Document and Entity Information
Document and Entity Information | 12 Months Ended |
Dec. 31, 2018 | |
Document and Entity Information Abstract | |
Entity Registrant Name | OGLETHORPE POWER CORP |
Entity Central Index Key | 0000788816 |
Document Type | S-4 |
Document Period End Date | Dec. 31, 2018 |
Amendment Flag | false |
Entity Filer Category | Non-accelerated Filer |
CONSOLIDATED STATEMENTS OF REVE
CONSOLIDATED STATEMENTS OF REVENUES AND EXPENSES - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Operating revenues: | |||
Total operating revenues | $ 1,480,113 | $ 1,434,196 | $ 1,507,231 |
Operating expenses: | |||
Fuel | 502,904 | 473,184 | 513,258 |
Production | 417,391 | 401,374 | 434,306 |
Depreciation and amortization | 233,284 | 224,098 | 217,534 |
Purchased power | 63,468 | 59,996 | 54,108 |
Accretion | 38,090 | 36,674 | 32,361 |
Total operating expenses | 1,255,137 | 1,195,326 | 1,251,567 |
Operating margin | 224,976 | 238,870 | 255,664 |
Other income: | |||
Investment income | 60,055 | 56,122 | 51,656 |
Amortization of deferred gains | 1,788 | 1,788 | 1,788 |
Allowance for equity funds used during construction | 1,006 | 784 | 788 |
Other | 5,413 | 6,291 | 2,671 |
Total other income | 68,262 | 64,985 | 56,903 |
Interest charges: | |||
Interest expense | 381,242 | 374,345 | 366,892 |
Allowance for debt funds used during construction | (151,643) | (134,319) | (116,634) |
Amortization of debt discount and expense | 12,440 | 12,552 | 11,964 |
Net interest charges | 242,039 | 252,578 | 262,222 |
Net margin | 51,199 | 51,277 | 50,345 |
Members | |||
Operating revenues: | |||
Total operating revenues | 1,479,379 | 1,433,830 | 1,506,807 |
Non-Members | |||
Operating revenues: | |||
Total operating revenues | $ 734 | $ 366 | $ 424 |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE MARGIN - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
CONSOLIDATED STATEMENTS OF COMPREHENSIVE MARGIN | |||||||||||
Net margin | $ (4,820) | $ 11,334 | $ 17,285 | $ 27,400 | $ 2,592 | $ 11,555 | $ 15,676 | $ 21,454 | $ 51,199 | $ 51,277 | $ 50,345 |
Other comprehensive margin: | |||||||||||
Unrealized loss on available-for-sale securities | (428) | ||||||||||
Amounts reclassified to regulatory assets | 370 | ||||||||||
Total comprehensive margin | $ 51,199 | $ 51,647 | $ 49,917 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Electric plant: | ||
In service | $ 9,283,970 | $ 8,886,407 |
Less: Accumulated provision for depreciation | (4,544,405) | (4,302,332) |
Net in service | 4,739,565 | 4,584,075 |
Nuclear fuel, at amortized cost | 358,358 | 358,562 |
Construction work in progress | 3,866,042 | 2,935,868 |
Total electric plant | 8,963,965 | 7,878,505 |
Investments and funds: | ||
Nuclear decommissioning trust fund | 420,818 | 445,055 |
Investments in associated companies | 77,037 | 74,981 |
Long-term investments | 164,125 | 140,622 |
Restricted investments | 503,158 | 653,585 |
Other | 24,259 | 22,562 |
Total investments and funds | 1,189,397 | 1,336,805 |
Current assets: | ||
Cash and cash equivalents | 752,618 | 397,695 |
Restricted short-term investments | 150,000 | 229,324 |
Receivables | 153,647 | 156,781 |
Inventories, at average cost | 259,087 | 266,219 |
Prepayments and other current assets | 8,098 | 18,884 |
Total current assets | 1,323,450 | 1,068,903 |
Deferred charges and other assets: | ||
Regulatory assets | 655,063 | 585,084 |
Prepayments to Georgia Power Company | 29,459 | 45,575 |
Other | 21,934 | 13,267 |
Total deferred charges | 706,456 | 643,926 |
Total assets | 12,183,268 | 10,928,139 |
Capitalization: | ||
Patronage capital and membership fees | 962,286 | 911,087 |
