total ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at December 31, 2014 $ $ $ $ Liabilities settled – – ) ) Accretion Change in Cash Flow Estimates ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at December 31, 2015 $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Nuclear Coal Ash Pond Other Total ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at December 31, 2013 $ $ $ $ Liabilities settled – – ) ) Accretion ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at December 31, 2014 $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Nuclear Decommissioning. Nuclear decommissioning cost estimates are based on site studies and assume prompt dismantlement and removal of both the radiated and non-radiated portions of the plant from service, as well as the management of spent fuel. We do not have a legal obligation to decommission non-radiated structures and, therefore, these costs are excluded from the related asset retirement obligation and the amounts in the table above. Actual decommissioning costs may vary from these estimates because of changes in the assumed date of decommissioning, changes in regulatory requirements, changes in technology, and changes in costs of labor, materials and equipment. The estimated costs of decommissioning are based on the most current study performed in 2015. In projecting future costs, the escalation rate for labor, materials and equipment was assumed to be 2.5%. The increase in the cash flow estimates in 2015 was primarily attributable to security costs, waste disposal costs and inflation, among other factors. Our portion of the estimated costs of decommissioning co-owned nuclear facilities were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2015 site study Hatch Unit No. 1 Hatch Unit No. 2 Vogtle Unit No. 1 Vogtle Unit No. 2 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Expected start date of decommissioning 2034 2038 2047 2049 Estimated costs based on site study in 2015 dollars: Radiated structures $ $ $ $ Spent fuel management Non-radiated structures ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total estimated site study costs $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ We have established funds to comply with the Nuclear Regulatory Commission regulations regarding the decommissioning of our nuclear plants. See Note 1j for information regarding the nuclear decommissioning funds. Coal Ash Pond. On April 17, 2015 the Environmental Protection Agency published its final coal combustion residuals (CCR) rule which regulates CCRs as non-hazardous materials under Subtitle D of the Resource Conservation and Recovery Act. The rule took effect on October 19, 2015. The most current assessment of the final CCR rule resulted in a $49,084,000 change in cash flow estimates for coal ash decommissioning. Estimates are based on various assumptions including, but not limited to, closure and post-closure cost estimates, timing of expenditures, escalation factors, discount rates and methods for complying with the CCR rule. The increase in the cash flow estimates in 2015 was a result of changes in the assumptions regarding the timing of expenditures as well as an increase in the cost estimates. Additional adjustments to the asset retirement obligations are expected periodically that will impact these estimates and assumptions. Accounting standards for asset retirement and environmental obligations do not apply to a retirement cost for which there is no legal obligation to retire the asset, and non-regulated entities are not allowed to accrue for such future retirement costs. We continue to recognize retirement costs for these other obligations in our depreciation rates under the accounting provisions for regulated operations. Accordingly, the accumulated retirement costs for other obligations are reflected as a regulatory liability in our balance sheets. For information regarding accumulated retirement costs for other obligations, see Note 1r. j. Nuclear decommissioning funds The Nuclear Regulatory Commission (NRC) requires all licensees operating commercial power reactors to establish a plan for providing, with reasonable assurance, funds for decommissioning. The NRC definition of decommissioning does not include all costs that may be associated with decommissioning, such as spent fuel management and non-radiated structures. We have established external trust funds to comply with the NRC's regulations. Upon approval by the NRC, any funding in the external trust in excess of their requirements may be used for other decommissioning costs. In 2015 and 2014, no additional amounts were contributed to the external trust funds. These funds are managed by unrelated third party investment managers with the discretion to buy, sell and invest pursuant to investment objectives and restrictions set forth in agreements entered into between us and the investment managers. The fair value of the external trust fund was $363,829,000 and $366,004,000 at December 31, 2015 and 2014, respectively. The funds are invested in a diversified mix of approximately 60% equity and 40% fixed income securities. We record the investment securities held in the nuclear decommissioning trust fund, which are classified as available-for-sale, at fair value, as disclosed in Note 2. Because day-to-day investment decisions are made by third party investment managers, the ability to hold investments in unrealized loss positions is outside our control. In addition to the external trust funds, we maintain unrestricted investments internally designated for nuclear decommissioning. These internal funds are available to be utilized to fund the external trust funds, should additional funding be required, as well as other decommissioning costs outside the scope of the NRC funding regulations. At December 31, 2015 and 2014, the fair value of these funds was $63,326,000 and $59,080,000, respectively. The funds are included in long-term investments on our consolidated balance sheet. We collected $4,750,000 and $2,975,000 from our members in 2015 and 2014, respectively, and contributed those amounts into the internal funds. Unrealized gains and losses of the nuclear decommissioning funds that would be recorded in earnings or other comprehensive margin (deficit) by a non-regulated entity are directly deducted from or added to the regulatory asset or liability for asset retirement obligations in accordance with our rate-making treatment. Realized gains and losses on the nuclear decommissioning funds are also recorded to the regulatory asset or liability. During 2015, we assumed a 6.0% earnings rate for our decommissioning fund assets. Earnings on the fund assets were approximately $40,380,000 and $23,507,000 in 2015 and 2014, respectively. Since inception in 1990 through 2015, the nuclear decommissioning trust fund has produced an average annualized return of approximately 7.1%. Based on current funding and cost study estimates, we expect the current balances and anticipated investment earnings of our decommissioning fund assets to be sufficient to meet all of our future nuclear decommissioning costs. Notwithstanding the results of revised site studies, our management believes that any increase in cost estimates of decommissioning can be recovered in future rates. k. Depreciation Depreciation is computed on additions when they are placed in service using the composite straight-line method. We use standard depreciation rates as well as site specific rates determined through depreciation studies as approved by the Rural Utilities Service. The depreciation rates for steam and nuclear production in the table below reflect revised rates from 2011 depreciation rate studies. Site specific depreciation studies are performed every five years. Annual depreciation rates in effect in 2015, 2014 and 2013 were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Range of Useful Life in years* 2015 2014 2013 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Steam production 49-65 % % % Nuclear production 37-60 % % % Hydro production 50 % % % Other production 27-33 % % % Transmission 36 % % % General 3-50 2.00-33.33 % 2.00-33.33 % 2.00-33.33 % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ * Calculated based on the composite depreciation rates in effect for 2015. Depreciation expense for the years 2015, 2014 and 2013 was $180,866,000, $178,302,000, and $171,240,000, respectively. l. Electric plant Electric plant is stated at original cost, which is the cost of the plant when first dedicated to public service, plus the cost of any subsequent additions. Cost includes an allowance for the cost of equity and debt funds used during construction and allocable overheads. For the years ended 2015, 2014 and 2013, the allowance for funds used during construction rates were 4.73%, 4.97% and 4.93%, respectively. Replacements and renewals of items considered to be units of property, the lowest level of property for which we capitalize, are charged to the plant accounts. At the time properties are disposed of, the original cost, plus cost of removal, less salvage of such property, is charged to the accumulated provision for depreciation. Maintenance and repairs of property and replacements and renewals of items determined to be less than units of property are charged to expense, including certain major maintenance costs at our natural gas-fired plants. m. Cash and cash equivalents We consider all temporary cash investments purchased with an original maturity of three months or less to be cash equivalents. Temporary cash investments with maturities at the time of purchase of more than three months are classified as short-term investments. n. Restricted cash and investments Restricted cash and investments primarily consist of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account. The restricted investments will be utilized for future Rural Utilities Service-guaranteed Federal Financing Bank debt service payments. The funds on deposit earn interest at a rate of 5% annum. At 2015 and 2014, we had restricted cash and investments totaling $387,961,000 and $365,585,000, respectively, of which $134,690,000 and $118,390,000, respectively was classified as long-term. o. Inventories We maintain inventories of fossil fuel and spare parts, including materials and supplies for our generation plants. These inventories are stated at weighted average cost on the accompanying balance sheets. The fossil fuel inventories primarily include the direct cost of coal and related transportation charges. The cost of fossil fuel inventories is carried at weighted average cost and is charged to fuel expense as consumed based on weighted average cost. The spare parts inventories primarily include the direct cost of generating plant spare parts. The spare parts inventory is carried at weighted average cost and the parts are charged to expense or capitalized, as appropriate when installed. At 2015 and 2014, fossil fuels inventories were $104,086,000 and $98,789,000, respectively. Inventories for spare parts at 2015 and 2014 were $195,166,000 and $172,060,000, respectively. p. Deferred charges and other assets Prepayments to Georgia Power Company primarily represent progress payments for equipment associated with future nuclear refueling outages. In 2014, prepayments to Georgia Power also included disputed payment amounts associated with the Vogtle Units No. 3 and No. 4 construction project that were paid during 2015. q. Deferred credits and other liabilities We have a power bill prepayment program pursuant to which members can prepay their power bills from us at a discount based on our avoided cost of borrowing. The prepayments are credited against the participating members' power bills in the month(s) agreed upon in advance. The discounts are credited against the power bills monthly and are recorded as a reduction to member revenues. The prepayments are being credited against members' power bills through July 2021, with the majority of the balance scheduled to be credited by the end of 2016. In connection with the Vogtle Units No. 3 and No. 4 construction project, we are accruing long-term contract retainage amounts for substantial and mechanical milestones that will become due near the anticipated commercial operation dates of the units. For more information regarding the Vogtle construction project, see Note 8. We recorded a liability for a power sale agreement assumed in conjunction with the Hawk Road acquisition in May 2009. The liability was fully amortized in 2015. r. Regulatory assets and liabilities We apply the accounting guidance for regulated operations. Regulatory assets represent certain costs that are probable of recovery from our members in future revenues through rates under the wholesale power contracts with our members, which extend through December 31, 2050. Regulatory liabilities represent certain items of income that we are retaining and that will be applied in the future to reduce revenues required to be recovered from members. ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2015 2014 ​ ​ ​ ​ ​ ​ ​ ​ Regulatory Assets: Premium and loss on reacquired debt (a) $ $ Amortization on capital leases (b) Outage costs (c) Interest rate swap termination fees (d) Depreciation expense (e) Deferred charges related to Vogtle Units No. 3 and No. 4 training costs (f) Interest rate options cost (g) Deferral of effects on net margin – Smith Energy Facility (h) Other regulatory assets (m) ​ ​ ​ ​ ​ ​ ​ ​ Total Regulatory Assets Regulatory Liabilities: Accumulated retirement costs for other obligations (i) $ $ Deferral of effects on net margin – Hawk Road Energy Facility (h) Major maintenance reserve (j) Amortization on capital leases (b) Deferred debt service adder (k) Asset retirement obligations (l) Other regulatory liabilities (m) ​ ​ ​ ​ ​ ​ ​ ​ Total Regulatory Liabilities ​ ​ ​ ​ ​ ​ ​ ​ Net regulatory assets $ $ ​ ​ ​ ​ ​ ​ ​ ​ (a) Represents premiums paid, together with unamortized transaction costs related to reacquired debt that are being amortized over the lives of the refunding debt, which range up to 28 years. (b) Represents the difference between expense recognized for rate-making purposes and financial statement purposes related to capital lease payments and the aggregate of the amortization of the asset and interest on the obligation. (c) Consists of both coal-fired maintenance and nuclear refueling outage costs. Coal-fired outage costs are amortized on a straight-line basis to expense over a 24-month period. Nuclear refueling outage costs are amortized on a straight-line basis to expense over the 18 to 24-month operating cycles of each unit. (d) Represents losses on settled interest rate swap arrangements that are being amortized through 2016 and 2019. (e) Prior to Nuclear Regulatory Commission (NRC) approval of a 20-year license extension for Plant Vogtle, we deferred the difference between Plant Vogtle depreciation expense based on the then 40-year operating license and depreciation expense assuming an expected 20-year license extension. Amortization commenced upon NRC approval of the license extension in 2009 and is being amortized over the remaining life of the plant. (f) Deferred charges related to Vogtle Units No. 3 and No. 4 training and interest related carrying costs of such training. Amortization will commence effective with the commercial operation date of each unit and amortized to expense over the life of the units. (g) Deferral of net loss associated with the unrealized and realized change in fair value of interest rate options purchased to hedge interest rates on certain borrowings related to Vogtle Units No. 3 and No. 4 construction. Amortization will commence in February 2020 and will be amortized through February 2044, the life of the DOE-guaranteed loan which is financing a portion of the construction project. (h) Effects on net margin for Smith and Hawk Road Energy Facilities were deferred through the end of 2015 and will be amortized over the remaining life of each respective plant. (i) Represents the accrual of retirement costs associated with long-lived assets for which there are no legal obligations to retire the assets. (j) Represents collections for future major maintenance expenses; revenues are recognized as major maintenance costs are incurred. (k) Represents collections to fund certain debt payments to be made through the end of 2025 which will be in excess of amounts collected through depreciation expense; the deferred credits will be amortized over the remaining useful life of the plants. (l) Represents difference in timing of recognition of the costs of decommissioning for financial statement purposes and for ratemaking purposes. (m) The amortization period for other regulatory assets range up to 34 years and the amortization period of other regulatory liabilities range up to 11 years. s. Related parties We and our 38 members are members of Georgia Transmission. Georgia Transmission provides transmission services to its members for delivery of its members' power purchases from us and other power suppliers. We have entered into an agreement with Georgia Transmission to provide transmission services for third party transactions and for service to our own facilities. For 2015, 2014, and 2013, we incurred expenses from Georgia Transmission of $28,172,000, $27,893,000, and $27,599,000, respectively. We, Georgia Transmission and 38 of our members are members of Georgia Systems Operations. Georgia Systems Operations operates the system control center and currently provides us system operations services and administrative support services. For 2015, 2014, and 2013, we incurred expenses from Georgia Systems Operations of $22,616,000, $27,893,000, and $27,599,000, respectively. t. Other income The components of other income within the Consolidated Statement of Revenues and Expenses were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2015 2014 2013 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Capital credits from associated companies (Note 4) $ $ $ Net revenue from Georgia Transmission and Georgia System Operations for shared Administrative and General costs Miscellaneous other ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ u. New accounting pronouncements In May 2014, the Financial Accounting Standards Board (FASB) issued "Revenue from Contracts with Customers" (Topic 606). The new revenue standard requires that an entity recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. The standard was effective for the annual reporting period beginning after December 15, 2016 using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a modified retrospective approach with the cumulative effect of initially adopting the standard recognized at the date of adoption (which includes additional footnote disclosures). Early adoption was not permitted. In August 2015, the FASB issued an update to Topic 606 deferring the effective date by one year. The standard is effective for annual reporting periods beginning after December 15, 2017 and interim periods therein. The standard also permits early adoption of the standard, but not before the original effective date of December 15, 2016. We are currently evaluating the future impact of this standard on our consolidated financial statements. In July 2015, the FASB issued "Inventory (Topic 330): Simplifying the Measurement of Inventory." Under the new inventory standard, inventories are required to be measured at the lower of cost and net realizable value, the latter representing the estimated selling price in the ordinary course of business, reduced by costs of completion, disposal, and transportation. Under current guidance, inventories are required to be measured at the lower of cost or market, but depending upon specific circumstances, market could be replacement cost, net realizable value, or net realizable value reduced by a normal profit margin. The amendments do not apply to inventory measured using the last-in, first-out or the retail inventory method. The amendments apply to all other inventory, which includes inventory that is measured using first-in, first out or average cost, the method used to measure all of our inventories. The new standard is effective for us prospectively for annual reporting periods beginning after December 15, 2016, and interim periods therein. Early adoption is permitted as of the beginning of an interim or annual reporting period. We are currently evaluating the future impact of this standard on our consolidated financial statements. In April 2015, the FASB issued "Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs." The amendments in this standard require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. In August 2015, the FASB clarified that its guidance issued in April |
Fair Value_
Fair Value: | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value: | |