Long-term debt | 8,727,148 | 7,927,562 |
Obligations under capital leases | 81,730 | 87,192 |
Other | 21,428 | 20,051 |
Total capitalization | 9,792,592 | 8,945,892 |
Current liabilities: | ||
Long-term debt and capital leases due within one year | 522,289 | 216,694 |
Short-term borrowings | 190,626 | |
Accounts payable | 206,577 | 212,868 |
Accrued interest | 60,971 | 79,510 |
Member power bill prepayments, current | 224,957 | 6,171 |
Other current liabilities | 49,465 | 55,136 |
Total current liabilities | 1,064,259 | 761,005 |
Deferred credits and other liabilities: | ||
Asset retirement obligations | 1,017,563 | 734,997 |
Member power bill prepayments, non-current | 54,750 | 203,615 |
Regulatory liabilities | 218,998 | 251,649 |
Other | 35,106 | 30,981 |
Total deferred credits and other liabilities | 1,326,417 | 1,221,242 |
Total equity and liabilities | 12,183,268 | 10,928,139 |
Commitments and Contingencies (Notes 1, 7, 10, 11 and 12) |
CONSOLIDATED STATEMENTS OF CAPI
CONSOLIDATED STATEMENTS OF CAPITALIZATION - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Secured Long-term debt: | ||
Total Secured Long-term, debt | $ 8,910,680 | $ 8,232,703 |
Unsecured debt: | ||
Total long-term debt | 9,347,307 | 8,232,703 |
Obligations under capital leases | 87,191 | 94,358 |
Obligation under Rocky Mountain transactions | 21,428 | 20,051 |
Patronage capital and membership fees | 962,286 | 911,087 |
Subtotal | 10,418,212 | 9,258,199 |
Less: long-term debt and capital leases due within one year | (522,289) | (216,694) |
Less: unamortized debt issuance costs | (92,377) | (87,802) |
Less: unamortized bond discounts on long-term debt | (10,954) | (7,811) |
Total capitalization | 9,792,592 | 8,945,892 |
Commercial paper | ||
Unsecured debt: | ||
Unsecured debt | 436,627 | |
Federal Financing Bank (FFB) | First mortgage notes payable to the Federal Financing Bank at interest rates varying from 1.84% to 8.43% (average rate of 3.85% at December 31, 2018) due in quarterly installments through 2046 | ||
Secured Long-term debt: | ||
Debt Instrument Principal Outstanding | 2,577,699 | 2,456,864 |
Federal Financing Bank (FFB) | First mortgage notes payable to the Federal Financing Bank at interest rates varying from 2.51% to 3.87% (average rate of 3.37% at December 31, 2018) due in quarterly installments through 2044 | ||
Secured Long-term debt: | ||
Debt Instrument Principal Outstanding | 1,794,723 | 1,735,586 |
National Rural Utilities Cooperative Finance Corporation | First mortgage notes payable to National Rural Utilities Cooperative Finance Corporation at interest rates varying from 4.75% to 4.90% (average rate of 4.79% at December 31, 2018) due in quarterly installments through 2020 | ||
Secured Long-term debt: | ||
Debt Instrument Principal Outstanding | 1,426 | 2,411 |
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 | 6,062 | 7,072 |
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 |
Public | First mortgage bonds payable: Series 2016A First Mortgage Bonds, 4.25% due 2046 | ||
Secured Long-term debt: | ||
Debt Instrument Principal Outstanding | 250,000 | 250,000 |
Public | First Mortgage Bonds Payable: Series 2018A First Mortgage Bonds, 5.05% Due 2048 | ||
Secured Long-term debt: | ||
Debt Instrument Principal Outstanding | 500,000 | |
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: 2009A Heard and Monroe, and 2009B Monroe, Weekly rate bonds, 1.80%, due 2030 through 2038 | ||
Secured Long-term debt: | ||
Debt Instrument Principal Outstanding | 112,055 | 112,055 |
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: 2010A Burke and Monroe, and 2010B Burke, Weekly rate bonds, 1.71% to 1.82%, due 2036 through 2037 | ||
Secured Long-term debt: | ||
Debt Instrument Principal Outstanding | 133,550 | 133,550 |
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: 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 |
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2017 A Burke, Heard, Monroe and 2017B Burke, Indexed put bonds - weekly reset, 2.81% due 2040 through 2045 | ||
Secured Long-term debt: | ||
Debt Instrument Principal Outstanding | 122,620 | 122,620 |
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2017 C, D Burke, Remarketed in 2018 to fixed rate bonds, 4.125% through February 1,2028, due 2041 through 2045 | ||
Secured Long-term debt: | ||
Debt Instrument Principal Outstanding | 200,000 | 200,000 |
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2017E Burke, Remarketed in 2018 to term rate bonds, 3.25% through February 3,2025, due 2041 through 2045 | ||
Secured Long-term debt: | ||
Debt Instrument Principal Outstanding | 100,000 | 100,000 |
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2017 F Burke, Remarketed in 2018 to term rate bonds, 3.00% through February 1,2023, due 2041 through 2045 | ||
Secured Long-term debt: | ||
Debt Instrument Principal Outstanding | $ 99,785 | $ 99,785 |
CONSOLIDATED STATEMENTS OF CA_2
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Parenthetical) | Dec. 31, 2018 |
Federal Financing Bank (FFB) | First mortgage notes payable to the Federal Financing Bank at interest rates varying from 1.84% to 8.43% (average rate of 3.85% at December 31, 2018) due in quarterly installments through 2046 | |
Secured Long-term debt: | |
Interest rate, average rate (as a percent) | 3.85% |
Federal Financing Bank (FFB) | First mortgage notes payable to the Federal Financing Bank at interest rates varying from 1.84% to 8.43% (average rate of 3.85% at December 31, 2018) due in quarterly installments through 2046 | Minimum | |
Secured Long-term debt: | |
Interest rate (as a percent) | 1.84% |
Federal Financing Bank (FFB) | First mortgage notes payable to the Federal Financing Bank at interest rates varying from 1.84% to 8.43% (average rate of 3.85% at December 31, 2018) due in quarterly installments through 2046 | Maximum | |
Secured Long-term debt: | |
Interest rate (as a percent) | 8.43% |
Federal Financing Bank (FFB) | First mortgage notes payable to the Federal Financing Bank at interest rates varying from 2.51% to 3.87% (average rate of 3.37% at December 31, 2018) due in quarterly installments through 2044 | |
Secured Long-term debt: | |
Interest rate, average rate (as a percent) | 3.37% |
Federal Financing Bank (FFB) | First mortgage notes payable to the Federal Financing Bank at interest rates varying from 2.51% to 3.87% (average rate of 3.37% at December 31, 2018) due in quarterly installments through 2044 | Minimum | |
Secured Long-term debt: | |
Interest rate (as a percent) | 2.51% |
Federal Financing Bank (FFB) | First mortgage notes payable to the Federal Financing Bank at interest rates varying from 2.51% to 3.87% (average rate of 3.37% at December 31, 2018) due in quarterly installments through 2044 | Maximum | |
Secured Long-term debt: | |
Interest rate (as a percent) | 3.87% |
National Rural Utilities Cooperative Finance Corporation | First mortgage notes payable to National Rural Utilities Cooperative Finance Corporation at interest rates varying from 4.75% to 4.90% (average rate of 4.79% at December 31, 2018) due in quarterly installments through 2020 | |
Secured Long-term debt: | |
Interest rate, average rate (as a percent) | 4.79% |