Fair Value: | 2. Fair Value: Authoritative guidance regarding fair value measurements for financial and non-financial assets and liabilities defines fair value, establishes a framework for measuring fair value in accordance with generally accepted accounting principles, and expands disclosures about fair value measurements. The guidance establishes a three-tier fair value hierarchy which prioritizes the inputs used in measuring fair value as follows: • Level 1. Quoted prices from active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Quoted prices in active markets provide the most reliable evidence of fair value and are used to measure fair value whenever available. Level 1 primarily consists of financial instruments that are exchange-traded. • Level 2. Pricing inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 2 primarily consists of financial instruments that are non-exchange-traded but have significant observable inputs. • Level 3. Pricing inputs that include significant inputs which are generally less observable from objective sources. These inputs may include internally developed methodologies that result in management's best estimate of fair value. Level 3 financial instruments are those whose fair value is based on significant unobservable inputs. 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 table below details assets and liabilities measured at fair value on a recurring basis for the periods ended December 31, 2015 and 2014, respectively. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fair Value Measurements at Reporting Date Using December 31, 2015 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ $ $ – $ – International equity trust – – Corporate bonds – – US Treasury and government agency securities – Agency mortgage and asset backed securities – – Other – – Long-term investments: Corporate bonds – – US Treasury and government agency securities – – Agency mortgage and asset backed securities – – International equity trust – – Mutual funds – – Other – – Interest rate options – – (1) Natural gas swaps – – ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fair Value Measurements at Reporting Date Using December 31, 2014 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ $ $ – $ – International equity trust – – Corporate bonds – – US Treasury and government agency securities – – Agency mortgage and asset backed securities – – Municipal Bonds – – Other – – Long-term investments: Corporate bonds – – US Treasury and government agency securities – – Agency mortgage and asset backed securities – – International equity trust – – Mutual funds – – Other – – Interest rate options – – (1) Natural gas swaps – – ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) Interest rate options as reflected on the Consolidated Balance Sheet include the fair value of the interest rate options. The Level 2 investments above in corporate bonds and agency mortgage and asset backed securities may not be exchange traded. The fair value measurements for these investments are based on a market approach, including the use of observable inputs. Common inputs include reported trades and broker/dealer bid/ask prices. The fair value of the Level 2 investments above in international equity trust are calculated based on the net asset value per share of the fund. There are no unfunded commitments for the international equity trust and redemption may occur daily with a three-day redemption notice period. The following tables present the changes in Level 3 assets measured at fair value on a recurring basis during the years ended 2015 and 2014, respectively. ​ ​ ​ ​ ​ Year Ended December 31, 2015 Interest rate options ​ ​ ​ ​ ​ (dollars in thousands) Assets: Balance at December 31, 2014 $ Total gains or losses (realized/unrealized): Included in earnings (or changes in net assets) ) ​ ​ ​ ​ ​ Balance at December 31, 2015 $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, 2014 Interest rate options ​ ​ ​ ​ ​ (dollars in thousands) Assets: Balance at December 31, 2013 $ Total gains or losses (realized/unrealized): Included in earnings (or changes in net assets) ) ​ ​ ​ ​ ​ Balance at December 31, 2014 $ ​ ​ ​ ​ ​ We estimate the value of the interest rate options as the sum of time value and any intrinsic value minus a counterparty credit adjustment. Intrinsic value is the value of the underlying swap, which we are able to calculate based on the forward LIBOR swap rates, the fixed rate on the underlying swap, the time to expiration, the term of the underlying swap and discount rates, all of which we are able to effectively observe. Time value is the additional value of the swaption due to the fact that it is an option. We estimate the time value using an option pricing model that, in addition to the factors used to calculate intrinsic value, also takes into account option volatility, which we estimate based on option valuations we obtain from various sources. We estimate the counterparty credit adjustment by observing credit attributes, including the credit default swap spread of entities similar to the counterparty and the amount of credit support that is available for each swaption. Since the primary component of the LIBOR swaptions' value is time value, which is based on estimated option volatility derived from valuations of comparable instruments that are generally not publicly available, we have categorized these LIBOR swaptions as Level 3. We believe the estimated fair values for the LIBOR swaptions we hold are based on the most accurate information available for these types of derivative contracts. For additional information regarding our interest rate options, see Note 3. The estimated fair values of our long-term debt, including current maturities at December 31, 2015 and 2014 were as follows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2015 2014 Carrying Value Fair Value Carrying Value Fair Value ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Long-term debt $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ The estimated fair value of long-term debt is classified as Level 2 and is estimated based on observed or quoted market prices for the same or similar issues or on current rates offered to us for debt of similar maturities. The primary sources of our long-term debt consist of first mortgage bonds, pollution control revenue bonds and long-term debt issued by the Federal Financing Bank that is guaranteed by the Rural Utilities Service or the U.S. Department of Energy. We also have small amounts of long-term debt provided by National Rural Utilities Cooperative Finance Corporation (CFC) and by CoBank, ACB. The valuations for the first mortgage bonds and the pollution control revenue bonds were obtained from third party investment banking firms and a third party data reporting service, and are based on secondary market trading of our debt. Valuations for debt issued by the Federal Financing Bank are based on U.S. Treasury rates as of December 31, 2015 and 2014 plus an applicable spread, which reflects our borrowing rate for new loans of this type from the Federal Financing Bank. The rates on the CFC debt are fixed and the valuation is based on rate quotes provided by CFC. We use an interest rate quote sheet provided by CoBank for valuation of the CoBank debt, which reflects current rates for a similar loan. For cash and cash equivalents, restricted cash and receivables, the carrying amount approximates fair value because of the short-term maturity of those instruments. |
Derivative instruments_
Derivative instruments: | 12 Months Ended |
Dec. 31, 2015 | |
Derivative instruments: | |
Derivative instruments: | 3. Derivative instruments: Our risk management and compliance committee provides general oversight over all risk management and compliance activities, including but not limited to, commodity trading, investment portfolio management and interest rate risk management. We use commodity trading derivatives to manage our exposure to fluctuations in the market price of natural gas. To hedge the risk of rising interest rates on a portion of our anticipated long-term debt to be incurred in connection with capital expenditures, we have entered into interest rate options. We do not apply hedge accounting for any of these derivatives, but apply regulatory accounting. Consistent with our rate-making, unrealized gains or losses on our natural gas swaps and interest rate options are reflected as regulatory assets or liabilities, as appropriate. We are exposed to credit risk as a result of entering into these hedging arrangements. Credit risk is the potential loss resulting from a counterparty's nonperformance under an agreement. We have established policies and procedures to manage credit risk through counterparty analysis, exposure calculation and monitoring, exposure limits, collateralization and certain other contractual provisions. It is possible that volatility in commodity prices and/or interest rates could cause us to have credit risk exposures with one or more counterparties. We currently have credit risk exposure to our interest rate options counterparties. If such counterparties fail to perform their obligations, we could suffer a financial loss. However, as of December 31, 2015, all of the counterparties with transaction amounts outstanding under our hedging programs are rated investment grade by the major rating agencies or have provided a guaranty from one of their affiliates that is rated investment grade. We have entered into International Swaps and Derivatives Association agreements with our natural gas hedge and interest rate option counterparties that mitigate credit exposure by creating contractual rights relating to creditworthiness, collateral, termination and netting (which, in certain cases, allows us to use the net value of affected transactions with the same counterparty in the event of default by the counterparty or early termination of the agreement). Additionally, we have implemented procedures to monitor the creditworthiness of our counterparties and to evaluate nonperformance in valuing counterparty positions. We have contracted with a third party to assist in monitoring certain of our counterparties' credit standing and condition. Net liability positions are generally not adjusted as we use derivative transactions as hedges and have the ability and intent to perform under each of our contracts. In the instance of net asset positions, we consider general market conditions and the observable financial health and outlook of specific counterparties, forward looking data such as credit default swaps, when available, and historical default probabilities from credit rating agencies in evaluating the potential impact of nonperformance risk to derivative positions. The contractual agreements contain provisions that could require us or the counterparty to post collateral or credit support. The amount of collateral or credit support that could be required is calculated as the difference between the aggregate fair value of the hedges and pre-established credit thresholds. The credit thresholds are contingent upon each party's credit ratings from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. Gas hedges. Under the natural gas swap arrangements, we pay the counterparty a fixed price for specified natural gas quantities and receive a payment for such quantities based on a market price index. These payment obligations are netted, such that if the market price index is lower than the fixed price, we will make a net payment, and if the market price index is higher than the fixed price, we will receive a net payment. At December 31, 2015 and 2014, the estimated fair value of our natural gas contracts were a net liability of $22,848,000 and $18,914,000, respectively. As of December 31, 2015 and 2014, neither we nor any counterparties were required to post credit support or collateral under the natural gas swap agreements. If the credit-risk-related contingent features underlying these agreements were triggered on December 31, 2015 due to our credit rating being downgraded below investment grade, we would have been required to post letters of credit of $24,995,000 with our counterparties. The following table reflects the volume activity of our natural gas derivatives as of December 31, 2015 that is expected to settle or mature each year: ​ ​ ​ ​ ​ Year Natural Gas Swaps (MMBTUs) (in millions) ​ ​ ​ ​ ​ 2016 2017 2018 2019 ​ ​ ​ ​ ​ Total ​ ​ ​ ​ ​ Interest rate options. We are exposed to the risk of rising interest rates due to the significant amount of new long-term debt we expect to incur in connection with anticipated capital expenditures, particularly the construction of Vogtle Units No. 3 and No. 4. In fourth quarter of 2011, we purchased LIBOR swaptions at a cost of $100,000,000 with a total notional amount of approximately $2,200,000,000 to hedge the interest rates on a portion of the debt that we are incurring to finance the two additional nuclear units at Plant Vogtle. Since inception, swaptions having a notional amount of approximately $1,788,502,000 have expired and, as of December 31, 2015, the remaining notional amount of our outstanding swaptions was approximately $390,702,000. The LIBOR swaptions are each designed to cap our effective interest rate at a specified fixed interest rate on a specified option expiration date. This is accomplished by means of a payment of the cash settlement value our counterparties are obligated to make to us if prevailing fixed LIBOR swap rates exceed the specified fixed rate on the option expiration date. This payment would partially offset our interest costs, thereby reducing our effective interest rate. The cash settlement value would be zero if swap rates are at or below the specified fixed rate on the expiration date. The cash settlement value is calculated based on the value of an underlying swap which we have the right, but not the obligation, to enter into, which would begin on the option expiration date and extend until 2042 and under which we would pay the specified fixed rate and receive a floating LIBOR rate. The fixed rates on the unexpired swaptions we hold average 151 basis points above the corresponding LIBOR swap rates that were in effect as of December 31, 2015 and the weighted average fixed rate is 3.95%. Swaptions having notional amounts totaling $470,625,000 expired without value during the year ended December 31, 2015. The remaining swaptions expire quarterly through March 31, 2017. We paid all the premiums to purchase these LIBOR swaptions at the time we entered into these transactions. At December 31, 2015 and 2014, the fair value of these swaptions was approximately $1,010,000 and $4,371,000, respectively. To manage our credit exposure to our counterparties, we negotiated credit support provisions that require each counterparty to provide us collateral in the form of cash or securities to the extent that the value of the swaptions outstanding for that counterparty exceeds a certain threshold. The collateral thresholds can range from $0 to $10,000,000 depending on each counterparty's credit rating. As of December 31, 2015 and 2014, there were no collateral postings required of the counterparties. We are deferring realized and unrealized gains or losses from the change in fair value of each LIBOR swaption as well as related carrying and other incidental costs in accordance with our rate-making treatment. The deferral will continue until February 2020, at which time the deferred costs and deferred gains, if any, from the settlement of the interest rate options will be amortized and collected in rates over the life of the $2,200,000,000 of debt that we hedged with the swaptions. The following table reflects the remaining notional amount of forecasted debt issuances we have hedged in each year with LIBOR swaptions as of December 31, 2015. ​ ​ ​ ​ ​ Year LIBOR Swaption Notional Dollar Amount (in thousands) ​ ​ ​ ​ ​ 2016 $ 2017 ​ ​ ​ ​ ​ Total $ ​ ​ ​ ​ ​ The table below reflects the fair value of derivative instruments and their effect on our consolidated balance sheets at December 31, 2015 and 2014. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance Sheet Location Fair Value ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2015 2014 (dollars in thousands) Not designated as hedge: Assets Interest rate options Other deferred charges $ $ Liabilities Natural gas swaps Other current liabilities $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ The following table presents the realized gains and (losses) on derivative instruments recognized in margin for the year ended December 31, 2015, 2014 and 2013. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Consolidated Statement of Revenues and Expenses Location 2015 2014 2013 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Not designated as hedge: Natural Gas Swaps Fuel $ $ $ Natural Gas Swaps Fuel ) ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ ) $ $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ The following table presents the unrealized gains and (losses) on derivative instruments deferred on the balance sheet at December 31, 2015 and 2014. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Consolidated Balance Sheet Location ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2015 2014 Not designated as hedges: Natural Gas Swaps Regulatory asset $ ) $ ) Interest Rate Options Regulatory asset ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total not designated as hedges $ ) $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ The following table presents the gross amounts of derivatives and their related offset amounts as permitted by their respective master netting agreements and obligations to return cash collateral at December 31, 2015 and 2014. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Gross Amounts of Recognized Assets (Liabilities) Gross Amounts offset on the Balance Sheet Cash Collateral Net Amounts of Assets (Liabilities) Presented on the Balance Sheet ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2015 Assets: Natural gas swaps $ ) $ – $ – $ ) Interest rate options $ $ ) $ – $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2014 Assets: Natural gas swaps $ ) $ – $ – $ ) Interest rate options $ $ ) $ – $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ |
Investments_
Investments: | 12 Months Ended |
Dec. 31, 2015 | |
Investments: | |
Investments: | 4. Investments: Investments in debt and equity securities Investment securities we hold are classified as available-for-sale. Available-for-sale securities are carried at market value with unrealized gains and losses, net of any tax effect, added to or deducted from patronage capital, except that, in accordance with our rate-making treatment, realized and unrealized gains and losses from investment securities held in the nuclear decommissioning funds are directly added to or deducted from the regulatory asset or liability for asset retirement obligations. All realized and unrealized gains and losses are determined using the specific identification method. Approximately 27% of these gross unrealized losses were in effect for less than one year. For those securities considered to be available-for-sale, the following table summarizes the activities for those securities as of December 31, 2015 and 2014: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Gross Unrealized 2015 Cost Gains Losses Fair Value ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity $ $ $ ) $ Debt ) Other – ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ ) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Gross Unrealized 2014 Cost Gains Losses Fair Value ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity $ $ $ ) $ Debt ) Other – ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ ) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ All of the available-for-sale investments are recorded at fair value in the accompanying consolidated balance sheets, therefore the carrying value equals the fair value. The contractual maturities of debt securities available-for-sale, which are included in the estimated fair value table above, at December 31, 2015 and 2014 are as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2015 2014 Cost Fair Value Cost Fair Value ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Due within one year $ $ $ $ Due after one year through five years Due after five years through ten years Due after ten years ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ The following table summarizes the realized gains and losses and proceeds from sales of securities for the years ended December 31, 2015, 2014 and 2013: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2015 2014 2013 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Gross realized gains $ $ $ Gross realized losses ) ) ) Proceeds from sales ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Investment in associated companies Investments in associated companies were as follows at December 31, 2015 and 2014: ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2015 2014 ​ ​ ​ ​ ​ ​ ​ ​ National Rural Utilities Cooperative Finance Corporation (CFC) $ $ CT Parts, LLC Georgia Transmission Corporation Georgia System Operations Corporation Other ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ ​ ​ ​ ​ ​ ​ ​ ​ The CFC investments consist of capital term certificates required in connection with our membership in CFC and a voluntary investment in CFC member capital securities. Accordingly, there is no market for these investments. The investments in Georgia Transmission represent capital credits. The investments in Georgia System Operations represent loan advances. Repayments of these advances are expected by December 2020. CT Parts, LLC is an affiliated organization formed by us and Smarr EMC for the purpose of purchasing and maintaining spare parts inventory and for the administration of contracted services for combustion turbine generation facilities. Such investment is recorded at cost. Rocky Mountain transactions In December 1996 and January 1997, we entered into six long-term lease transactions relating to our 74.61% undivided interest in Rocky Mountain. In each transaction, we leased a portion of our undivided interest in Rocky Mountain to six separate owner trusts for the benefit of three investors, referred to as owner participants, for a term equal to 120% of the estimated useful life of Rocky Mountain. Immediately thereafter, the owner trusts leased their undivided interests in Rocky Mountain to our wholly owned subsidiary, Rocky Mountain Leasing Corporation, or RMLC, for a term of 30 years under six separate leases. RMLC then subleased the undivided interests back to us under six separate leases for an identical term. In 2012, we terminated five of the six lease transactions prior to the end of their lease terms. The remaining lease in place represented approximately 10% of the original lease transactions. We have a guarantee for the basic rental payments under the remaining lease. The fair value amount relating to the guarantee of basic rent payments is immaterial to us principally due to the high credit rating of the payment undertaker. The basic rental payments remaining through the end of the lease are approximately $59,209,000. The assets of RMLC are not available to pay our creditors. |
Income taxes_
Income taxes: | 12 Months Ended |
Dec. 31, 2015 | |
Income taxes: | |
Income taxes: | 5. Income taxes: While we are a not-for-profit membership corporation formed under the laws of Georgia, we are subject to federal and state income taxation. As a taxable cooperative, we are allowed to deduct patronage dividends that we allocate to our members for purposes of calculating our taxable income. We annually allocate income and deductions between patronage and non-patronage activities and substantially all of our income is from patronage-sourced activities, resulting in no current period income tax expense or current or deferred income tax liability. Although we believe that treatment of non-member sales as patronage-sourced income is appropriate, this treatment has not been examined by the Internal Revenue Service. If this treatment was not sustained, we believe that the amount of taxes on such non-member sales, after allocating related expenses against the revenues from such sales, would not have a material adverse effect on financial condition or results of operations and cash flows. We account for income taxes pursuant to the authoritative guidance for accounting for income taxes, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements or tax returns. The difference between the statutory federal income tax rate on income before income taxes and our effective income tax rate is summarized as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2015 2014 2013 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Statutory federal income tax rate % % Patronage exclusion %) %) Other %) %) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Effective income tax rate % % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ The components of our net deferred tax assets and liabilities as of December 31, 2015 and 2014 were as follows: ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2015 2014 ​ ​ ​ ​ ​ ​ ​ ​ Deferred tax assets Net operating losses $ $ Tax credits (alternative minimum tax and other) Accounting for Rocky Mountain transactions Other assets ​ ​ ​ ​ ​ ​ ​ ​ Deferred tax assets Less: Valuation allowance ) ) ​ ​ ​ ​ ​ ​ ​ ​ Net deferred tax assets $ $ ​ ​ ​ ​ ​ ​ ​ ​ Deferred tax liabilities Depreciation $ $ Accounting for Rocky Mountain transactions Other liabilities ​ ​ ​ ​ ​ ​ ​ ​ Deferred tax liabilities ​ ​ ​ ​ ​ ​ ​ ​ Net deferred tax liabilities Less: Patronage exclusion ) ) ​ ​ ​ ​ ​ ​ ​ ​ Net deferred taxes $ – $ – ​ ​ ​ ​ ​ ​ ​ ​ As of December 31, 2015, we have federal tax net operating loss carryforwards and alternative minimum tax credits as follows: ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) ​ ​ ​ ​ ​ ​ ​ ​ Expiration Date Alternative Minimum Tax Credits NOLs ​ ​ ​ ​ ​ ​ ​ ​ 2018 $ – $ 2019 – 2020 – None – ​ ​ ​ ​ ​ ​ ​ ​ $ $ ​ ​ ​ ​ ​ ​ ​ ​ The net operating loss expiration dates start in the year 2018 and end in the year 2020. Due to the tax basis method for allocating patronage and as shown by the above valuation allowance, it is not more likely than not that the deferred tax asset to the net operating losses will be realized. On December 18, 2015, the President signed into law the Protecting Americans from Tax Hikes Act of 2015. The law extends to ability for us to make an election to accelerate AMT credits in lieu of bonus depreciation through 2019. We intend to make this election for tax years ended December 31, 2015 through December 31, 2017 and expect to monetize the entire balance of tax credits by the tax year ended December 31, 2017. The authoritative guidance for income taxes addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. We may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. We file a U.S. federal consolidated income tax return. The U.S. federal statute of limitations remains open for the year 2012 forward. State jurisdictions have statutes of limitations generally ranging from three to five years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by tax authorities in major state jurisdictions include 2012 forward. We have no liabilities recorded for uncertain tax positions. |
Capital leases_
Capital leases: | 12 Months Ended |
Dec. 31, 2015 | |
Capital leases: | |
Capital leases: | 6. Capital leases: In 1985, we sold and subsequently leased back from four purchasers their 60% undivided ownership interest in Scherer Unit No. 2. The gain from the sale is being amortized over the terms of the leases. Three of the leases have lease terms through December 31, 2027, and one lease extends through June 30, 2031. The assumed interest rate at inception on the lease obligation is 11.05%. The minimum lease payments under the capital leases together with the present value of the net minimum lease payments as of December 31, 2015 are as follows: ​ ​ ​ ​ ​ Year Ending December 31, (dollars in thousands) ​ ​ ​ ​ ​ Scherer Unit No. 2 ​ ​ ​ ​ ​ 2016 $ 2017 2018 2019 2020 2021-2031 ​ ​ ​ ​ ​ Total minimum lease payments Less: Amount representing interest ) ​ ​ ​ ​ ​ Present value of net minimum lease payments Less: Current portion ) ​ ​ ​ ​ ​ Long-term balance $ ​ ​ ​ ​ ​ The Scherer No. 2 lease is reported as a capital lease. For rate-making purposes, however, we include the actual lease payments in our cost of service. The difference between lease payments and the aggregate of the amortization on the capital lease asset and the interest on the capital lease obligation is recognized as a regulatory asset or regulatory liability on the consolidated balance sheet. Capital lease amortization is recorded in depreciation and amortization expense. In 2000, we entered into a power purchase and sale agreement with Doyle I, LLC (Doyle Agreement), an affiliate of one of our members, to purchase all of the output from a five-unit generation facility (Doyle) for a period of 15 years, through August 24, 2015. We exercised our purchase option and acquired the facility on August 24, 2015. |
Debt_
Debt: | 12 Months Ended |
Dec. 31, 2015 | |
Debt: | |
Debt: | 7. Debt: Long-term debt consists of first mortgage notes payable to the United States of America acting through the Federal Financing Bank (FFB) and guaranteed by the Rural Utilities Service or the U.S. Department of Energy, first mortgage bonds payable (FMBs), first mortgage notes issued in conjunction with the sale by public authorities of pollution control revenue bonds (PCBs) and first mortgage notes payable to CoBank and CFC. Substantially all of our owned tangible and certain of our intangible assets are pledged under our first mortgage indenture as collateral for the Federal Financing Bank notes, the first mortgage bonds, the first mortgage notes issued in conjunction with the sale of pollution control revenue bonds, and the CoBank and CFC first mortgage notes. Maturities for long-term debt and capital lease obligations through 2020 are as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2016 2017 2018 2019 2020 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ FFB $ $ $ $ $ FMBs PCBs (1) – CFC CoBank – ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Capital Leases ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) In addition to regularly scheduled principal payments on the bonds, this includes amounts that would be due if the credit support facilities for the Series 2009 and Series 2010 pollution control bonds were drawn upon and became payable in accordance with their terms, such as would occur if the credit facility providing the support was not renewed or extended at its expiration date. These amounts equal $37 million in each of the years 2016, 2017 and 2018 and $134 million in 2020. We anticipate extending these credit facilities before their expiration. The nominal maturities of the Series 2009 and Series 2010 pollution control bonds range from 2030 through 2038. The weighted average interest rate on our long-term debt at December 31, 2015 and 2014 was 4.45% and 4.55%, respectively. Long-term debt principal and the associated unamortized debt issuance costs and debt discounts at December 31, 2015 and December 31, 2014 are as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2015 2014 Principal Unamortized Debt Issuance Costs and Debt Discounts Principal Unamortized Debt Issuance Costs and Debt Discounts ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) FFB $ $ $ $ FMBs PCBs CFC – – CoBank – – ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ We use the effective interest rate method to amortize debt issuance costs and debt discounts as well as the straight-line method when the results approximate those of the effective interest rate method. Unamortized debt issuance costs and debt discounts are being amortized to expense over the life of the respective debt issues. a) Department of Energy Loan Guarantee: Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005 (the "Title XVII Loan Guarantee Program"), we and the U.S. Department of Energy, acting by and through the Secretary of Energy, entered into a Loan Guarantee Agreement on February 20, 2014 pursuant to which the Department of Energy agreed to guarantee our obligations under the Note Purchase Agreement dated as of February 20, 2014 (the "Note Purchase Agreement"), among us, the Federal Financing Bank and the Department of Energy and two future advance promissory notes, each dated February 20, 2014, made by us to the Federal Financing Bank (the "Federal Financing Bank Notes" and together with the Note Purchase Agreement, the "FFB Credit Facility Documents"). The FFB Credit Facility Documents provide for a multi-advance term loan facility (the "Facility"), under which we may make long-term loan borrowings through the Federal Financing Bank. Proceeds of advances made under the Facility will be used to reimburse us for a portion of certain costs of construction relating to Vogtle Units No. 3 and No. 4 that are eligible for financing under the Title XVII Loan Guarantee Program. Aggregate borrowings under the Facility may not exceed $3,057,069,461 of which $335,471,604 is designated for capitalized interest. Advances may be requested under the Facility on a quarterly basis through December 31, 2020. During 2015, we received advances under the Facility totaling $270,000,000. At December 31, 2015, aggregate DOE-guaranteed borrowings totaled $1,180,628,000, including capitalized interest. b) Rural Utilities Service Guaranteed Loans: During 2015, we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling $153,637,000 for long-term financing of general and environmental improvements at existing plants. In January 2016, we received an additional $7,998,000 in advances on Rural Utilities Service-guaranteed Federal Financing Bank loans for long-term financing of general and environmental improvements at existing plants. c) Credit Facilities: On March 23, 2015, we entered into a 5-year $1,210,000,000 credit agreement with a syndicate of thirteen lenders, led by the National Rural Utilities Cooperative Finance Corporation as administrative agent. As of December 31, 2015, we had a total of $1,610,000,000 of committed credit arrangements comprised of four separate facilities with maturity dates that range from November 2016 to March 2020. These credit facilities are for general working capital purposes, issuing letters of credit and backing up outstanding commercial paper. Under our unsecured committed lines of credit that we had in place at December 31, 2015, we had the ability to issue letters of credit totaling $760,000,000 in the aggregate, of which $509,000,000 remained available. At December 31, 2015, we had 1) $251,000,000 under these lines of credit in the form of issued letters of credit supporting variable rate demand bonds and collateral postings to third parties, and 2) $261,000,000 dedicated under one of these lines of credit to support a like amount of commercial paper that was outstanding. The weighted average interest rate on short-term borrowings at December 31, 2015 and December 31, 2014 was 0.43% and 0.28%, respectively. |
Electric plant, construction an
Electric plant, construction and related agreements: | 12 Months Ended |
Dec. 31, 2015 | |
Electric plant, construction and related agreements: | |
Electric plant, construction and related agreements: | 8. Electric plant, construction and related agreements: a. Electric plant We, along with Georgia Power, have entered into agreements providing for the purchase and subsequent joint operation of certain electric generating plants. Each co-owner is responsible for providing its' own financing. The plant investments disclosed in the table below represent our undivided interest in each plant. A summary of our plant investments and related accumulated depreciation as of December 31, 2015 and 2014 is as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2015 2014 (dollars in thousands) Plant Investment Accumulated Depreciation Investment Accumulated Depreciation ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ In-service (1) Owned property Vogtle Units No. 1 & No. 2 (Nuclear – 30% ownership) $ $ ) $ $ ) Vogtle Units No. 3 & No. 4 (Nuclear – 30% ownership) ) ) Hatch Units No. 1 & No. 2 (Nuclear – 30% ownership) ) ) Wansley Units No. 1 & No. 2 (Fossil – 30% ownership) ) ) Scherer Unit No. 1 (Fossil – 60% ownership) ) ) Doyle (Combustion Turbine – 100% leasehold) (2) ) ) Rocky Mountain Units No. 1, No. 2 & No. 3 (Hydro – 75% ownership) ) ) Hartwell (Combustion Turbine – 100% ownership) ) ) Hawk Road (Combustion Turbine – 100% ownership) ) ) Talbot (Combustion Turbine – 100% ownership) ) ) Chattahoochee (Combined cycle – 100% ownership) ) ) Smith (Combined cycle – 100% ownership) ) ) Wansley (Combustion Turbine – 30% ownership) ) ) Transmission plant ) ) Other ) ) Property under capital lease: Scherer Unit No. 2 (Fossil – 60% leasehold) ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total in-service $ $ ) $ $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Construction work in progress Vogtle Units No. 3 & No. 4 $ $ Environmental and other generation improvements Other ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total construction work in progress $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) Amounts include plant acquisition adjustments at December 31, 2015 and 2014 of $196,000,000. (2) On August 20, 2015, we acquired Doyle which we previously operated under a capital lease. Our proportionate share of direct expenses of joint operation of the above plants is included in the corresponding operating expense captions (e.g., fuel, production) on the accompanying Statement of Revenues and Expenses. b. Construction In 2008, Georgia Power, acting for itself and as agent for us, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, doing business as Dalton Utilities (collectively, the Co-owners) and Westinghouse Electric Company LLC and Stone & Webster, Inc. (collectively, the Contractor) entered into an Engineering, Procurement and Construction Agreement (the EPC Agreement). Pursuant to the EPC Agreement, the Contractor will design, engineer, procure, construct and test two 1,100 megawatt nuclear units using the Westinghouse AP1000 technology and related facilities at Plant Vogtle Units No. 3 and No. 4. Our ownership interest and proportionate share of the cost to construct these units is 30%. Under the EPC Agreement, the Co-owners will pay a purchase price that is subject to certain price escalations and adjustments, including fixed escalation amounts and certain index-based adjustments, as well as adjustments for change orders and performance bonuses. The EPC Agreement also provides for liquidated damages upon the Contractor's failure to fulfill the schedule and performance guarantees, subject to a cap. In addition, the EPC Agreement provides for limited cost sharing by the Co-owners for increases to Contractor costs under certain conditions. The maximum amount of additional capital costs under this provision attributable to us is $75,000,000. Each Co-owner is severally, not jointly, liable to the Contractor for its proportionate share, based on ownership interest, of all amounts owed under the EPC Agreement. As agent for the Co-owners, Georgia Power has designated Southern Nuclear Operating Company as its agent for contract management. On December 31, 2015, Westinghouse acquired Stone & Webster, Inc. from Chicago Bridge & Iron Co. N.V. (the Acquisition). In connection with the Acquisition, Stone & Webster, Inc. changed its name to WECTEC Global Project Services Inc. (WECTEC). Certain obligations of Westinghouse and Stone & Webster, Inc. have been guaranteed by Toshiba Corporation, Westinghouse's parent company, and The Shaw Group Inc., a subsidiary of Chicago Bridge & Iron, respectively. On March 9, 2016, in connection with the Acquisition and pursuant to the settlement agreement described below, the guarantee of The Shaw Group was terminated. The guarantee of Toshiba remains in place. Additionally, as a result of recent credit rating downgrades of Toshiba, Westinghouse has provided the Co-owners with letters of credit of approximately of $900,000,000 in accordance with, and subject to adjustment under, the terms of the EPC Agreement. In the event of certain credit rating downgrades of any Co-owner, such Co-owner will be required to provide a letter of credit or other credit enhancement. The Co-owners may terminate the EPC Agreement at any time for their convenience, provided that the Co-owners will be required to pay certain termination costs. The Contractor may also terminate the EPC Agreement under certain circumstances, including certain suspension or delays of work by the Co-owners, action by a governmental authority to stop work permanently, certain breaches of the EPC Agreement by the Co-owners, Co-owner insolvency, and certain other events. The Nuclear Regulatory Commission certified the Westinghouse AP1000 Design Control Document (DCD) in late 2011. In early 2012, the Nuclear Regulatory Commission issued combined construction and operating licenses for Vogtle Units No. 3 and No. 4 which allowed full construction to begin. There have been technical and procedural challenges to the construction and licensing of Vogtle Units No. 3 and No. 4 at the federal and state levels, and additional challenges may arise as construction proceeds. In 2012, the Co-owners and the Contractor commenced litigation regarding the costs associated with design changes to the DCD and the delays in the timing of approval of the DCD and issuance of the combined construction and operating licenses, including the assertion by the Contractor that the Co-owners are responsible for these costs under the terms of the EPC Agreement. The Contractor also asserted that it was entitled to extensions of the guaranteed substantial completion dates of April 2016 and April 2017 for Vogtle Units No. 3 and No. 4, respectively. In May 2014, the Contractor filed an amended claim alleging that (i) the design changes to the DCD imposed by the Nuclear Regulatory Commission delayed module production and the impacts to the Contractor are recoverable by the Contractor under the EPC Agreement and (ii) the changes to the basemat rebar design required by the Nuclear Regulatory Commission caused additional costs and delays recoverable by the Contractor under the EPC Agreement. In June 2015, the Contractor updated its estimated damages, based on our ownership interest, to an aggregate of approximately $470,000,000 (in 2015 dollars). The case was pending in the U.S. District Court for the Southern District of Georgia (the Vogtle Construction Litigation). On December 31, 2015, Westinghouse and the Co-owners entered into a definitive settlement agreement (the Settlement Agreement) to resolve disputes between the Co-owners and the Contractor under the EPC Agreement, including the Vogtle Construction Litigation. Effective December 31, 2015, Georgia Power, acting for itself and as agent for the other Co-owners, and the Contractor entered into an amendment to the EPC Agreement to implement the Settlement Agreement. The Settlement Agreement and the related amendment to the EPC Agreement (i) restrict the Contractor's ability to seek further increases in the contract price by clarifying and limiting the circumstances that constitute nuclear regulatory changes in law; (ii) provide for enhanced dispute resolution procedures; (iii) revise the guaranteed substantial completion dates to match the currently estimated in-service dates of June 30, 2019 for Unit No. 3 and June 30, 2020 for Unit No. 4; (iv) provide that delay liquidated damages will now commence from the currently estimated nuclear fuel loading date for each unit, which is December 31, 2018 for Unit No. 3 and December 31, 2019 for Unit No. 4, rather than the original guaranteed substantial completion dates under the EPC Agreement; and (v) provide that we, based on our ownership interest, will pay to the Contractor and capitalize to the project cost approximately $230,000,000, of which we have paid (a) approximately $80,000,000 prior to the Settlement Agreement under the dispute resolution procedures of the EPC Agreement and (b) approximately $80,000,000 subsequent to December 31, 2015 under the terms of the Settlement Agreement. In addition, the Settlement Agreement provides for the resolution of other open existing items relating to the scope of the project under the EPC Agreement, including cyber security. Further, as part of the settlement and in connection with the Acquisition: (i) Westinghouse has engaged Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, as a new construction subcontractor; and (ii) the Co-owners, Chicago Bridge & Iron, and The Shaw Group have entered into mutual releases of any and all claims arising out of events or circumstances in connection with the construction of Vogtle Units No. 3 and No. 4 that occurred on or before December 31, 2015. On January 5, 2016, the Vogtle Construction Litigation was dismissed with prejudice. Our previously disclosed project budget, which includes capital costs, allowance for funds used during construction and a contingency amount, is $5,000,000,000, even after payments contemplated by the Settlement Agreement. As of December 31, 2015, our total investment in the additional Vogtle units was $2,888,000,000. Processes are in place that are designed to assure compliance with the requirements specified in the DCD and the combined construction and operating licenses, including inspections by Southern Nuclear and the Nuclear Regulatory Commission that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the Nuclear Regulatory Commission. Various design and other licensing-based compliance issues may arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be further delays in the project schedule that could result in increased costs to the Co-owners, the Contractor, or both. In addition, as construction continues, the risk remains that challenges with the Contractor's performance including additional challenges in its fabrication, assembly, delivery, and installation of the shield building and structural modules could further impact the revised forecasted completion dates and cost and the Contractor must improve its schedule performance in order to mitigate this risk. Also, delays in the receipt of the remaining permits necessary for the operation of Vogtle Units No. 3 and No. 4 or other issues could arise and may further impact the project schedule and cost. Future claims by the Contractor or Georgia Power, on behalf of the Co-owners, could arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the EPC Agreement and, under the enhanced dispute resolution procedures, may be resolved through litigation after the completion of nuclear fuel load for both units. The ultimate outcome of these matters cannot be determined at this time. |
Employee benefit plans_
Employee benefit plans: | 12 Months Ended |
Dec. 31, 2015 | |
Employee benefit plans: | |
Employee benefit plans: | 9. Employee benefit plans: Our retirement plan is a contributory 401(k) that covers substantially all employees. An employee may contribute, subject to IRS limitations, up to 60% of his or her eligible annual compensation. At our discretion, we may match the employee's contribution and have done so each year of the plan's existence. Our current policy is to match the employee's contribution as long as there is sufficient margin to do so. The match, which is calculated each pay period, currently can be equal to as much as three-quarters of the first 6% of an employee's eligible compensation, depending on the amount and timing of the employee's contribution. Our contributions to the matching feature of the plan were approximately $1,310,000, $1,205,000 and $1,161,000 in 2015, 2014 and 2013, respectively. Our 401(k) plan also includes an employer retirement contribution feature, which subject to IRS limitations, contributes 8% of an employee's eligible annual compensation. Our contributions to the employer retirement contribution feature of the 401(k) plan were approximately $2,611,000, $2,441,000 and $2,289,000 in 2015, 2014 in 2013, respectively. |
Nuclear insurance_
Nuclear insurance: | 12 Months Ended |
Dec. 31, 2015 | |
Nuclear insurance: | |
Nuclear insurance: | 10. Nuclear insurance: The Price-Anderson Act limits public liability claims that could arise from a single nuclear incident to $13,500,000,000. This amount is covered by private insurance and a mandatory program of deferred premiums that could be assessed against all owners of nuclear power reactors. Such private insurance provided by American Nuclear Insurers (ANI), is carried by Georgia Power for the benefit of all the co-owners of Plants Hatch and Vogtle. Agreements of indemnity have been entered into by and between each of the co-owners and the NRC. In the event of a nuclear incident involving any commercial nuclear facility in the country involving total public liability in excess of $375,000,000, a licensee of a nuclear power plant could be assessed a deferred premium of up to $127,000,000 per incident for each licensed reactor operated by it, but not more than $19,000,000 per reactor per incident to be paid in a calendar year. On the basis of our ownership interest in four nuclear reactors, we could be assessed a maximum of $152,000,000 per incident, but not more than $23,000,000 in any one year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years, and exclude any applicable state premium taxes. The next scheduled adjustment is due no later than September 10, 2018. Georgia Power, on behalf of all the co-owners of Plants Hatch and Vogtle, is a member of Nuclear Electric Insurance, Ltd. (NEIL), a mutual insurer established to provide property damage insurance coverage in an amount up to $1,500,000,000 for members' operating nuclear generating facilities. Additionally, there is coverage through NEIL for decontamination, excess property insurance, and premature decommissioning coverage up to $1,250,000,000 for nuclear losses in excess of the $1,500,000,000 primary coverage. On April 1, 2014, NEIL introduced a new excess non-nuclear policy providing coverage up to $750,000,000 for non-nuclear losses in excess of the $1,500,000,000 primary coverage. Georgia Power, on behalf of all the co-owners has purchased a builders' risk property insurance policy from NEIL for Vogtle Units No. 3 and No. 4. This policy provides $2,750,000,000 in limits for accidental property damage occurring during construction. Under each of the NEIL policies, members are subject to retroactive assessments in proportion to their premiums, if losses each year exceed the accumulated reserve funds available to the insurer. The portion of the current maximum annual assessment for Georgia Power that would be payable by Oglethorpe based on ownership share, is limited to approximately $41,000,000. Claims resulting from terrorist acts are covered under both the ANI and NEIL policies (subject to normal policy limits). The aggregate, however, that NEIL will pay for all claims resulting from terrorist acts in any 12-month period is $3,200,000,000 plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources. For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are next to be applied toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to Georgia Power, for the benefit of all the co-owners, or to bond trustees as may be appropriate under the policies and applicable trust indentures. All retrospective assessments, whether generated for liability or property, may be subject to applicable state premium taxes. In the event of a loss, the amount of insurance available may not be adequate to cover property damage and other incurred expenses. Uninsured losses and other expenses could have a material adverse effect on our financial condition and results of operations. |
Commitments_
Commitments: | 12 Months Ended |
Dec. 31, 2015 | |
Commitments: | |
Commitments: | 11. Commitments: a. Operating leases As of December 31, 2015, our estimated minimum rental commitments for our railcar leases for use at our coal-fired facilities over the next five years and thereafter are as follows: ​ ​ ​ ​ ​ (dollars in thousands) ​ ​ ​ ​ ​ 2016 $ 2017 2018 2019 2020 Thereafter – ​ ​ ​ ​ ​ The rental expenses for the railcar leases are added to the cost of the fossil inventories and are recognized in fuel expense. Rental expenses totaled $4,849,000, $5,139,000 and $5,213,000 in 2015, 2014 and 2013, respectively. b. Fuel To supply a portion of the fuel requirements to our generating units, Southern Nuclear on our behalf for nuclear fuel, and Georgia Power, on our behalf for coal, have entered into various long-term commitments for the procurement of coal and nuclear fuel. The contracts in most cases contain provision for price escalations, minimum and maximum purchase levels and other financial commitments. The value of the coal commitments is based on maximum coal prices and minimum volumes as provided in the contracts and does not include taxes, transportation, government impositions or railcar costs. For further discussion of total nuclear fuel expense, see Note 1h. As of December 31, 2015, our estimated minimum long-term commitments are as follows: ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Coal Nuclear Fuel ​ ​ ​ ​ ​ ​ ​ ​ 2016 $ $ 2017 2018 2019 – 2020 – Thereafter – ​ ​ ​ ​ ​ ​ ​ ​ |
Contingencies and Regulatory Ma
Contingencies and Regulatory Matters: | 12 Months Ended |
Dec. 31, 2015 | |
Contingencies and Regulatory Matters: | |
Contingencies and Regulatory Matters: | 12. Contingencies and Regulatory Matters: We do not anticipate that the liabilities, if any, for any current proceedings against us will have a material effect on our financial condition or results of operations. However, at this time, the ultimate outcome of any pending or potential litigation cannot be determined. a. Nuclear Construction In 2012, the Co-owners and the Contractor commenced litigation regarding the costs associated with design changes to the DCD and the delays in the timing of approval of the DCD and issuance of the combined construction and operating licenses, including the assertion by the Contractor that the Co-owners are responsible for these costs under the terms of the EPC Agreement. The Contractor also asserted that it was entitled to extensions of the guaranteed substantial completion dates of April 2016 and April 2017 for Vogtle Units No. 3 and No. 4, respectively. In May 2014, the Contractor filed an amended claim alleging that (i) the design changes to the DCD imposed by the Nuclear Regulatory Commission delayed module production and the impacts to the Contractor are recoverable by the Contractor under the EPC Agreement and (ii) the changes to the basemat rebar design required by the Nuclear Regulatory Commission caused additional costs and delays recoverable by the Contractor under the EPC Agreement. In June 2015, the Contractor updated its estimated damages, based on our ownership interest, to an aggregate of approximately $470,000,000 (in 2015 dollars). The Vogtle Construction Litigation was pending in the U.S. District Court for the Southern District of Georgia. On December 31, 2015, Westinghouse and the Co-owners entered into the Settlement Agreement to resolve disputes between the Co-owners and the Contractor under the EPC Agreement, including the Vogtle Construction Litigation. Effective December 31, 2015, Georgia Power, acting for itself and as agent for the other Co-owners, and the Contractor entered into an amendment to the EPC Agreement to implement the Settlement Agreement. The Settlement Agreement and the related amendment to the EPC Agreement (i) restrict the Contractor's ability to seek further increases in the contract price by clarifying and limiting the circumstances that constitute nuclear regulatory changes in law; (ii) provide for enhanced dispute resolution procedures; (iii) revise the guaranteed substantial completion dates to match the currently estimated in-service dates of June 30, 2019 for Unit No. 3 and June 30, 2020 for Unit No. 4; (iv) provide that delay liquidated damages will now commence from the currently estimated nuclear fuel loading date for each unit, which is December 31, 2018 for Unit No. 3 and December 31, 2019 for Unit No. 4, rather than the original guaranteed substantial completion dates under the EPC Agreement; and (v) provide that we, based on our ownership interest, will pay to the Contractor and capitalize to the project cost approximately $230,000,000, of which we have paid (a) approximately $80,000,000 prior to the Settlement Agreement under the dispute resolution procedures of the EPC Agreement and (b) approximately $80,000,000 subsequent to December 31, 2015 under the terms of the Settlement Agreement. In addition, the Settlement Agreement provides for the resolution of other open existing items relating to the scope of the project under the EPC Agreement, including cyber security. Further, as part of the settlement and in connection with the Acquisition: (i) Westinghouse has engaged Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, as a new construction subcontractor; and (ii) the Co-owners, Chicago Bridge & Iron, and The Shaw Group have entered into mutual releases of any and all claims arising out of events or circumstances in connection with the construction of Vogtle Units No. 3 and No. 4 that occurred on or before December 31, 2015. On January 5, 2016, the Vogtle Construction Litigation was dismissed with prejudice. Future claims by the Contractor or Georgia Power, on behalf of the Co-owners, could arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the EPC Agreement and, under the enhanced dispute resolution procedures, may be resolved through litigation after the completion of nuclear fuel load for both units. b. Patronage Capital Litigation On March 13, 2014, a lawsuit was filed in the Superior Court of DeKalb County, Georgia, against us, Georgia Transmission and three of our member distribution cooperatives. Plaintiffs filed an amended complaint on July 28, 2014. The amended complaint challenges the patronage capital distribution practices of Georgia's electric cooperatives and seeks to certify a defendant class of all but one of our 38 members. It was filed by four former consumer-members of four of our members on behalf of themselves and a proposed class of all former consumer-members of our members. Plaintiffs claim that approximately 30% of all the defendants' total allocated patronage capital belongs to former consumer-members. Plaintiffs also allege that patronage capital owed to former consumer-members includes patronage capital allocated by us to our members but not yet distributed to our members. Plaintiffs claim that the patronage capital of former consumer-members held by defendants and the proposed defendant class should be retired immediately when the consumer-members end their membership by terminating service, or alternatively, according to a revolving schedule of no longer than 13 years from the date of its allocation and seek relief to effect such retirements. Plaintiffs further seek to require the defendants to adjust rates in order to establish and maintain reasonable reserves to fund patronage capital retirements on this basis. Plaintiffs also claim that defendants and the proposed defendant class should be required to adopt policies to periodically retire the patronage capital of all consumer-members on a revolving schedule of no longer than 13 years from the date of its allocation. Our first mortgage indenture restricts our ability to distribute patronage capital. Although not expected, if we were ordered by the Court to make distributions of our patronage capital, our first mortgage indenture would require us to raise our rates to a level sufficient so that we could comply with the current patronage capital distribution restrictions, and the rate increases required to meet the Plaintiffs' demands would be significant for a period of years. On August 20, 2014, a second patronage capital lawsuit was filed in the Superior Court of DeKalb County against us, Georgia Transmission, and two of our member distribution cooperatives. The case was filed by two current consumer-members of the two member distribution cooperatives named in the lawsuit. Similar to the above described litigation, this complaint challenges the patronage capital distribution practices of Georgia's electric cooperatives; however, one notable difference is that the first case, described above, seeks to bring claims on behalf of former members while this second case seeks to bring claims on behalf of current members. The plaintiffs allege that the defendants have (i) retained patronage capital for an unreasonably long period of time; (ii) conspired with each other to deprive consumer-members of their patronage capital; and (iii) breached bylaw provisions allegedly requiring that patronage capital be retired when the financial condition of the cooperative will not be impaired. The plaintiffs seek unspecified damages and equitable relief, including an order declaring that the defendants be required to retire patronage capital "according to a regular, reasonable revolving plan." Similarly to the litigation described above, although not expected, if we were ordered by the Court to make distributions of our patronage capital, our first mortgage indenture would require us to raise our rates to a level where we could comply with current patronage capital distribution restrictions, and the rate increases required to meet the Plaintiff's demands could be significant for a period of years. The plaintiffs seek to certify three plaintiffs' classes but do not seek to certify a defendants' class. In May 2015, the Superior Court judge for both patronage capital lawsuits appointed a special master to oversee all pre-trial issues relating to these cases, including motions to dismiss that we and the other defendants filed in connection with each lawsuit. In September, the special master issued proposed orders to the judge to grant our and the other defendants' motions to dismiss both patronage capital lawsuits on all counts. These orders have been challenged by the plaintiffs and remain subject to approval by the Court. If approved, the Court's decision to grant the motions to dismiss will be subject to appeal. We intend to defend vigorously against all claims in the above-described litigation. c. Environmental Matters As is typical for electric utilities, we are subject to various federal, state and local environmental laws which represent significant future risks and uncertainties. Air emissions, water discharges and water usage are extensively controlled, closely monitored and periodically reported. Handling and disposal requirements govern the manner of transportation, storage and disposal of various types of waste. We are also subject to climate change regulations that impose restrictions on emissions of greenhouse gases, including carbon dioxide, for certain new and modified facilities. In general, these and other types of environmental requirements are becoming increasingly stringent. Such requirements may substantially increase the cost of electric service, by requiring modifications in the design or operation of existing facilities or the purchase of emission allowances. Failure to comply with these requirements could result in civil and criminal penalties and could include the complete shutdown of individual generating units not in compliance. Certain of our debt instruments require us to comply in all material respects with laws, rules, regulations and orders imposed by applicable governmental authorities, which include current and future environmental laws or regulations. Should we fail to be in compliance with these requirements, it would constitute a default under those debt instruments. We believe that we are in compliance with those environmental regulations currently applicable to our business and operations. Although it is our intent to comply with current and future regulations, we cannot provide assurance that we will always be in compliance. At this time, the ultimate impact of any new and more stringent environmental regulations described above is uncertain and could have an effect on our financial condition, results of operations and cash flows as a result of future additional capital expenditures and increased operations and maintenance costs. Additionally, litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has increased generally throughout the United States. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief, personal injury and property damage allegedly caused by coal combustion residue, greenhouse gas and other emissions have become more frequent. |
Purchase Agreements_
Purchase Agreements: | 12 Months Ended |
Dec. 31, 2015 | |
Purchase Agreements: | |
Purchase Agreements: | 13. Purchase Agreements: On April 11, 2014, we signed a precedent agreement with Transcontinental Gas Pipeline Company, LLC (Transco) for additional firm natural gas transportation to our Smith facility. The additional firm transportation is contingent upon the construction of a new natural gas pipeline by Transco. Total fixed charges over the 25-year base term will be approximately $942,500,000. Our obligation to make payments begins when the pipeline expansion project is placed into service, which is projected to be May 1, 2017. |
Quarterly financial data (unaud
Quarterly financial data (unaudited): | 12 Months Ended |
Dec. 31, 2015 | |
Quarterly financial data (unaudited): | |
Quarterly financial data (unaudited): | 14. Quarterly financial data (unaudited): Summarized quarterly financial information for 2015 and 2014 is as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ First Quarter Second Quarter Third Quarter Fourth Quarter ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2015 Operating revenues $ $ $ $ Operating margin Net margin 2014 Operating revenues $ $ $ $ Operating margin Net margin ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ The decrease in net margin in the fourth quarter of 2015 and the negative net margins in the fourth quarter of 2014 were due to reductions to revenue requirements in order to achieve the targeted margins for interest ratio of 1.14. |
Summary of significant accoun23
Summary of significant accounting policies: (Policies) | 12 Months Ended |
Dec. 31, 2015 | |
Summary of significant accounting policies: | |
Business description | a. Business description Oglethorpe Power Corporation is an electric membership corporation incorporated in 1974 and headquartered in metropolitan Atlanta, Georgia that operates on a not-for-profit basis. We are owned by 38 retail electric distribution cooperative members in Georgia. We provide wholesale electric power from a combination of owned and co-owned generating units of which our ownership share totals 7,067 megawatts of summer planning reserve capacity. We also manage and operate Smarr EMC which owns 718 megawatts of summer planning reserve capacity. Georgia Power Company is a co-owner and the operating agent of our nuclear and coal-fired generating units. Our members in turn distribute energy on a retail basis to approximately 4.2 million people. |
Basis of accounting | b. Basis of accounting Our consolidated financial statements include our accounts and the accounts of our majority-owned and controlled subsidiary. We have determined that there are no accounts of variable interest entities for which we are the primary beneficiary. We have eliminated any intercompany profits and transactions in consolidation. We follow generally accepted accounting principles in the United States. We maintain our accounts in accordance with the Uniform System of Accounts of the Federal Energy Regulatory Commission as modified and adopted by the Rural Utilities Service. We also apply the accounting guidance for regulated operations. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of December 31, 2015 and 2014 and the reported amounts of revenues and expenses for each of the three years in the period ended December 31, 2015. Actual results could differ from those estimates. Certain reclassifications have been made to prior periods to conform to the current period presentation. For the year ended December 31, 2014, we made an adjustment of $24,607,000 in the Consolidated Statement of Cash Flows to decrease other adjustments to reconcile net margin to net cash provided by operating activities and decrease cash paid for property additions. This adjustment reflects the non-cash nature of the allowance for debt funds used during construction related to interest paid-in-kind associated with loans under our Department of Energy Loan Guarantee. The change properly reflects an immaterial adjustment to cash flows provided by operations and cash used in investing activities, and is consistent with the 2015 presentation. |
Patronage capital and membership fees | c. Patronage capital and membership fees We are organized and operate as a cooperative. Our members paid a total of $190 in membership fees. Patronage capital includes retained net margin. Any excess of revenues over expenditures from operations is treated as an advance of capital by our members and is allocated to each member on the basis of their fixed percentage capacity cost responsibilities in our generation. Any distributions of patronage capital are subject to the discretion of our board of directors, subject to first mortgage indenture requirements. Under our first mortgage indenture, we are prohibited from making any distribution of patronage capital to our members if, at the time of or after giving effect to, (i) an event of default exists under the indenture, (ii) our equity as of the end of the immediately preceding fiscal quarter is less than 20% of our total long-term debt and equities, or (iii) the aggregate amount expended for distributions on or after the date on which our equity first reaches 20% of our total long-term debt and equities exceeds 35% of our aggregate net margins earned after such date. This last restriction, however will not apply if, after giving effect to such distribution, our equity as of the end of the immediately preceding fiscal quarter is not less than 30% of our long-term debt and equities. |
Accumulated other comprehensive margin (deficit) | d. Accumulated other comprehensive margin (deficit) The table below provides detail regarding the beginning and ending balance for each classification of other comprehensive margin (deficit) along with the amount of any reclassification adjustments included in net margin for each of the years presented in the Statement of Patronage Capital and Membership Fees and Accumulated Other Comprehensive Margin (Deficit). Our effective tax rate is zero; therefore, all amounts below are presented net of tax. ​ ​ ​ ​ ​ Accumulated Other Comprehensive Margin (Deficit) (dollars in thousands) Available-for-sale Securities ​ ​ ​ ​ ​ Balance at December 31, 2012 $ Unrealized loss ) (Gain) reclassified to net margin ) ​ ​ ​ ​ ​ Balance at December 31, 2013 ) Unrealized gain (Gain) reclassified to net margin ) ​ ​ ​ ​ ​ Balance at December 31, 2014 Unrealized gain (Gain) reclassified to net margin ) ​ ​ ​ ​ ​ Balance at December 31, 2015 $ ​ ​ ​ ​ ​ |
Margin policy | e. Margin policy We are required under our first mortgage indenture to produce a margins for interest ratio of at least 1.10 for each fiscal year. For the years 2015, 2014 and 2013, we achieved a margins for interest ratio of 1.14. |
Operating revenues | f. Operating revenues Electricity revenues are recognized when capacity and energy are provided. Operating revenues from sales to members consist primarily of electricity sales pursuant to long-term wholesale power contracts which we maintain with each of our members. These wholesale power contracts obligate each member to pay us for capacity and energy furnished in accordance with rates we establish. Capacity revenues recover our fixed costs plus a targeted margin and are charged regardless of whether our generation and purchased power resources are dispatched to produce electricity. Capacity revenues are based on an annual budget and, notwithstanding budget adjustments to meet our targeted margin, are recorded in approximately equal amounts throughout the year. Energy revenues recover variable costs, such as fuel, incurred to generate or purchase electricity and are recorded such that energy revenues equal the actual energy costs incurred. Operating revenues from sales to non-members consist primarily of capacity and energy sales at Smith. Energy sales accounted for a substantial portion of our sales to non-members in 2015, 2014 and 2013. The following table reflects members whose revenues accounted for 10% or more of our total operating revenues in 2015, 2014 or 2013: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2015 2014 2013 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Cobb EMC % % % Sawnee EMC % % % Jackson EMC % % % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ We have two rate management programs that allow us to expense and recover certain costs on a current basis that would otherwise be deferred or capitalized. The subscribing members of Smith and/or Vogtle Units No. 3 and No. 4, can elect to participate in one, both or neither of these two programs on an annual basis. The Smith program allows for the accelerated recovery of deferred net costs related to Smith. The Vogtle program allows for the recovery of financing costs associated with the construction of Vogtle Units No. 3 and No. 4 on a current basis. Under these programs, amounts billed to participating members in 2015, 2014 and 2013 were $25,375,000, $14,991,000 and $13,962,000, respectively. |
Receivables | g. Receivables A substantial portion of our receivables are related to electricity sales to our members. These receivables are recorded at the invoiced amount and do not bear interest. Our members are required through the wholesale power contracts to reimburse us for all costs. Member receivables at December 31, 2015 and 2014 were $108,729,000 and $114,808,000, respectively. The remainder of our receivables is primarily related to transactions with affiliated companies, electricity sales to non-members and to interest income on investments. Uncollectible amounts, if any, are identified on a specific basis and charged to expense in the period the amounts are determined to be uncollectible. |
Nuclear fuel cost | h. Nuclear fuel cost The cost of nuclear fuel is being amortized to fuel expense based on usage. The total nuclear fuel expense for 2015, 2014 and 2013 amounted to $78,762,000, $85,166,000, and $86,828,000, respectively. Contracts with the U.S. Department of Energy have been executed to provide for the permanent disposal of spent nuclear fuel produced at Hatch and Vogtle. The Department of Energy failed to begin disposing of spent fuel in January 1998 as required by the contracts, and Georgia Power, as agent for the co-owners of the plants has pursued and continues to pursue legal remedies against the Department of Energy for breach of contract. On December 14, 2014, the U.S. Court of Federal Claims issued a judgment in favor of Georgia Power, as agent for the co-owners, to recover spent nuclear fuel storage costs at Hatch and Vogtle Units No. 1 and No. 2 covering the period of 2005 through 2010. Our ownership share of the $36,474,000 total award was $10,949,000, which was received in April 2015. The effects of the award were recorded during the first quarter of 2015 and resulted in a $7,320,000 reduction in total operating expenses, including reductions to fuel expense and production costs, as well as a $3,629,000 reduction to plant in service. On March 4, 2014, Georgia Power, as agent for the co-owners, filed a separate claim seeking damages for spent nuclear fuel storage costs at Hatch and Vogtle Units No. 1 and No. 2 covering a period of January 1, 2011 through December 31, 2013. The damage period was subsequently amended and now extends through December 31, 2014. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the financial statements as of December 31, 2015 for this claim. The final outcome of these matters cannot be determined at this time. Both Plants Hatch and Vogtle have on-site dry spent storage facilities in operation. Facilities at both plants can be expanded to accommodate spent fuel through the expected life of each plant. |
Asset retirement obligations and other retirement costs | i. Asset retirement obligations and other retirement costs Asset retirement obligations are legal obligations associated with the retirement of long-lived assets. These obligations represent the present value of the estimated costs for an asset's future retirement discounted using a credit-adjusted risk-free rate, and are recorded in the period in which the liability is incurred. The liabilities we have recognized primarily relate to the decommissioning of our nuclear facilities. In addition, we have retirement obligations related to coal ash ponds, gypsum cells, powder activated carbon cells, landfill sites and asbestos removal. Under the accounting provision for regulated operations, we record a regulatory asset or liability to reflect the difference in timing of recognition of the costs related to nuclear and coal ash related decommissioning for financial statement purposes and for ratemaking purposes. Periodically, we obtain revised cost studies associated with our nuclear and fossil plants' asset retirement obligations. Actual retirement costs may vary from these estimates. The estimated costs of nuclear and coal ash pond decommissioning are based on the most recent studies performed in 2015. The following table reflects the details of the Asset Retirement Obligations included in the consolidated balance sheets for the years 2015 and 2014. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Nuclear Coal Ash Pond Other Total ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at December 31, 2014 $ $ $ $ Liabilities settled – – ) ) Accretion Change in Cash Flow Estimates ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at December 31, 2015 $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Nuclear Coal Ash Pond Other Total ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at December 31, 2013 $ $ $ $ Liabilities settled – – ) ) Accretion ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at December 31, 2014 $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Nuclear Decommissioning. Nuclear decommissioning cost estimates are based on site studies and assume prompt dismantlement and removal of both the radiated and non-radiated portions of the plant from service, as well as the management of spent fuel. We do not have a legal obligation to decommission non-radiated structures and, therefore, these costs are excluded from the related asset retirement obligation and the amounts in the table above. Actual decommissioning costs may vary from these estimates because of changes in the assumed date of decommissioning, changes in regulatory requirements, changes in technology, and changes in costs of labor, materials and equipment. The estimated costs of decommissioning are based on the most current study performed in 2015. In projecting future costs, the escalation rate for labor, materials and equipment was assumed to be 2.5%. The increase in the cash flow estimates in 2015 was primarily attributable to security costs, waste disposal costs and inflation, among other factors. Our portion of the estimated costs of decommissioning co-owned nuclear facilities were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2015 site study Hatch Unit No. 1 Hatch Unit No. 2 Vogtle Unit No. 1 Vogtle Unit No. 2 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Expected start date of decommissioning 2034 2038 2047 2049 Estimated costs based on site study in 2015 dollars: Radiated structures $ $ $ $ Spent fuel management Non-radiated structures ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total estimated site study costs $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ We have established funds to comply with the Nuclear Regulatory Commission regulations regarding the decommissioning of our nuclear plants. See Note 1j for information regarding the nuclear decommissioning funds. Coal Ash Pond. On April 17, 2015 the Environmental Protection Agency published its final coal combustion residuals (CCR) rule which regulates CCRs as non-hazardous materials under Subtitle D of the Resource Conservation and Recovery Act. The rule took effect on October 19, 2015. The most current assessment of the final CCR rule resulted in a $49,084,000 change in cash flow estimates for coal ash decommissioning. Estimates are based on various assumptions including, but not limited to, closure and post-closure cost estimates, timing of expenditures, escalation factors, discount rates and methods for complying with the CCR rule. The increase in the cash flow estimates in 2015 was a result of changes in the assumptions regarding the timing of expenditures as well as an increase in the cost estimates. Additional adjustments to the asset retirement obligations are expected periodically that will impact these estimates and assumptions. Accounting standards for asset retirement and environmental obligations do not apply to a retirement cost for which there is no legal obligation to retire the asset, and non-regulated entities are not allowed to accrue for such future retirement costs. We continue to recognize retirement costs for these other obligations in our depreciation rates under the accounting provisions for regulated operations. Accordingly, the accumulated retirement costs for other obligations are reflected as a regulatory liability in our balance sheets. For information regarding accumulated retirement costs for other obligations, see Note 1r. |
Nuclear decommissioning funds | j. Nuclear decommissioning funds The Nuclear Regulatory Commission (NRC) requires all licensees operating commercial power reactors to establish a plan for providing, with reasonable assurance, funds for decommissioning. The NRC definition of decommissioning does not include all costs that may be associated with decommissioning, such as spent fuel management and non-radiated structures. We have established external trust funds to comply with the NRC's regulations. Upon approval by the NRC, any funding in the external trust in excess of their requirements may be used for other decommissioning costs. In 2015 and 2014, no additional amounts were contributed to the external trust funds. These funds are managed by unrelated third party investment managers with the discretion to buy, sell and invest pursuant to investment objectives and restrictions set forth in agreements entered into between us and the investment managers. The fair value of the external trust fund was $363,829,000 and $366,004,000 at December 31, 2015 and 2014, respectively. The funds are invested in a diversified mix of approximately 60% equity and 40% fixed income securities. We record the investment securities held in the nuclear decommissioning trust fund, which are classified as available-for-sale, at fair value, as disclosed in Note 2. Because day-to-day investment decisions are made by third party investment managers, the ability to hold investments in unrealized loss positions is outside our control. In addition to the external trust funds, we maintain unrestricted investments internally designated for nuclear decommissioning. These internal funds are available to be utilized to fund the external trust funds, should additional funding be required, as well as other decommissioning costs outside the scope of the NRC funding regulations. At December 31, 2015 and 2014, the fair value of these funds was $63,326,000 and $59,080,000, respectively. The funds are included in long-term investments on our consolidated balance sheet. We collected $4,750,000 and $2,975,000 from our members in 2015 and 2014, respectively, and contributed those amounts into the internal funds. Unrealized gains and losses of the nuclear decommissioning funds that would be recorded in earnings or other comprehensive margin (deficit) by a non-regulated entity are directly deducted from or added to the regulatory asset or liability for asset retirement obligations in accordance with our rate-making treatment. Realized gains and losses on the nuclear decommissioning funds are also recorded to the regulatory asset or liability. During 2015, we assumed a 6.0% earnings rate for our decommissioning fund assets. Earnings on the fund assets were approximately $40,380,000 and $23,507,000 in 2015 and 2014, respectively. Since inception in 1990 through 2015, the nuclear decommissioning trust fund has produced an average annualized return of approximately 7.1%. Based on current funding and cost study estimates, we expect the current balances and anticipated investment earnings of our decommissioning fund assets to be sufficient to meet all of our future nuclear decommissioning costs. Notwithstanding the results of revised site studies, our management believes that any increase in cost estimates of decommissioning can be recovered in future rates. |
Depreciation | k. Depreciation Depreciation is computed on additions when they are placed in service using the composite straight-line method. We use standard depreciation rates as well as site specific rates determined through depreciation studies as approved by the Rural Utilities Service. The depreciation rates for steam and nuclear production in the table below reflect revised rates from 2011 depreciation rate studies. Site specific depreciation studies are performed every five years. Annual depreciation rates in effect in 2015, 2014 and 2013 were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Range of Useful Life in years* 2015 2014 2013 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Steam production 49-65 % % % Nuclear production 37-60 % % % Hydro production 50 % % % Other production 27-33 % % % Transmission 36 % % % General 3-50 2.00-33.33 % 2.00-33.33 % 2.00-33.33 % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ * Calculated based on the composite depreciation rates in effect for 2015. Depreciation expense for the years 2015, 2014 and 2013 was $180,866,000, $178,302,000, and $171,240,000, respectively. |
Electric plant | l. Electric plant Electric plant is stated at original cost, which is the cost of the plant when first dedicated to public service, plus the cost of any subsequent additions. Cost includes an allowance for the cost of equity and debt funds used during construction and allocable overheads. For the years ended 2015, 2014 and 2013, the allowance for funds used during construction rates were 4.73%, 4.97% and 4.93%, respectively. Replacements and renewals of items considered to be units of property, the lowest level of property for which we capitalize, are charged to the plant accounts. At the time properties are disposed of, the original cost, plus cost of removal, less salvage of such property, is charged to the accumulated provision for depreciation. Maintenance and repairs of property and replacements and renewals of items determined to be less than units of property are charged to expense, including certain major maintenance costs at our natural gas-fired plants. |
Cash and cash equivalents | m. Cash and cash equivalents We consider all temporary cash investments purchased with an original maturity of three months or less to be cash equivalents. Temporary cash investments with maturities at the time of purchase of more than three months are classified as short-term investments. |
Restricted cash and investments | n. Restricted cash and investments Restricted cash and investments primarily consist of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account. The restricted investments will be utilized for future Rural Utilities Service-guaranteed Federal Financing Bank debt service payments. The funds on deposit earn interest at a rate of 5% annum. At 2015 and 2014, we had restricted cash and investments totaling $387,961,000 and $365,585,000, respectively, of which $134,690,000 and $118,390,000, respectively was classified as long-term. |
Inventories | o. Inventories We maintain inventories of fossil fuel and spare parts, including materials and supplies for our generation plants. These inventories are stated at weighted average cost on the accompanying balance sheets. The fossil fuel inventories primarily include the direct cost of coal and related transportation charges. The cost of fossil fuel inventories is carried at weighted average cost and is charged to fuel expense as consumed based on weighted average cost. The spare parts inventories primarily include the direct cost of generating plant spare parts. The spare parts inventory is carried at weighted average cost and the parts are charged to expense or capitalized, as appropriate when installed. At 2015 and 2014, fossil fuels inventories were $104,086,000 and $98,789,000, respectively. Inventories for spare parts at 2015 and 2014 were $195,166,000 and $172,060,000, respectively. |
Deferred charges and other assets | p. Deferred charges and other assets Prepayments to Georgia Power Company primarily represent progress payments for equipment associated with future nuclear refueling outages. In 2014, prepayments to Georgia Power also included disputed payment amounts associated with the Vogtle Units No. 3 and No. 4 construction project that were paid during 2015. |
Deferred credits and other liabilities | q. Deferred credits and other liabilities We have a power bill prepayment program pursuant to which members can prepay their power bills from us at a discount based on our avoided cost of borrowing. The prepayments are credited against the participating members' power bills in the month(s) agreed upon in advance. The discounts are credited against the power bills monthly and are recorded as a reduction to member revenues. The prepayments are being credited against members' power bills through July 2021, with the majority of the balance scheduled to be credited by the end of 2016. In connection with the Vogtle Units No. 3 and No. 4 construction project, we are accruing long-term contract retainage amounts for substantial and mechanical milestones that will become due near the anticipated commercial operation dates of the units. For more information regarding the Vogtle construction project, see Note 8. We recorded a liability for a power sale agreement assumed in conjunction with the Hawk Road acquisition in May 2009. The liability was fully amortized in 2015. |
Regulatory assets and liabilities | r. Regulatory assets and liabilities We apply the accounting guidance for regulated operations. Regulatory assets represent certain costs that are probable of recovery from our members in future revenues through rates under the wholesale power contracts with our members, which extend through December 31, 2050. Regulatory liabilities represent certain items of income that we are retaining and that will be applied in the future to reduce revenues required to be recovered from members. ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2015 2014 ​ ​ ​ ​ ​ ​ ​ ​ Regulatory Assets: Premium and loss on reacquired debt (a) $ $ Amortization on capital leases (b) Outage costs (c) Interest rate swap termination fees (d) Depreciation expense (e) Deferred charges related to Vogtle Units No. 3 and No. 4 training costs (f) Interest rate options cost (g) Deferral of effects on net margin – Smith Energy Facility (h) Other regulatory assets (m) ​ ​ ​ ​ ​ ​ ​ ​ Total Regulatory Assets Regulatory Liabilities: Accumulated retirement costs for other obligations (i) $ $ Deferral of effects on net margin – Hawk Road Energy Facility (h) Major maintenance reserve (j) Amortization on capital leases (b) Deferred debt service adder (k) Asset retirement obligations (l) Other regulatory liabilities (m) ​ ​ ​ ​ ​ ​ ​ ​ Total Regulatory Liabilities ​ ​ ​ ​ ​ ​ ​ ​ Net regulatory assets $ $ ​ ​ ​ ​ ​ ​ ​ ​ (a) Represents premiums paid, together with unamortized transaction costs related to reacquired debt that are being amortized over the lives of the refunding debt, which range up to 28 years. (b) Represents the difference between expense recognized for rate-making purposes and financial statement purposes related to capital lease payments and the aggregate of the amortization of the asset and interest on the obligation. (c) Consists of both coal-fired maintenance and nuclear refueling outage costs. Coal-fired outage costs are amortized on a straight-line basis to expense over a 24-month period. Nuclear refueling outage costs are amortized on a straight-line basis to expense over the 18 to 24-month operating cycles of each unit. (d) Represents losses on settled interest rate swap arrangements that are being amortized through 2016 and 2019. (e) Prior to Nuclear Regulatory Commission (NRC) approval of a 20-year license extension for Plant Vogtle, we deferred the difference between Plant Vogtle depreciation expense based on the then 40-year operating license and depreciation expense assuming an expected 20-year license extension. Amortization commenced upon NRC approval of the license extension in 2009 and is being amortized over the remaining life of the plant. (f) Deferred charges related to Vogtle Units No. 3 and No. 4 training and interest related carrying costs of such training. Amortization will commence effective with the commercial operation date of each unit and amortized to expense over the life of the units. (g) Deferral of net loss associated with the unrealized and realized change in fair value of interest rate options purchased to hedge interest rates on certain borrowings related to Vogtle Units No. 3 and No. 4 construction. Amortization will commence in February 2020 and will be amortized through February 2044, the life of the DOE-guaranteed loan which is financing a portion of the construction project. (h) Effects on net margin for Smith and Hawk Road Energy Facilities were deferred through the end of 2015 and will be amortized over the remaining life of each respective plant. (i) Represents the accrual of retirement costs associated with long-lived assets for which there are no legal obligations to retire the assets. (j) Represents collections for future major maintenance expenses; revenues are recognized as major maintenance costs are incurred. (k) Represents collections to fund certain debt payments to be made through the end of 2025 which will be in excess of amounts collected through depreciation expense; the deferred credits will be amortized over the remaining useful life of the plants. (l) Represents difference in timing of recognition of the costs of decommissioning for financial statement purposes and for ratemaking purposes. (m) The amortization period for other regulatory assets range up to 34 years and the amortization period of other regulatory liabilities range up to 11 years. |
Related parties | s. Related parties We and our 38 members are members of Georgia Transmission. Georgia Transmission provides transmission services to its members for delivery of its members' power purchases from us and other power suppliers. We have entered into an agreement with Georgia Transmission to provide transmission services for third party transactions and for service to our own facilities. For 2015, 2014, and 2013, we incurred expenses from Georgia Transmission of $28,172,000, $27,893,000, and $27,599,000, respectively. We, Georgia Transmission and 38 of our members are members of Georgia Systems Operations. Georgia Systems Operations operates the system control center and currently provides us system operations services and administrative support services. For 2015, 2014, and 2013, we incurred expenses from Georgia Systems Operations of $22,616,000, $27,893,000, and $27,599,000, respectively. |
Other income | t. Other income The components of other income within the Consolidated Statement of Revenues and Expenses were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2015 2014 2013 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Capital credits from associated companies (Note 4) $ $ $ Net revenue from Georgia Transmission and Georgia System Operations for shared Administrative and General costs Miscellaneous other ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ |
New accounting pronouncements | u. New accounting pronouncements In May 2014, the Financial Accounting Standards Board (FASB) issued "Revenue from Contracts with Customers" (Topic 606). The new revenue standard requires that an entity recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. The standard was effective for the annual reporting period beginning after December 15, 2016 using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a modified retrospective approach with the cumulative effect of initially adopting the standard recognized at the date of adoption (which includes additional footnote disclosures). Early adoption was not permitted. In August 2015, the FASB issued an update to Topic 606 deferring the effective date by one year. The standard is effective for annual reporting periods beginning after December 15, 2017 and interim periods therein. The standard also permits early adoption of the standard, but not before the original effective date of December 15, 2016. We are currently evaluating the future impact of this standard on our consolidated financial statements. In July 2015, the FASB issued "Inventory (Topic 330): Simplifying the Measurement of Inventory." Under the new inventory standard, inventories are required to be measured at the lower of cost and net realizable value, the latter representing the estimated selling price in the ordinary course of business, reduced by costs of completion, disposal, and transportation. Under current guidance, inventories are required to be measured at the lower of cost or market, but depending upon specific circumstances, market could be replacement cost, net realizable value, or net realizable value reduced by a normal profit margin. The amendments do not apply to inventory measured using the last-in, first-out or the retail inventory method. The amendments apply to all other inventory, which includes inventory that is measured using first-in, first out or average cost, the method used to measure all of our inventories. The new standard is effective for us prospectively for annual reporting periods beginning after December 15, 2016, and interim periods therein. Early adoption is permitted as of the beginning of an interim or annual reporting period. We are currently evaluating the future impact of this standard on our consolidated financial statements. In April 2015, the FASB issued "Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs." The amendments in this standard require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. In August 2015, the FASB clarified that its guidance issued in April 2015 does not apply to line-of-credit arrangements. Accordingly, entities may continue to present related debt issuance costs as an asset and subsequently amortize the deferred debt costs ratably over the term of the line-of-credit arrangements, regardless of whether there are any outstanding borrowings on the line-of-credit arrangements. As permitted, we early adopted these updates as of December 31, 2015 and applied their provisions retrospectively. The adoption resulted in a $97,423,000 adjustment in the presentation of unamortized debt issuance costs as a direct reduction of the carrying amount of long-term debt as of December 31, 2014. These unamortized debt issuance costs were previously presented within deferred charges and other assets. Other than the current year consolidated balance sheet presentation and the aforementioned reclassification, the adoption of these updates did not have an impact on our consolidated financial statements. See Note 7 for additional information regarding the adoption of the new guidance. In November 2015, the FASB issued "Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes." The amendments in this standard simplifies the presentation of deferred income taxes by eliminating the separate classification of deferred income tax assets and liabilities into current and noncurrent amounts in the statement of financial position. The amendments in the update require that all deferred tax assets and liabilities be classified as noncurrent in the consolidated balance sheet. The new standard is effective for us prospectively for annual reporting periods beginning after December 15, 2016, and interim periods therein. Early adoption is permitted as of the beginning of an interim or annual reporting period. We are currently evaluating the future impact of this standard on our consolidated financial statements. In February 2016, the FASB issued "Leases (Topic 842)." The new leases standard requires a dual approach for lessee accounting under which a lessee would account for leases as finance leases or operating leases. Both finance leases and operating leases will result in the lessee recognizing a right-of-use (ROU) asset and a corresponding lease liability. For finance leases the lessee would recognize interest expense and amortization of the ROU asset and for operating leases the lessee would recognize a straight-line total lease expense. The new lease standard does not substantially change lessor accounting. The new leases standard is effective for us on a modified retrospectively approach for annual reporting periods beginning after December 15, 2018, and interim periods therein. Early adoption is permitted. We are currently evaluating the future impact of this standard on our consolidated financial statements. |
Summary of significant accoun24
Summary of significant accounting policies: (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Summary of significant accounting policies: | |
Schedule of changes in accumulated other comprehensive margin (deficit) | ​ ​ ​ ​ ​ Accumulated Other Comprehensive Margin (Deficit) (dollars in thousands) Available-for-sale Securities ​ ​ ​ ​ ​ Balance at December 31, 2012 $ Unrealized loss ) (Gain) reclassified to net margin ) ​ ​ ​ ​ ​ Balance at December 31, 2013 ) Unrealized gain (Gain) reclassified to net margin ) ​ ​ ​ ​ ​ Balance at December 31, 2014 Unrealized gain (Gain) reclassified to net margin ) ​ ​ ​ ​ ​ Balance at December 31, 2015 $ ​ ​ ​ ​ ​ |
Schedule of members whose revenues accounted for 10% or more of total operating revenues | ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2015 2014 2013 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Cobb EMC % % % Sawnee EMC % % % Jackson EMC % % % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ |
Schedule reflecting details of Asset Retirement Obligations included in the consolidated balance sheets | ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Nuclear Coal Ash Pond Other Total ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at December 31, 2014 $ $ $ $ Liabilities settled – – ) ) Accretion Change in Cash Flow Estimates ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at December 31, 2015 $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Nuclear Coal Ash Pond Other Total ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at December 31, 2013 $ $ $ $ Liabilities settled – – ) ) Accretion ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at December 31, 2014 $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ |
Schedule of estimated costs of decommissioning of co-owned nuclear facilities | ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2015 site study Hatch Unit No. 1 Hatch Unit No. 2 Vogtle Unit No. 1 Vogtle Unit No. 2 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Expected start date of decommissioning 2034 2038 2047 2049 Estimated costs based on site study in 2015 dollars: Radiated structures $ $ $ $ Spent fuel management Non-radiated structures ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total estimated site study costs $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ |
Schedule of annual depreciation rates as approved by Rural Utilities Service | ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Range of Useful Life in years* 2015 2014 2013 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Steam production 49-65 % % % Nuclear production 37-60 % % % Hydro production 50 % % % Other production 27-33 % % % Transmission 36 % % % General 3-50 2.00-33.33 % 2.00-33.33 % 2.00-33.33 % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ * Calculated based on the composite depreciation rates in effect for 2015. |
Schedule of regulatory assets and (liabilities) | ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2015 2014 ​ ​ ​ ​ ​ ​ ​ ​ Regulatory Assets: Premium and loss on reacquired debt (a) $ $ Amortization on capital leases (b) Outage costs (c) Interest rate swap termination fees (d) Depreciation expense (e) Deferred charges related to Vogtle Units No. 3 and No. 4 training costs (f) Interest rate options cost (g) Deferral of effects on net margin – Smith Energy Facility (h) Other regulatory assets (m) ​ ​ ​ ​ ​ ​ ​ ​ Total Regulatory Assets Regulatory Liabilities: Accumulated retirement costs for other obligations (i) $ $ Deferral of effects on net margin – Hawk Road Energy Facility (h) Major maintenance reserve (j) Amortization on capital leases (b) Deferred debt service adder (k) Asset retirement obligations (l) Other regulatory liabilities (m) ​ ​ ​ ​ ​ ​ ​ ​ Total Regulatory Liabilities ​ ​ ​ ​ ​ ​ ​ ​ Net regulatory assets $ $ ​ ​ ​ ​ ​ ​ ​ ​ (a) Represents premiums paid, together with unamortized transaction costs related to reacquired debt that are being amortized over the lives of the refunding debt, which range up to 28 years. (b) Represents the difference between expense recognized for rate-making purposes and financial statement purposes related to capital lease payments and the aggregate of the amortization of the asset and interest on the obligation. (c) Consists of both coal-fired maintenance and nuclear refueling outage costs. Coal-fired outage costs are amortized on a straight-line basis to expense over a 24-month period. Nuclear refueling outage costs are amortized on a straight-line basis to expense over the 18 to 24-month operating cycles of each unit. (d) Represents losses on settled interest rate swap arrangements that are being amortized through 2016 and 2019. (e) Prior to Nuclear Regulatory Commission (NRC) approval of a 20-year license extension for Plant Vogtle, we deferred the difference between Plant Vogtle depreciation expense based on the then 40-year operating license and depreciation expense assuming an expected 20-year license extension. Amortization commenced upon NRC approval of the license extension in 2009 and is being amortized over the remaining life of the plant. (f) Deferred charges related to Vogtle Units No. 3 and No. 4 training and interest related carrying costs of such training. Amortization will commence effective with the commercial operation date of each unit and amortized to expense over the life of the units. (g) Deferral of net loss associated with the unrealized and realized change in fair value of interest rate options purchased to hedge interest rates on certain borrowings related to Vogtle Units No. 3 and No. 4 construction. Amortization will commence in February 2020 and will be amortized through February 2044, the life of the DOE-guaranteed loan which is financing a portion of the construction project. (h) Effects on net margin for Smith and Hawk Road Energy Facilities were deferred through the end of 2015 and will be amortized over the remaining life of each respective plant. (i) Represents the accrual of retirement costs associated with long-lived assets for which there are no legal obligations to retire the assets. (j) Represents collections for future major maintenance expenses; revenues are recognized as major maintenance costs are incurred. (k) Represents collections to fund certain debt payments to be made through the end of 2025 which will be in excess of amounts collected through depreciation expense; the deferred credits will be amortized over the remaining useful life of the plants. (l) Represents difference in timing of recognition of the costs of decommissioning for financial statement purposes and for ratemaking purposes. (m) The amortization period for other regulatory assets range up to 34 years and the amortization period of other regulatory liabilities range up to 11 years. |
Schedule of components of other income | ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2015 2014 2013 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Capital credits from associated companies (Note 4) $ $ $ Net revenue from Georgia Transmission and Georgia System Operations for shared Administrative and General costs Miscellaneous other ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ |
Fair Value_ (Tables)
Fair Value: (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value: | |
Schedule of assets and liabilities measured at fair value on a recurring basis | ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fair Value Measurements at Reporting Date Using December 31, 2015 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ $ $ – $ – International equity trust – – Corporate bonds – – US Treasury and government agency securities – Agency mortgage and asset backed securities – – Other – – Long-term investments: Corporate bonds – – US Treasury and government agency securities – – Agency mortgage and asset backed securities – – International equity trust – – Mutual funds – – Other – – Interest rate options – – (1) Natural gas swaps – – ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fair Value Measurements at Reporting Date Using December 31, 2014 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ $ $ – $ – International equity trust – – Corporate bonds – – US Treasury and government agency securities – – Agency mortgage and asset backed securities – – Municipal Bonds – – Other – – Long-term investments: Corporate bonds – – US Treasury and government agency securities – – Agency mortgage and asset backed securities – – International equity trust – – Mutual funds – – Other – – Interest rate options – – (1) Natural gas swaps – – ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) Interest rate options as reflected on the Consolidated Balance Sheet include the fair value of the interest rate options. |
Schedule of changes in Level 3 assets measured at fair value on a recurring basis | ​ ​ ​ ​ ​ Year Ended December 31, 2015 Interest rate options ​ ​ ​ ​ ​ (dollars in thousands) Assets: Balance at December 31, 2014 $ Total gains or losses (realized/unrealized): Included in earnings (or changes in net assets) ) ​ ​ ​ ​ ​ Balance at December 31, 2015 $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, 2014 Interest rate options ​ ​ ​ ​ ​ (dollars in thousands) Assets: Balance at December 31, 2013 $ Total gains or losses (realized/unrealized): Included in earnings (or changes in net assets) ) ​ ​ ​ ​ ​ Balance at December 31, 2014 $ ​ ​ ​ ​ ​ |
Schedule of estimated fair values of long-term debt, including current maturities | The estimated fair values of our long-term debt, including current maturities at December 31, 2015 and 2014 were as follows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2015 2014 Carrying Value Fair Value Carrying Value Fair Value ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Long-term debt $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ |
Derivative instruments_ (Tables
Derivative instruments: (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Derivative instruments: | |
Schedule of volume activity of natural gas derivatives that is expected to settle or mature each year | The following table reflects the volume activity of our natural gas derivatives as of December 31, 2015 that is expected to settle or mature each year: ​ ​ ​ ​ ​ Year Natural Gas Swaps (MMBTUs) (in millions) ​ ​ ​ ​ ​ 2016 2017 2018 2019 ​ ​ ​ ​ ​ Total ​ ​ ​ ​ ​ |
Schedule of remaining notional amount of forecasted debt issuances hedged in each year with LIBOR swaptions | The following table reflects the remaining notional amount of forecasted debt issuances we have hedged in each year with LIBOR swaptions as of December 31, 2015. ​ ​ ​ ​ ​ Year LIBOR Swaption Notional Dollar Amount (in thousands) ​ ​ ​ ​ ​ 2016 $ 2017 ​ ​ ​ ​ ​ Total $ ​ ​ ​ ​ ​ |
Schedule of fair value of derivative instruments and their effect on consolidated balance sheets | ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance Sheet Location Fair Value ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2015 2014 (dollars in thousands) Not designated as hedge: Assets Interest rate options Other deferred charges $ $ Liabilities Natural gas swaps Other current liabilities $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ |
Schedule of the gross realized gains and (losses) on derivative instruments recognized in margin | ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Consolidated Statement of Revenues and Expenses Location 2015 2014 2013 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Not designated as hedge: Natural Gas Swaps Fuel $ $ $ Natural Gas Swaps Fuel ) ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ ) $ $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ |
Schedule of unrealized gains and (losses) on derivative instruments deferred on the balance sheet | ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Consolidated Balance Sheet Location ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2015 2014 Not designated as hedges: Natural Gas Swaps Regulatory asset $ ) $ ) Interest Rate Options Regulatory asset ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total not designated as hedges $ ) $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ |
Schedule of gross amounts of derivatives and their related offset amounts as permitted by their respective master netting agreements and obligations to return cash collateral | ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Gross Amounts of Recognized Assets (Liabilities) Gross Amounts offset on the Balance Sheet Cash Collateral Net Amounts of Assets (Liabilities) Presented on the Balance Sheet ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2015 Assets: Natural gas swaps $ ) $ – $ – $ ) Interest rate options $ $ ) $ – $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2014 Assets: Natural gas swaps $ ) $ – $ – $ ) Interest rate options $ $ ) $ – $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ |
Investments_ (Tables)
Investments: (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Investments: | |
Summary of activities for available-for-sale securities | ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Gross Unrealized 2015 Cost Gains Losses Fair Value ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity $ $ $ ) $ Debt ) Other – ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ ) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Gross Unrealized 2014 Cost Gains Losses Fair Value ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity $ $ $ ) $ Debt ) Other – ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ ) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ |
Schedule of contractual maturities of debt securities available-for-sale | ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2015 2014 Cost Fair Value Cost Fair Value ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Due within one year $ $ $ $ Due after one year through five years Due after five years through ten years Due after ten years ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ |
Summary of realized gains and losses and proceeds from sales of securities | ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2015 2014 2013 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Gross realized gains $ $ $ Gross realized losses ) ) ) Proceeds from sales ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ |
Schedule of investments in associated companies | ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2015 2014 ​ ​ ​ ​ ​ ​ ​ ​ National Rural Utilities Cooperative Finance Corporation (CFC) $ $ CT Parts, LLC Georgia Transmission Corporation Georgia System Operations Corporation Other ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ ​ ​ ​ ​ ​ ​ ​ ​ |
Income taxes_ (Tables)
Income taxes: (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Income taxes: | |
Summary of difference between statutory federal income tax rate on income before income taxes and effective income tax rate | ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2015 2014 2013 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Statutory federal income tax rate % % Patronage exclusion %) %) Other %) %) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Effective income tax rate % % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ |
Schedule of components of net deferred tax assets and liabilities | ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2015 2014 ​ ​ ​ ​ ​ ​ ​ ​ Deferred tax assets Net operating losses $ $ Tax credits (alternative minimum tax and other) Accounting for Rocky Mountain transactions Other assets ​ ​ ​ ​ ​ ​ ​ ​ Deferred tax assets Less: Valuation allowance ) ) ​ ​ ​ ​ ​ ​ ​ ​ Net deferred tax assets $ $ ​ ​ ​ ​ ​ ​ ​ ​ Deferred tax liabilities Depreciation $ $ Accounting for Rocky Mountain transactions Other liabilities ​ ​ ​ ​ ​ ​ ​ ​ Deferred tax liabilities ​ ​ ​ ​ ​ ​ ​ ​ Net deferred tax liabilities Less: Patronage exclusion ) ) ​ ​ ​ ​ ​ ​ ​ ​ Net deferred taxes $ – $ – ​ ​ ​ ​ ​ ​ ​ ​ |
Schedule of federal tax net operating loss carryforwards and alternative minimum tax credits | As of December 31, 2015, we have federal tax net operating loss carryforwards and alternative minimum tax credits as follows: ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) ​ ​ ​ ​ ​ ​ ​ ​ Expiration Date Alternative Minimum Tax Credits NOLs ​ ​ ​ ​ ​ ​ ​ ​ 2018 $ – $ 2019 – 2020 – None – ​ ​ ​ ​ ​ ​ ​ ​ $ $ ​ ​ ​ ​ ​ ​ ​ ​ |
Capital leases_ (Tables)
Capital leases: (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Capital leases: | |
Schedule of minimum lease payments under capital leases together with present value of net minimum lease payments | The minimum lease payments under the capital leases together with the present value of the net minimum lease payments as of December 31, 2015 are as follows: ​ ​ ​ ​ ​ Year Ending December 31, (dollars in thousands) ​ ​ ​ ​ ​ Scherer Unit No. 2 ​ ​ ​ ​ ​ 2016 $ 2017 2018 2019 2020 2021-2031 ​ ​ ​ ​ ​ Total minimum lease payments Less: Amount representing interest ) ​ ​ ​ ​ ​ Present value of net minimum lease payments Less: Current portion ) ​ ​ ​ ​ ​ Long-term balance $ ​ ​ ​ ​ ​ |
Debt_ (Tables)
Debt: (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Debt: | |
Schedule of principal amount of long-term debt and the associated unamortized debt issuance costs and debt discounts | ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2015 2014 Principal Unamortized Debt Issuance Costs and Debt Discounts Principal Unamortized Debt Issuance Costs and Debt Discounts ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) FFB $ $ $ $ FMBs PCBs CFC – – CoBank – – ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ |
Long Term Debt And Capital Lease Obligations | |
Debt | |
Schedule of maturities for long-term debt and capital lease obligations | ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2016 2017 2018 2019 2020 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ FFB $ $ $ $ $ FMBs PCBs (1) – CFC CoBank – ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Capital Leases ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) In addition to regularly scheduled principal payments on the bonds, this includes amounts that would be due if the credit support facilities for the Series 2009 and Series 2010 pollution control bonds were drawn upon and became payable in accordance with their terms, such as would occur if the credit facility providing the support was not renewed or extended at its expiration date. These amounts equal $37 million in each of the years 2016, 2017 and 2018 and $134 million in 2020. We anticipate extending these credit facilities before their expiration. The nominal maturities of the Series 2009 and Series 2010 pollution control bonds range from 2030 through 2038. |
Electric plant, construction 31
Electric plant, construction and related agreements: (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Electric plant, construction and related agreements: | |
Summary of plant investments and related accumulated depreciation | ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2015 2014 (dollars in thousands) Plant Investment Accumulated Depreciation Investment Accumulated Depreciation ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ In-service (1) Owned property Vogtle Units No. 1 & No. 2 (Nuclear – 30% ownership) $ $ ) $ $ ) Vogtle Units No. 3 & No. 4 (Nuclear – 30% ownership) ) ) Hatch Units No. 1 & No. 2 (Nuclear – 30% ownership) ) ) Wansley Units No. 1 & No. 2 (Fossil – 30% ownership) ) ) Scherer Unit No. 1 (Fossil – 60% ownership) ) ) Doyle (Combustion Turbine – 100% leasehold) (2) ) ) Rocky Mountain Units No. 1, No. 2 & No. 3 (Hydro – 75% ownership) ) ) Hartwell (Combustion Turbine – 100% ownership) ) ) Hawk Road (Combustion Turbine – 100% ownership) ) ) Talbot (Combustion Turbine – 100% ownership) ) ) Chattahoochee (Combined cycle – 100% ownership) ) ) Smith (Combined cycle – 100% ownership) ) ) Wansley (Combustion Turbine – 30% ownership) ) ) Transmission plant ) ) Other ) ) Property under capital lease: Scherer Unit No. 2 (Fossil – 60% leasehold) ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total in-service $ $ ) $ $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Construction work in progress Vogtle Units No. 3 & No. 4 $ $ Environmental and other generation improvements Other ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total construction work in progress $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) Amounts include plant acquisition adjustments at December 31, 2015 and 2014 of $196,000,000. (2) On August 20, 2015, we acquired Doyle which we previously operated under a capital lease. |
Commitments_ (Tables)
Commitments: (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Commitments: | |
Schedule of estimated minimum rental commitments for railcar leases for use at coal-fired facilities over the next five years and thereafter | As of December 31, 2015, our estimated minimum rental commitments for our railcar leases for use at our coal-fired facilities over the next five years and thereafter are as follows: ​ ​ ​ ​ ​ (dollars in thousands) ​ ​ ​ ​ ​ 2016 $ 2017 2018 2019 2020 Thereafter – ​ ​ ​ ​ ​ |
Schedule of estimated minimum long-term commitments | As of December 31, 2015, our estimated minimum long-term commitments are as follows: ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Coal Nuclear Fuel ​ ​ ​ ​ ​ ​ ​ ​ 2016 $ $ 2017 2018 2019 – 2020 – Thereafter – ​ ​ ​ ​ ​ ​ ​ ​ |
Quarterly financial data (una33
Quarterly financial data (unaudited): (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Quarterly financial data (unaudited): | |
Summary of quarterly financial information | ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ First Quarter Second Quarter Third Quarter Fourth Quarter ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2015 Operating revenues $ $ $ $ Operating margin Net margin 2014 Operating revenues $ $ $ $ Operating margin Net margin ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ |
Summary of significant accoun34
Summary of significant accounting policies: Accounting policies (Details) | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2015USD ($)itemMW | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | |
Summary of significant accounting policies: | |||||
Number of electric distribution cooperative members | item | 38 | ||||
Number of people to whom energy is distributed on a retail basis by the entity's members | item | 4,200,000 | ||||
Patronage capital and membership fees | |||||
Membership fees paid by members | $ 190 | ||||
Minimum equity as a percentage of total long-term debt and equities for distributions of patronage capital | 20.00% | ||||
Maximum percentage of aggregate net margins in which specified percentage of total long-term debt and equities cannot exceed on or after distributions expended | 35.00% | ||||
Minimum equity as a percentage of total long-term debt and equities after distributions of patronage capital | 30.00% | ||||
Accumulated Other Comprehensive Loss Net Of Tax Roll Forward | |||||
Effective income tax rate (as a percent) | 0.00% | 0.00% | 0.00% | ||
Balance at the beginning of the period | $ 468,000 | $ (549,000) | $ 903,000 | ||
Unrealized gain (loss) | 265,000 | 1,180,000 | (1,396,000) | ||
(Gain) reclassified to net margin | (675,000) | (163,000) | (56,000) | ||
Balance at the end of the period | $ 58,000 | $ 468,000 | $ 58,000 | $ 468,000 | $ (549,000) |
Margin policy | |||||
Minimum margins for interest ratio under the first mortgage indenture | 1.10 | ||||
Margins for interest ratio | 1.14 | 1.14 | 1.14 | 1.14 | 1.14 |
Concentration | |||||
Number of programs allowing expense costs on current basis otherwise capitalized approved by Rural Utilities Service | item | 2 | ||||
Amounts billed to members | $ 25,375,000 | $ 14,991,000 | $ 13,962,000 | ||
Summer planning reserve capacity of generating units (in megawatts) | MW | 7,067 | ||||
Basis of accounting | |||||
Decrease in other adjustments to reconcile net margin to net cash provided by operating activities | $ (8,353,000) | (8,835,000) | (8,718,000) | ||
Decrease in cash paid for property additions | $ (495,426,000) | $ (534,171,000) | $ (628,216,000) | ||
Smarr EMC | |||||
Concentration | |||||
Summer planning reserve capacity of generating units (in megawatts) | MW | 718 | ||||
Total operating revenues | Revenues of members | Cobb EMC | |||||
Concentration | |||||
Operating revenues (as a percent) | 13.10% | 13.60% | 13.20% | ||
Total operating revenues | Revenues of members | Sawnee EMC | |||||
Concentration | |||||
Operating revenues (as a percent) | 10.40% | 9.50% | 9.50% | ||
Total operating revenues | Revenues of members | Jackson EMC | |||||
Concentration | |||||
Operating revenues (as a percent) | 9.70% | 10.40% | 10.90% | ||
Adjustments | |||||
Basis of accounting | |||||
Decrease in other adjustments to reconcile net margin to net cash provided by operating activities | $ 24,607,000 | ||||
Decrease in cash paid for property additions | $ 24,607,000 |
Summary of significant accoun35
Summary of significant accounting policies: Nuclear fuel cost information (Details) - USD ($) | 1 Months Ended | 12 Months Ended | |||
Apr. 30, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 14, 2014 | |
Receivables | |||||
Member receivables | $ 108,729,000 | $ 114,808,000 | |||
Nuclear fuel cost | |||||
Nuclear fuel expense | 78,762,000 | $ 85,166,000 | $ 86,828,000 | ||
Nuclear Fuel Disposal Cost Settlement, January 1, 2005 through December 31, 2010 | Plant Hatch and Plant Vogtle | |||||
Nuclear fuel cost | |||||
Settlement amount, entity share | $ 10,949,000 | ||||
Settlement amount, all parties | $ 36,474,000 | ||||
Reduction of total operating expenses | 7,320,000 | ||||
Reduction to plant in service | $ 3,629,000 | ||||
Nuclear Fuel Disposal Cost Settlement, January 1, 2011 through December 31, 2013 | Plant Hatch and Plant Vogtle | |||||
Nuclear fuel cost | |||||
Damages receivable | $ 0 |
Summary of significant accoun36
Summary of significant accounting policies: Asset retirement obligations (Details) - USD ($) | Apr. 17, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Asset Retirement Obligations | ||||
Balance at the beginning of the period | $ 432,260,000 | $ 408,050,000 | ||
Liabilities settled | (299,000) | (406,000) | ||
Accretion | 26,108,000 | 24,616,000 | $ 22,900,000 | |
Change in Cash Flow Estimates | $ 49,084,000 | 144,161,000 | ||
Balance at the end of the period | $ 602,230,000 | 432,260,000 | 408,050,000 | |
Assumed escalation rate for labor, material and equipment (as a percent) | 2.50% | |||
Fair value of external trust fund | $ 363,829,000 | 366,004,000 | ||
Hatch Unit No. 1 | ||||
Asset Retirement Obligations | ||||
Estimated costs based on site study | 258,000,000 | |||
Hatch Unit No. 1 | Radiated structures | ||||
Asset Retirement Obligations | ||||
Estimated costs based on site study | 193,000,000 | |||
Hatch Unit No. 1 | Spent fuel management | ||||
Asset Retirement Obligations | ||||
Estimated costs based on site study | 49,000,000 | |||
Hatch Unit No. 1 | Non-radiated structures | ||||
Asset Retirement Obligations | ||||
Estimated costs based on site study | 16,000,000 | |||
Hatch Unit No. 2 | ||||
Asset Retirement Obligations | ||||
Estimated costs based on site study | 282,000,000 | |||
Hatch Unit No. 2 | Radiated structures | ||||
Asset Retirement Obligations | ||||
Estimated costs based on site study | 213,000,000 | |||
Hatch Unit No. 2 | Spent fuel management | ||||
Asset Retirement Obligations | ||||
Estimated costs based on site study | 47,000,000 | |||
Hatch Unit No. 2 | Non-radiated structures | ||||
Asset Retirement Obligations | ||||
Estimated costs based on site study | 22,000,000 | |||
Vogtle Unit No. 1 | ||||
Asset Retirement Obligations | ||||
Estimated costs based on site study | 253,000,000 | |||
Vogtle Unit No. 1 | Radiated structures | ||||
Asset Retirement Obligations | ||||
Estimated costs based on site study | 178,000,000 | |||
Vogtle Unit No. 1 | Spent fuel management | ||||
Asset Retirement Obligations | ||||
Estimated costs based on site study | 49,000,000 | |||
Vogtle Unit No. 1 | Non-radiated structures | ||||
Asset Retirement Obligations | ||||
Estimated costs based on site study | 26,000,000 | |||
Vogtle Unit No. 2 | ||||
Asset Retirement Obligations | ||||
Estimated costs based on site study | 275,000,000 | |||
Vogtle Unit No. 2 | Radiated structures | ||||
Asset Retirement Obligations | ||||
Estimated costs based on site study | 195,000,000 | |||
Vogtle Unit No. 2 | Spent fuel management | ||||
Asset Retirement Obligations | ||||
Estimated costs based on site study | 47,000,000 | |||
Vogtle Unit No. 2 | Non-radiated structures | ||||
Asset Retirement Obligations | ||||
Estimated costs based on site study | 33,000,000 | |||
Nuclear | ||||
Asset Retirement Obligations | ||||
Balance at the beginning of the period | 369,046,000 | 347,201,000 | ||
Accretion | 23,231,000 | 21,845,000 | ||
Change in Cash Flow Estimates | 96,181,000 | |||
Balance at the end of the period | 488,458,000 | 369,046,000 | 347,201,000 | |
Coal Ash Pond | ||||
Asset Retirement Obligations | ||||
Balance at the beginning of the period | 42,609,000 | 40,760,000 | ||
Accretion | 1,929,000 | 1,849,000 | ||
Change in Cash Flow Estimates | 49,084,000 | |||
Balance at the end of the period | 93,622,000 | 42,609,000 | 40,760,000 | |
Other | ||||
Asset Retirement Obligations | ||||
Balance at the beginning of the period | 20,605,000 | 20,089,000 | ||
Liabilities settled | (299,000) | (406,000) | ||
Accretion | 948,000 | 922,000 | ||
Change in Cash Flow Estimates | (1,104,000) | |||
Balance at the end of the period | $ 20,150,000 | $ 20,605,000 | $ 20,089,000 |
Summary of significant accoun37
Summary of significant accounting policies: Nuclear decommissioning information (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Summary of significant accounting policies: | ||
Additional contribution to external trust funds | $ 0 | $ 0 |
Diversified mix of equity under external trust fund (as a percent) | 60.00% | |
Diversified mix of fixed income securities under external trust fund (as a percent) | 40.00% | |
Unrestricted Long term investments associated with internal decommissioning fund | $ 63,326,000 | 59,080,000 |
Additional amount collected for nuclear decommissioning | $ 4,750,000 | 2,975,000 |
Earning rate assumed on decommissioning trust fund (as a percent) | 6.00% | |
Earnings on fund assets | $ 40,380,000 | $ 23,507,000 |
Average annualized return produced by the nuclear decommissioning trust fund (as a percent) | 7.10% |
Summary of significant accoun38
Summary of significant accounting policies: Annual depreciation rates (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Depreciation | |||
Depreciation expense | $ 180,866,000 | $ 178,302,000 | $ 171,240,000 |
Electric plant | |||
Construction rates for allowance of funds (as a percent) | 4.73% | 4.97% | 4.93% |
Restricted cash and investments | |||
Guaranteed interest rate on deposit with Rural Utilities Service (as a percent) | 5.00% | 5.00% | |
Restricted cash and investments | $ 387,961,000 | $ 365,585,000 | |
Restricted cash and investments - long-term | 134,690,000 | 118,390,000 | |
Inventories | |||
Fossil fuels inventories | 104,086,000 | 98,789,000 | |
Spare parts | $ 195,166,000 | $ 172,060,000 | |
Steam production | |||
Depreciation | |||
Annual depreciation rates (as a percent) | 1.93% | 1.86% | 1.82% |
Steam production | Minimum | |||
Depreciation | |||
Range of Useful Life | 49 years | ||
Steam production | Maximum | |||
Depreciation | |||
Range of Useful Life | 65 years | ||
Nuclear production | |||
Depreciation | |||
Annual depreciation rates (as a percent) | 1.55% | 1.53% | 1.54% |
Nuclear production | Minimum | |||
Depreciation | |||
Range of Useful Life | 37 years | ||
Nuclear production | Maximum | |||
Depreciation | |||
Range of Useful Life | 60 years | ||
Hydro production | |||
Depreciation | |||
Range of Useful Life | 50 years | ||
Annual depreciation rates (as a percent) | 2.00% | 2.00% | 2.00% |
Other production | |||
Depreciation | |||
Annual depreciation rates (as a percent) | 2.38% | 2.56% | 2.55% |
Other production | Minimum | |||
Depreciation | |||
Range of Useful Life | 27 years | ||
Other production | Maximum | |||
Depreciation | |||
Range of Useful Life | 33 years | ||
Transmission | |||
Depreciation | |||
Range of Useful Life | 36 years | ||
Annual depreciation rates (as a percent) | 2.75% | 2.75% | 2.75% |
General | Minimum | |||
Depreciation | |||
Range of Useful Life | 3 years | ||
Annual depreciation rates (as a percent) | 2.00% | 2.00% | 2.00% |
General | Maximum | |||
Depreciation | |||
Range of Useful Life | 50 years | ||
Annual depreciation rates (as a percent) | 33.33% | 33.33% | 33.33% |
Summary of significant accoun39
Summary of significant accounting policies: Regulatory assets and liabilities (Details) | 12 Months Ended | ||
Dec. 31, 2015USD ($)item | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | |
Regulatory Assets and Liabilities | |||
Total Regulatory Assets | $ 530,254,000 | $ 484,049,000 | |
Total Regulatory Liabilities | 166,967,000 | 194,073,000 | |
Net Regulatory Assets | $ 363,287,000 | 289,976,000 | |
Related parties | |||
Number of electric distribution cooperative members | item | 38 | ||
Other income | |||
Capital credits from associated companies | $ 1,859,000 | 1,986,000 | $ 1,954,000 |
Net revenue from Georgia Transmission and Georgia System Operations for shared Administrative and General costs | 6,278,000 | 4,944,000 | 4,459,000 |
Miscellaneous other | 1,006,000 | (310,000) | (723,000) |
Total | $ 9,143,000 | 6,620,000 | 5,690,000 |
Georgia Transmission | |||
Related parties | |||
Number of electric distribution cooperative members | item | 38 | ||
Expenses incurred for transmission services, system operations services and administrative support services | $ 28,172,000 | 27,893,000 | 27,599,000 |
Georgia System Operations Corporation | |||
Related parties | |||
Number of electric distribution cooperative members | item | 38 | ||
Expenses incurred for transmission services, system operations services and administrative support services | $ 22,616,000 | 27,893,000 | $ 27,599,000 |
Accumulated retirement costs for other obligations | |||
Regulatory Assets and Liabilities | |||
Total Regulatory Liabilities | 8,910,000 | 18,559,000 | |
Deferral of effects on net margin- Hawk Road Energy Facility | Hawk Road | |||
Regulatory Assets and Liabilities | |||
Total Regulatory Liabilities | 20,775,000 | 29,867,000 | |
Major maintenance reserve | |||
Regulatory Assets and Liabilities | |||
Total Regulatory Liabilities | 22,422,000 | 23,427,000 | |
Amortization on Capital Leases | |||
Regulatory Assets and Liabilities | |||
Total Regulatory Liabilities | 26,502,000 | 21,693,000 | |
Deferred debt service adder | |||
Regulatory Assets and Liabilities | |||
Total Regulatory Liabilities | 76,334,000 | 66,754,000 | |
Asset retirement obligations. | |||
Regulatory Assets and Liabilities | |||
Total Regulatory Liabilities | 8,316,000 | 28,870,000 | |
Other regulatory liabilities | |||
Regulatory Assets and Liabilities | |||
Total Regulatory Liabilities | $ 3,708,000 | 4,903,000 | |
Other regulatory liabilities | Maximum | |||
Regulatory Assets and Liabilities | |||
Amortization period | 11 years | ||
Premium and loss on reacquired debt | |||
Regulatory Assets and Liabilities | |||
Total Regulatory Assets | $ 61,916,000 | 71,731,000 | |
Premium and loss on reacquired debt | Maximum | |||
Regulatory Assets and Liabilities | |||
Amortization period | 28 years | ||
Amortization on capital leases | |||
Regulatory Assets and Liabilities | |||
Total Regulatory Assets | $ 30,253,000 | 27,829,000 | |
Outage costs | |||
Regulatory Assets and Liabilities | |||
Total Regulatory Assets | 42,027,000 | 45,795,000 | |
Interest rate swap termination fees | |||
Regulatory Assets and Liabilities | |||
Total Regulatory Assets | 5,355,000 | 9,345,000 | |
Depreciation expense | |||
Regulatory Assets and Liabilities | |||
Total Regulatory Assets | $ 45,514,000 | 46,938,000 | |
Depreciation expense | Plant Vogtle | |||
Regulatory Assets and Liabilities | |||
Operating license expected extension period for Plant Vogtle | 20 years | ||
Operating license, expected extension period, for Plant Vogtle | 40 years | ||
Deferred charges related to Vogtle Units No. 3 and No. 4 training costs | Vogtle Units Number 3 And Number 4 | |||
Regulatory Assets and Liabilities | |||
Total Regulatory Assets | $ 37,646,000 | 32,501,000 | |
Interest rate options cost | |||
Regulatory Assets and Liabilities | |||
Total Regulatory Assets | 102,554,000 | 98,671,000 | |
Deferral of effects on net margin - Smith Energy Facility | Smith | |||
Regulatory Assets and Liabilities | |||
Total Regulatory Assets | 178,343,000 | 128,666,000 | |
Other regulatory assets | |||
Regulatory Assets and Liabilities | |||
Total Regulatory Assets | $ 26,646,000 | $ 22,573,000 | |
Other regulatory assets | Maximum | |||
Regulatory Assets and Liabilities | |||
Amortization period | 34 years | ||
Coal-fired outage costs | |||
Regulatory Assets and Liabilities | |||
Amortization period | 24 months | ||
Nuclear refueling outage costs | Minimum | |||
Regulatory Assets and Liabilities | |||
Amortization period | 18 months | ||
Nuclear refueling outage costs | Maximum | |||
Regulatory Assets and Liabilities | |||
Amortization period | 24 months |
Summary of significant accoun40
Summary of significant accounting policies: New accounting pronouncements (Details) - USD ($) | Dec. 31, 2015 | Dec. 31, 2014 |
New Accounting Pronouncements | ||
Deferred costs | $ (93,651,000) | $ (97,423,000) |
Long-term debt | $ (7,291,154,000) | (7,015,577,000) |
Accounting Standards Update 2015-03 - Simplifying the Presentation of Debt Issuance Costs | Adjustments for New Accounting Principle, Early Adoption | ||
New Accounting Pronouncements | ||
Deferred costs | 97,423,000 | |
Long-term debt | $ 97,423,000 |
Fair Value_ Asset and liabiliti
Fair Value: Asset and liabilities measured at fair value on a recurring basis (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Fair value measurement | ||
Long-term investments | $ 86,771,000 | $ 85,728,000 |
Interest rate options | ||
Fair value measurement | ||
Derivative assets | 1,010,000 | 4,371,000 |
International equity trust | ||
Fair value measurement | ||
Unfunded commitments | $ 0 | |
Notice period for redemptions | 3 days | |
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic equity | ||
Fair value measurement | ||
Nuclear decommissioning trust funds | $ 151,178,000 | 159,536,000 |
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | US Treasury and government agency securities | ||
Fair value measurement | ||
Nuclear decommissioning trust funds | 74,698,000 | 68,854,000 |
Long-term investments | 13,772,000 | 16,619,000 |
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other | ||
Fair value measurement | ||
Nuclear decommissioning trust funds | 4,772,000 | 13,803,000 |
Long-term investments | 479,000 | 118,000 |
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Mutual funds | ||
Fair value measurement | ||
Long-term investments | 48,649,000 | 51,741,000 |
Recurring basis | Significant Other Observable Inputs (Level 2) | Natural gas swaps | ||
Fair value measurement | ||
Derivative assets | 24,995,000 | 18,914,000 |
Recurring basis | Significant Other Observable Inputs (Level 2) | International equity trust | ||
Fair value measurement | ||
Nuclear decommissioning trust funds | 68,753,000 | 72,474,000 |
Long-term investments | 12,846,000 | 11,162,000 |
Recurring basis | Significant Other Observable Inputs (Level 2) | Corporate bonds | ||
Fair value measurement | ||
Nuclear decommissioning trust funds | 48,450,000 | 34,446,000 |
Long-term investments | 9,903,000 | 5,445,000 |
Recurring basis | Significant Other Observable Inputs (Level 2) | US Treasury and government agency securities | ||
Fair value measurement | ||
Nuclear decommissioning trust funds | 475,000 | |
Recurring basis | Significant Other Observable Inputs (Level 2) | Agency mortgage and asset backed securities | ||
Fair value measurement | ||
Nuclear decommissioning trust funds | 15,503,000 | 16,148,000 |
Long-term investments | 1,121,000 | 643,000 |
Recurring basis | Significant Other Observable Inputs (Level 2) | Municipal Bonds | ||
Fair value measurement | ||
Nuclear decommissioning trust funds | 743,000 | |
Recurring basis | Significant Unobservable Inputs (Level 3) | Interest rate options | ||
Fair value measurement | ||
Derivative assets | 1,010,000 | 4,371,000 |
Recurring basis | Total Fair Value | Interest rate options | ||
Fair value measurement | ||
Derivative assets | 1,010,000 | 4,371,000 |
Recurring basis | Total Fair Value | Natural gas swaps | ||
Fair value measurement | ||
Derivative assets | 24,995,000 | 18,914,000 |
Recurring basis | Total Fair Value | Domestic equity | ||
Fair value measurement | ||
Nuclear decommissioning trust funds | 151,178,000 | 159,536,000 |
Recurring basis | Total Fair Value | International equity trust | ||
Fair value measurement | ||
Nuclear decommissioning trust funds | 68,753,000 | 72,474,000 |
Long-term investments | 12,846,000 | 11,162,000 |
Recurring basis | Total Fair Value | Corporate bonds | ||
Fair value measurement | ||
Nuclear decommissioning trust funds | 48,450,000 | 34,446,000 |
Long-term investments | 9,903,000 | 5,445,000 |
Recurring basis | Total Fair Value | US Treasury and government agency securities | ||
Fair value measurement | ||
Nuclear decommissioning trust funds | 75,173,000 | 68,854,000 |
Long-term investments | 13,772,000 | 16,619,000 |
Recurring basis | Total Fair Value | Agency mortgage and asset backed securities | ||
Fair value measurement | ||
Nuclear decommissioning trust funds | 15,503,000 | 16,148,000 |
Long-term investments | 1,121,000 | 643,000 |
Recurring basis | Total Fair Value | Municipal Bonds | ||
Fair value measurement | ||
Nuclear decommissioning trust funds | 743,000 | |
Recurring basis | Total Fair Value | Other | ||
Fair value measurement | ||
Nuclear decommissioning trust funds | 4,772,000 | 13,803,000 |
Long-term investments | 479,000 | 118,000 |
Recurring basis | Total Fair Value | Mutual funds | ||
Fair value measurement | ||
Long-term investments | $ 48,649,000 | $ 51,741,000 |
Fair Value_ Change in Level 3 a
Fair Value: Change in Level 3 assets (Details) - Interest rate options - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Assets (Liabilities): | ||
Balance at the beginning of the period | $ 4,371 | $ 63,471 |
Total gains or losses (realized/unrealized): | ||
Included in earnings (or changes in net assets) | (3,361) | (59,100) |
Balance at the end of the period | $ 1,010 | $ 4,371 |
Fair Value_ Estimated fair valu
Fair Value: Estimated fair value of long-term debt (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Carrying Value | ||
Grouping Financial Statement Captions | ||
Long-term debt | $ 7,575,027 | $ 7,256,995 |
Total Fair Value | ||
Grouping Financial Statement Captions | ||
Long-term debt | $ 8,445,630 | $ 8,460,685 |
Derivative instruments_ Volume
Derivative instruments: Volume activity of natural gas derivatives (Details) item in Millions | Dec. 31, 2015USD ($)item | Dec. 31, 2014USD ($) |
Gas hedges | ||
Letters of credit required to be posted with counterparties, if credit-risk-related contingent features were triggered due to credit rating being downgraded below investment grade | $ | $ 24,995,000 | |
Natural gas swaps | ||
Gas hedges | ||
Fair Value of liabilities | $ | $ 22,848,000 | $ 18,914,000 |
Derivative volume activity that is expected to settle or mature each year (in MMBTUs) | 54.7 | |
Natural gas swaps | 2016 | ||
Gas hedges | ||
Derivative volume activity that is expected to settle or mature each year (in MMBTUs) | 23.1 | |
Natural gas swaps | 2017 | ||
Gas hedges | ||
Derivative volume activity that is expected to settle or mature each year (in MMBTUs) | 15.6 | |
Natural gas swaps | 2018 | ||
Gas hedges | ||
Derivative volume activity that is expected to settle or mature each year (in MMBTUs) | 10 | |
Natural gas swaps | 2019 | ||
Gas hedges | ||
Derivative volume activity that is expected to settle or mature each year (in MMBTUs) | 6 |
Derivative instruments_ Interes
Derivative instruments: Interest rate options (Details) - Interest rate options | 3 Months Ended | ||
Dec. 31, 2011USD ($)item | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | |
Derivative instruments and hedging activities | |||
Purchased amount of derivative instrument | $ 100,000,000 | ||
Number of nuclear units expected to be financed | item | 2 | ||
Derivative notional amount expired | $ 1,788,502,000 | ||
Derivative remaining notional amount | 390,702,000 | ||
Cash settlement value, if swap rates are at or below the specified fixed rate on the expiration date | $ 0 | ||
Weighted average fixed rate (as a percent) | 3.95% | ||
Notional amount of derivatives, expired without value | $ 470,625,000 | ||
Fair value of assets | 1,010,000 | $ 4,371,000 | |
Funds posted as collateral of the counterparties | 0 | $ 0 | |
Notional Dollar Amount | $ 390,702,000 | ||
LIBOR | |||
Derivative instruments and hedging activities | |||
Variable rate basis | LIBOR | ||
Basis spread (as a percent) | 1.51% | ||
2,016 | |||
Derivative instruments and hedging activities | |||
Notional Dollar Amount | $ 310,533,000 | ||
2,017 | |||
Derivative instruments and hedging activities | |||
Notional Dollar Amount | 80,169,000 | ||
Minimum | |||
Derivative instruments and hedging activities | |||
Collateral thresholds range | 0 | ||
Maximum | |||
Derivative instruments and hedging activities | |||
Collateral thresholds range | 10,000,000 | ||
Department of Energy-guaranteed loan | |||
Derivative instruments and hedging activities | |||
Hedged amount of expected debt | $ 2,200,000,000 | $ 2,200,000,000 |
Derivative instruments_ Fair va
Derivative instruments: Fair value of derivative instruments not designated as hedging (Details) - USD ($) | Dec. 31, 2015 | Dec. 31, 2014 |
Interest rate options | ||
Assets: | ||
Fair value of assets | $ 1,010,000 | $ 4,371,000 |
Natural gas swaps | ||
Liabilities: | ||
Fair Value of liabilities | 22,848,000 | 18,914,000 |
Not designated as hedges | Interest rate options | ||
Assets: | ||
Fair value of assets | 1,010,000 | 4,371,000 |
Not designated as hedges | Natural gas swaps | ||
Liabilities: | ||
Fair Value of liabilities | $ 22,848,000 | $ 18,914,000 |
Derivative instruments_ Realize
Derivative instruments: Realized and unrealized gains and (losses) on derivative instruments (Details) - Not designated as hedges - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Effect of Derivative Instruments on the Condensed Statement of Revenues and Expenses or Balance Sheet | |||
Total gains (losses) on derivatives | $ (19,896) | $ 848 | $ (3,312) |
Unrealized gains and (losses) on derivatives | (48,763) | (68,146) | |
Natural gas swaps | Regulatory Asset | |||
Effect of Derivative Instruments on the Condensed Statement of Revenues and Expenses or Balance Sheet | |||
Unrealized losses on derivatives | (22,848) | (18,914) | |
Natural gas swaps | Fuel | |||
Effect of Derivative Instruments on the Condensed Statement of Revenues and Expenses or Balance Sheet | |||
Gains | 206 | 1,881 | 739 |
Losses | (20,102) | (1,033) | $ (4,051) |
Interest rate options | Regulatory Asset | |||
Effect of Derivative Instruments on the Condensed Statement of Revenues and Expenses or Balance Sheet | |||
Unrealized losses on derivatives | $ (25,915) | $ (49,232) |
Derivative instruments_ Master
Derivative instruments: Master netting agreements (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Natural gas swaps | ||
Assets: | ||
Gross Amounts of Recognized Assets (Liabilities) | $ (22,848) | $ (18,914) |
Net Amounts of Assets Presented on the Balance Sheet | (22,848) | (18,914) |
Interest rate options | ||
Assets: | ||
Gross Amounts of Recognized Assets (Liabilities) | 26,925 | 53,603 |
Gross Amounts offset on the Balance Sheets | (25,915) | (49,232) |
Net Amounts of Assets Presented on the Balance Sheet | $ 1,010 | $ 4,371 |
Investments_ Activity and matur
Investments: Activity and maturities of available-for-sale securities (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Investments: | ||
Available-for-sale securities, gross unrealized losses that were in effect for less than one year (as a percent) | 27.00% | |
Available-for-sale securities | ||
Cost | $ 425,078 | $ 383,001 |
Gains | 38,652 | 79,517 |
Losses | (13,130) | (10,786) |
Fair Value | 450,600 | 451,732 |
Equity | ||
Available-for-sale securities | ||
Cost | 230,123 | 200,892 |
Gains | 37,494 | 69,536 |
Losses | (9,635) | (2,163) |
Fair Value | 257,982 | 268,265 |
Debt. | ||
Available-for-sale securities | ||
Cost | 189,700 | 168,182 |
Gains | 1,158 | 9,981 |
Losses | (3,491) | (8,619) |
Fair Value | 187,367 | 169,544 |
Cost | ||
Due within one year | 8,559 | 1,744 |
Due after one year through five years | 50,018 | 48,105 |
Due after five years through ten years | 56,448 | 67,103 |
Due after ten years | 74,675 | 51,230 |
Total | 189,700 | 168,182 |
Fair Value | ||
Due within one year | 8,612 | 1,790 |
Due after one year through five years | 49,538 | 47,508 |
Due after five years through ten years | 55,880 | 67,665 |
Due after ten years | 73,337 | 52,581 |
Total | 187,367 | 169,544 |
Other | ||
Available-for-sale securities | ||
Cost | 5,255 | 13,927 |
Losses | (4) | (4) |
Fair Value | $ 5,251 | $ 13,923 |
Investments_ Investment gains,
Investments: Investment gains, losses and proceeds and investment in associated companies (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Investments: | |||
Gross realized gains | $ 53,453 | $ 64,437 | $ 46,647 |
Gross realized losses | (18,989) | (46,258) | (21,685) |
Proceeds from sales | 640,217 | 438,941 | $ 605,364 |
Investment in associated companies | |||
Investment in associated companies | 72,010 | 67,368 | |
National Rural Utilities Cooperative Finance Corporation | |||
Investment in associated companies | |||
Investment in associated companies | 24,040 | 24,030 | |
CT Parts, LLC | |||
Investment in associated companies | |||
Investment in associated companies | 11,067 | 9,939 | |
Georgia Transmission Corporation | |||
Investment in associated companies | |||
Investment in associated companies | 25,872 | 24,254 | |
Georgia System Operations Corporation | |||
Investment in associated companies | |||
Investment in associated companies | 7,200 | 5,200 | |
Other | |||
Investment in associated companies | |||
Investment in associated companies | $ 3,831 | $ 3,945 |
Investments_ Rocky Mountain inf
Investments: Rocky Mountain information (Details) - Rocky Mountain | 2 Months Ended | 12 Months Ended |
Jan. 31, 1997item | Dec. 31, 2012USD ($)item | |
Rocky Mountain Lease Transaction | ||
Number of long-term lease transactions | 6 | |
Percentage of undivided ownership interest | 74.61% | |
Number of separate owner trusts to whom undivided interest was leased | 6 | |
Number of investors in ownership trusts | 3 | |
Term of lease as a percentage of the estimated useful life of the jointly owned utility plant | 120.00% | |
Term of lease | 30 years | |
Number of leases terminated prior to end of lease term | 5 | |
Percentage of leases which remained in place | 10.00% | |
Basic rental payments due | $ | $ 59,209,000 |
Income taxes_ Statutory federal
Income taxes: Statutory federal and effective income tax rate and components of deferred tax assets and liabilities (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Income taxes: | |||
Current period income tax expense | $ 0 | ||
Current income tax liability | $ 0 | ||
Difference between statutory federal income tax rate on income before income taxes and effective income tax rate | |||
Statutory federal income tax rate (as a percent) | 35.00% | 35.00% | 35.00% |
Patronage exclusion (as a percent) | (34.70%) | (34.40%) | (33.30%) |
Other (as a percent) | (0.30%) | (0.60%) | (1.70%) |
Effective income tax rate (as a percent) | 0.00% | 0.00% | 0.00% |
Deferred tax assets | |||
Net operating losses | $ 29,724,000 | $ 29,724,000 | |
Tax credits (alternative minimum tax and other) | 1,198,000 | 1,275,000 | |
Accounting for Rocky Mountain transactions | 348,779,000 | 348,460,000 | |
Other assets | 107,527,000 | 100,203,000 | |
Deferred tax assets, gross | 487,228,000 | 479,662,000 | |
Less: Valuation allowance | (29,724,000) | (30,999,000) | |
Net deferred tax assets | 457,504,000 | 448,663,000 | |
Deferred tax liabilities | |||
Depreciation | 426,173,000 | 444,139,000 | |
Accounting for Rocky Mountain transactions | 167,907,000 | 165,462,000 | |
Other liabilities | 131,454,000 | 112,732,000 | |
Deferred tax liabilities, gross | 725,534,000 | 722,333,000 | |
Net deferred tax liabilities | 268,030,000 | 273,670,000 | |
Less: Patronage exclusion | $ (268,030,000) | $ (273,670,000) |
Income taxes_ NOLs and alternat
Income taxes: NOLs and alternative minimum tax credits (Details) $ in Thousands | Dec. 31, 2015USD ($) |
Income taxes | |
NOLs | $ 76,411 |
Alternative Minimum Tax Credits | |
Income taxes | |
Tax Credits | 1,198 |
2,018 | |
Income taxes | |
NOLs | 61,533 |
2,019 | |
Income taxes | |
NOLs | 10,516 |
2,020 | |
Income taxes | |
NOLs | 4,362 |
None | Alternative Minimum Tax Credits | |
Income taxes | |
Tax Credits | $ 1,198 |
Income taxes_ Other tax informa
Income taxes: Other tax information (Details) | 12 Months Ended |
Dec. 31, 2015USD ($) | |
Income taxes | |
Uncertain tax positions | $ 0 |
State jurisdictions | Maximum | |
Income taxes | |
Period during which state impact of any federal changes remains subject to examination by various states | 1 year |
Capital leases_ (Details)
Capital leases: (Details) $ in Thousands | 1 Months Ended | 12 Months Ended | |||
Jun. 30, 2012item | Dec. 31, 2000item | Dec. 31, 1985item | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | |
Minimum lease payments under the capital leases together with the present value of the net minimum lease payments | |||||
Long-term balance | $ 96,501 | $ 100,456 | |||
Assumed interest rate on lease obligation (as a percent) | 11.05% | ||||
Lease renewal through December 31, 2027 | |||||
Capital leases | |||||
Number of leases for which lease term is extended | item | 3 | ||||
Lease renewal through June 30, 2031 | |||||
Capital leases | |||||
Number of leases for which lease term is extended | item | 1 | ||||
Scherer Unit Number 2 | |||||
Capital leases | |||||
Number of purchasers from which entity sold and leased back assets | item | 4 | ||||
Percentage of undivided ownership interest of purchasers in assets under lease | 60.00% | ||||
Minimum lease payments under the capital leases together with the present value of the net minimum lease payments | |||||
2,016 | 14,949 | ||||
2,017 | 14,949 | ||||
2,018 | 14,949 | ||||
2,019 | 14,949 | ||||
2,020 | 14,949 | ||||
2021-2031 | 115,331 | ||||
Total minimum lease payments | 190,076 | ||||
Less: Amount representing interest | (89,620) | ||||
Present value of net minimum lease payments | 100,456 | ||||
Less: Current portion | (3,955) | ||||
Long-term balance | $ 96,501 | ||||
Doyle | |||||
Capital leases | |||||
Number of unit generation facilities | item | 5 | ||||
Agreement period | 15 years |
Debt_ (Details)
Debt: (Details) | Mar. 23, 2015USD ($)item | Jan. 31, 2016USD ($) | Dec. 31, 2015USD ($)item | Dec. 31, 2014USD ($) | Feb. 20, 2014USD ($)item |
Maturities for long-term debt and capital lease obligations | |||||
Weighted average interest rate on short-term borrowings (as a percent) | 0.43% | 0.28% | |||
Principal | $ 7,575,027,000 | $ 7,256,995,000 | |||
Unamortized Debt Issuance Costs and Debt Discounts | 97,988,000 | $ 101,939,000 | |||
Long Term Debt And Capital Lease Obligations | |||||
Maturities for long-term debt and capital lease obligations | |||||
2,016 | 189,840,000 | ||||
2,017 | 187,698,000 | ||||
2,018 | 193,457,000 | ||||
2,019 | 511,459,000 | ||||
2,020 | 345,556,000 | ||||
Long Term Debt | |||||
Maturities for long-term debt and capital lease obligations | |||||
2,016 | 185,885,000 | ||||
2,017 | 183,294,000 | ||||
2,018 | 188,552,000 | ||||
2,019 | 505,997,000 | ||||
2,020 | $ 339,474,000 | ||||
Weighted average interest rate on long-term debt | 4.45% | 4.55% | |||
Facility | |||||
Debt | |||||
Borrowings guaranteed | $ 1,180,628,000 | ||||
Maturities for long-term debt and capital lease obligations | |||||
2,016 | 145,846,000 | ||||
2,017 | 143,110,000 | ||||
2,018 | 148,210,000 | ||||
2,019 | 153,233,000 | ||||
2,020 | 156,998,000 | ||||
Principal | 3,777,540,000 | $ 3,456,953,000 | |||
Unamortized Debt Issuance Costs and Debt Discounts | 56,851,000 | 58,417,000 | |||
Line of credit, amount outstanding | 270,000,000 | ||||
Number of future advance promissory notes | item | 2 | ||||
Facility | Maximum | |||||
Debt | |||||
Capitalized interest | $ 335,471,604 | ||||
Aggregate borrowings | $ 3,057,069,461 | ||||
FMBs | |||||
Maturities for long-term debt and capital lease obligations | |||||
2,016 | 1,010,000 | ||||
2,017 | 1,010,000 | ||||
2,018 | 1,010,000 | ||||
2,019 | 351,010,000 | ||||
2,020 | 1,010,000 | ||||
Principal | 2,809,093,000 | 2,810,103,000 | |||
Unamortized Debt Issuance Costs and Debt Discounts | 32,002,000 | 33,782,000 | |||
PCBs | |||||
Maturities for long-term debt and capital lease obligations | |||||
2,016 | 37,352,000 | ||||
2,017 | 37,352,000 | ||||
2,018 | 37,352,000 | ||||
2,020 | 181,075,000 | ||||
Principal | 980,770,000 | 980,770,000 | |||
Unamortized Debt Issuance Costs and Debt Discounts | 9,135,000 | 9,740,000 | |||
Series 2009 and Series 2010 pollution control bonds | |||||
Maturities for long-term debt and capital lease obligations | |||||
2,016 | 37,000,000 | ||||
2,017 | 37,000,000 | ||||
2,018 | 37,000,000 | ||||
2,020 | 134,000,000 | ||||
CFC | |||||
Maturities for long-term debt and capital lease obligations | |||||
2,016 | 891,000 | ||||
2,017 | 937,000 | ||||
2,018 | 984,000 | ||||
2,019 | 1,035,000 | ||||
2,020 | 391,000 | ||||
Principal | 4,238,000 | 5,085,000 | |||
CoBank | |||||
Maturities for long-term debt and capital lease obligations | |||||
2,016 | 786,000 | ||||
2,017 | 885,000 | ||||
2,018 | 996,000 | ||||
2,019 | 719,000 | ||||
Principal | 3,386,000 | $ 4,084,000 | |||
Capital Lease Obligations. | |||||
Maturities for long-term debt and capital lease obligations | |||||
2,016 | 3,955,000 | ||||
2,017 | 4,404,000 | ||||
2,018 | 4,905,000 | ||||
2,019 | 5,462,000 | ||||
2,020 | 6,082,000 | ||||
Committed credit arrangements | |||||
Debt | |||||
Aggregate borrowings | $ 1,210,000,000 | $ 1,610,000,000 | |||
Maturities for long-term debt and capital lease obligations | |||||
Number of separate facilities | item | 4 | ||||
Term of credit facility | 5 years | ||||
Number of lenders | item | 13 | ||||
Letter of credit | |||||
Debt | |||||
Aggregate borrowings | $ 760,000,000 | ||||
Maturities for long-term debt and capital lease obligations | |||||
Available borrowing capacity | 509,000,000 | ||||
Letters of credit, amount outstanding | 251,000,000 | ||||
Commercial paper | |||||
Maturities for long-term debt and capital lease obligations | |||||
Line of credit, amount outstanding | 261,000,000 | ||||
Rural Utilities Service Guaranteed Loans | |||||
Debt | |||||
Principal amount | $ 7,998,000 | $ 153,637,000 |
Electric plant, construction 57
Electric plant, construction and related agreements: Summary of plant investments and related accumulated depreciation (Details) - USD ($) | Dec. 31, 2015 | Dec. 31, 2014 |
Electric plant, construction and related agreements | ||
Investment | $ 8,596,148,000 | $ 8,345,241,000 |
Accumulated Depreciation | (3,925,838,000) | (3,762,690,000) |
Total construction work in progress | 2,868,669,000 | 2,374,392,000 |
Plant acquisition adjustments | 196,000,000 | 196,000,000 |
Vogtle Units Number 1 And Number 2 | ||
Electric plant, construction and related agreements | ||
Investment | 2,869,142,000 | 2,805,310,000 |
Accumulated Depreciation | $ (1,674,431,000) | (1,634,062,000) |
Ownership interest (as a percent) | 30.00% | |
Vogtle Units Number 3 And Number 4 | ||
Electric plant, construction and related agreements | ||
Investment | $ 22,557,000 | 18,267,000 |
Accumulated Depreciation | (891,000) | (637,000) |
Total construction work in progress | $ 2,724,543,000 | 2,268,344,000 |
Ownership interest (as a percent) | 30.00% | |
Hatch Units Number 1 And Number 2 | ||
Electric plant, construction and related agreements | ||
Investment | $ 767,019,000 | 695,392,000 |
Accumulated Depreciation | $ (391,822,000) | (377,902,000) |
Ownership interest (as a percent) | 30.00% | |
Wansley Units Number 1 And Number 2 | ||
Electric plant, construction and related agreements | ||
Investment | $ 499,180,000 | 474,740,000 |
Accumulated Depreciation | $ (163,266,000) | (157,543,000) |
Ownership interest (as a percent) | 30.00% | |
Scherer Unit Number 1 | ||
Electric plant, construction and related agreements | ||
Investment | $ 1,086,435,000 | 1,067,777,000 |
Accumulated Depreciation | $ (332,493,000) | (318,990,000) |
Ownership interest (as a percent) | 60.00% | |
Doyle | ||
Electric plant, construction and related agreements | ||
Investment | $ 124,051,000 | 126,990,000 |
Accumulated Depreciation | $ (90,590,000) | (95,644,000) |
Ownership interest (as a percent) | 100.00% | |
Rocky Mountain Units Number 1, Number 2 And Number 3 | ||
Electric plant, construction and related agreements | ||
Investment | $ 600,640,000 | 587,762,000 |
Accumulated Depreciation | $ (222,888,000) | (211,010,000) |
Ownership interest (as a percent) | 75.00% | |
Hartwell | ||
Electric plant, construction and related agreements | ||
Investment | $ 226,737,000 | 224,512,000 |
Accumulated Depreciation | $ (103,111,000) | (98,696,000) |
Ownership interest (as a percent) | 100.00% | |
Hawk Road | ||
Electric plant, construction and related agreements | ||
Investment | $ 243,517,000 | 242,293,000 |
Accumulated Depreciation | $ (70,832,000) | (65,931,000) |
Ownership interest (as a percent) | 100.00% | |
Talbot | ||
Electric plant, construction and related agreements | ||
Investment | $ 290,463,000 | 289,020,000 |
Accumulated Depreciation | $ (111,617,000) | (102,947,000) |
Ownership interest (as a percent) | 100.00% | |
Chattahoochee | ||
Electric plant, construction and related agreements | ||
Investment | $ 310,788,000 | 308,943,000 |
Accumulated Depreciation | $ (114,914,000) | (106,633,000) |
Ownership interest (as a percent) | 100.00% | |
Smith | ||
Electric plant, construction and related agreements | ||
Investment | $ 601,903,000 | 579,486,000 |
Accumulated Depreciation | $ (166,324,000) | (151,677,000) |
Ownership interest (as a percent) | 100.00% | |
Wansley | ||
Electric plant, construction and related agreements | ||
Investment | $ 3,582,000 | 3,582,000 |
Accumulated Depreciation | $ (3,513,000) | (3,377,000) |
Ownership interest (as a percent) | 30.00% | |
Transmission | ||
Electric plant, construction and related agreements | ||
Investment | $ 90,195,000 | 88,031,000 |
Accumulated Depreciation | (50,786,000) | (49,132,000) |
Other production | ||
Electric plant, construction and related agreements | ||
Investment | 116,396,000 | 112,431,000 |
Accumulated Depreciation | (73,442,000) | (63,427,000) |
Scherer Unit Number 2 | ||
Electric plant, construction and related agreements | ||
Investment | 743,543,000 | 720,705,000 |
Accumulated Depreciation | $ (354,918,000) | (325,082,000) |
Ownership interest (as a percent) | 60.00% | |
Environmental and other generation improvements | ||
Electric plant, construction and related agreements | ||
Total construction work in progress | $ 143,723,000 | 104,600,000 |
Other Construction Work In Progress | ||
Electric plant, construction and related agreements | ||
Total construction work in progress | $ 403,000 | $ 1,448,000 |
Electric plant, construction 58
Electric plant, construction and related agreements: Construction information (Details) - Vogtle Units Number 3 And Number 4 | Jan. 01, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 30, 2015USD ($) | Dec. 31, 2008USD ($)itemMW | Jan. 13, 2016USD ($) | Jun. 30, 2015USD ($) |
Construction | ||||||
Number of Westinghouse AP1000 nuclear generating units | item | 2 | |||||
Nominally rated generating capacity for each unit | MW | 1,100 | |||||
Ownership interest of nuclear units (as a percent) | 30.00% | |||||
Amount to be paid to the Contractor and capitalized to the project, contingent upon acquisition | $ 230,000,000 | |||||
Payments for Legal Settlements | $ 80,000,000 | $ 80,000,000 | ||||
Project budget including capital costs, allowance for funds used during construction and contingency amount | 5,000,000,000 | |||||
Total investment in additional vogtle units | $ 2,888,000,000 | |||||
Aggregate Damages Under Initial Complaint And Amended Counterclaim | ||||||
Construction | ||||||
Maximum additional capital cost under the provision | $ 470,000,000 | |||||
Amended counterclaim associated with design changes, delays in Project Schedule and issuance of permits and operating licenses | ||||||
Construction | ||||||
Maximum additional capital cost under the provision | $ 75,000,000 | |||||
Toshiba Corporation | Letter of credit | ||||||
Construction | ||||||
Letters of credit | $ 900,000,000 |
Employee benefit plans_ (Detail
Employee benefit plans: (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Employee benefit plans: | |||
Maximum percentage of eligible annual compensation that the employee can contribute subject to IRS limitations | 60.00% | ||
Percentage of employee's contribution percent matched | 75.00% | ||
Employer matching contribution, as a percent of employee's eligible compensation | 6.00% | ||
Amount of contributions to the matching feature of the 401(k) plan | $ 1,310,000 | $ 1,205,000 | $ 1,161,000 |
Contribution to employer retirement contribution feature (as a percent) | 8.00% | ||
Amount of contributions to the employer retirement contribution feature of the 401(k) plan | $ 2,611,000 | $ 2,441,000 | $ 2,289,000 |
Nuclear insurance_ (Details)
Nuclear insurance: (Details) | 12 Months Ended |
Dec. 31, 2015USD ($)item | |
Nuclear insurance: | |
Maximum fund for public liability claims arising from a single nuclear incident under Price-Anderson Act | $ 13,500,000,000 |
Maximum insurance coverage provided by American Nuclear Insurers to each nuclear plant | 375,000,000 |
Maximum amount that a company could be assessed per incident for each licensed reactor | 127,000,000 |
Maximum aggregate amount that a reactor can assess in a calendar period for each incident | $ 19,000,000 |
Number of nuclear reactors in which entity has ownership interest | item | 4 |
Maximum deferred premium amount which the entity could be assessed per incident on the basis of its joint ownership interest in four nuclear reactors | $ 152,000,000 |
Maximum deferred premium amount which the entity could be assessed per calendar year on the basis of its joint ownership interest in four nuclear reactors | $ 23,000,000 |
Period considered for inflation adjustment for maximum assessment per reactor and maximum yearly assessment | 5 years |
Maximum property damage insurance provided to nuclear generating facilities | $ 1,500,000,000 |
Additional coverage provided for losses in excess of primary coverage | 1,250,000,000 |
Sublimit for non-nuclear losses | 750,000,000 |
Maximum limits for accidental property damage occurring during construction under the policy | 2,750,000,000 |
Portion of the current maximum annual assessment for Georgia Power that would be payable by the entity based on ownership share | 41,000,000 |
Aggregate payment for claims resulting from terrorist acts in one year period | $ 3,200,000,000 |
Commitments_ (Details)
Commitments: (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Operating leases | |||
2,016 | $ 5,318,000 | ||
2,017 | 5,318,000 | ||
2,018 | 5,318,000 | ||
2,019 | 2,950,000 | ||
2,020 | 588,000 | ||
Rental expenses | 4,849,000 | $ 5,139,000 | $ 5,213,000 |
Nuclear Fuel | |||
Fuel: | |||
2,016 | 55,400,000 | ||
2,017 | 27,800,000 | ||
2,018 | 29,200,000 | ||
2,019 | 24,300,000 | ||
2,020 | 21,700,000 | ||
Thereafter | 60,800,000 | ||
Public Utilities Inventory Coal | |||
Fuel: | |||
2,016 | 29,658,000 | ||
2,017 | 15,342,000 | ||
2,018 | $ 8,117,000 |
Contingencies and Regulatory 62
Contingencies and Regulatory Matters: (Details) | Jan. 01, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 30, 2015USD ($) | Aug. 20, 2014item | Jul. 28, 2014item | Dec. 31, 2015item | Jun. 30, 2015USD ($) |
Nuclear Construction | |||||||
Number of electric distribution cooperative members | 38 | ||||||
Vogtle Units Number 3 And Number 4 | |||||||
Nuclear Construction | |||||||
Amount to be paid to the Contractor and capitalized to the project, contingent upon acquisition | $ | $ 230,000,000 | ||||||
Payments for Legal Settlements | $ | $ 80,000,000 | $ 80,000,000 | |||||
Aggregate Damages Under Initial Complaint And Amended Counterclaim | Vogtle Units Number 3 And Number 4 | |||||||
Nuclear Construction | |||||||
Contractor's estimated adjustment attributable to the entity | $ | $ 470,000,000 | ||||||
Patronage Capital Litigation | |||||||
Nuclear Construction | |||||||
Number of defendant members | 2 | 3 | |||||
Number of excluded members against whom defendant class action is certified | 1 | ||||||
Number of electric distribution cooperative members | 38 | ||||||
Number of former consumer members | 4 | ||||||
Number of members in which the former consumer members filing the lawsuit belonged | 4 | ||||||
Percentage of cooperatives total booked patronage capital | 30.00% | ||||||
Number of current consumer members | 2 | ||||||
Number of plaintiffs' classes | 3 | ||||||
Patronage Capital Litigation | Maximum | |||||||
Nuclear Construction | |||||||
Period of revolving schedule to retire the patronage capital of former consumer-members | 13 years | ||||||
Period of revolving schedule to adopt policies to periodically retire the patronage capital of all consumer-members | 13 years |
Purchase Agreements_ (Details)
Purchase Agreements: (Details) - Precedent Agreement - Transcontinental Gas Pipeline Company, LLC (Transco) | Apr. 11, 2014USD ($) |
Purchase Agreements | |
Base term of an agreement | 25 years |
Aggregate agreement fixed charge | $ 942,500,000 |
Quarterly financial data (una64
Quarterly financial data (unaudited): (Details) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015USD ($) | Sep. 30, 2015USD ($) | Jun. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Sep. 30, 2014USD ($) | Jun. 30, 2014USD ($) | Mar. 31, 2014USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | |
Quarterly financial data (unaudited): | |||||||||||
Operating revenues | $ 297,642 | $ 368,664 | $ 343,741 | $ 339,778 | $ 315,475 | $ 369,405 | $ 355,983 | $ 367,300 | $ 1,349,825 | $ 1,408,163 | $ 1,245,376 |
Operating margin | 56,417 | 69,287 | 63,494 | 68,260 | 49,255 | 70,685 | 69,600 | 69,857 | 257,458 | 259,397 | 231,524 |
Net margin | $ 6,212 | $ 15,908 | $ 10,852 | $ 15,369 | $ (4,237) | $ 14,453 | $ 17,196 | $ 19,223 | $ 48,341 | $ 46,635 | $ 41,480 |
Margins for interest ratio | 1.14 | 1.14 | 1.14 | 1.14 | 1.14 |