National Rural Utilities Cooperative Finance Corporation | First mortgage notes payable to National Rural Utilities Cooperative Finance Corporation at interest rates varying from 4.75% to 4.90% (average rate of 4.79% at December 31, 2018) due in quarterly installments through 2020 | Minimum | |
Secured Long-term debt: | |
Interest rate (as a percent) | 4.75% |
National Rural Utilities Cooperative Finance Corporation | First mortgage notes payable to National Rural Utilities Cooperative Finance Corporation at interest rates varying from 4.75% to 4.90% (average rate of 4.79% at December 31, 2018) due in quarterly installments through 2020 | Maximum | |
Secured Long-term debt: | |
Interest rate (as a percent) | 4.90% |
Public | First mortgage bonds payable: Series 2006 First Mortgage Bonds, 5.534%, due 2031 through 2035 | |
Secured Long-term debt: | |
Interest rate (as a percent) | 5.534% |
Public | First mortgage bonds payable: Series 2007 First Mortgage Bonds, 6.191%, due 2024 through 2031 | |
Secured Long-term debt: | |
Interest rate (as a percent) | 6.191% |
Public | First mortgage bonds payable: Series 2009A First Mortgage Bonds, 6.10%, due 2019 | |
Secured Long-term debt: | |
Interest rate (as a percent) | 6.10% |
Public | First mortgage bonds payable: Series 2009B First Mortgage Bonds, 5.95%, due 2039 | |
Secured Long-term debt: | |
Interest rate (as a percent) | 5.95% |
Public | First mortgage bonds payable: Series 2009 Clean renewable energy bond, 1.81%, due 2024 | |
Secured Long-term debt: | |
Interest rate (as a percent) | 1.81% |
Public | First mortgage bonds payable: Series 2010A First Mortgage Bonds, 5.375% due 2040 | |
Secured Long-term debt: | |
Interest rate (as a percent) | 5.375% |
Public | First mortgage bonds payable: Series 2011A First Mortgage Bonds, 5.25% due 2050 | |
Secured Long-term debt: | |
Interest rate (as a percent) | 5.25% |
Public | First mortgage bonds payable: Series 2012A First Mortgage Bonds, 4.20% due 2042 | |
Secured Long-term debt: | |
Interest rate (as a percent) | 4.20% |
Public | First mortgage bonds payable: Series 2014A First Mortgage Bonds, 4.55% due 2044 | |
Secured Long-term debt: | |
Interest rate (as a percent) | 4.55% |
Public | First mortgage bonds payable: Series 2016A First Mortgage Bonds, 4.25% due 2046 | |
Secured Long-term debt: | |
Interest rate (as a percent) | 4.25% |
Public | First Mortgage Bonds Payable: Series 2018A First Mortgage Bonds, 5.05% Due 2048 | |
Secured Long-term debt: | |
Interest rate (as a percent) | 5.05% |
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: 2009A Heard and Monroe, and 2009B Monroe, Weekly rate bonds, 1.80%, due 2030 through 2038 | |
Secured Long-term debt: | |
Interest rate (as a percent) | 1.80% |
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: 2010A Burke and Monroe, and 2010B Burke, Weekly rate bonds, 1.71% to 1.82%, due 2036 through 2037 | Minimum | |
Secured Long-term debt: | |
Interest rate (as a percent) | 1.71% |
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: 2010A Burke and Monroe, and 2010B Burke, Weekly rate bonds, 1.71% to 1.82%, due 2036 through 2037 | Maximum | |
Secured Long-term debt: | |
Interest rate (as a percent) | 1.82% |
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: 2013A Appling, Burke and Monroe, Term rate bonds, 2.40% through April 1, 2020, due 2038 through 2040 | |
Secured Long-term debt: | |
Interest rate (as a percent) | 2.40% |
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2017 A Burke, Heard, Monroe and 2017B Burke, Indexed put bonds - weekly reset, 2.81% due 2040 through 2045 | |
Secured Long-term debt: | |
Interest rate (as a percent) | 2.81% |
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2017 C, D Burke, Remarketed in 2018 to fixed rate bonds, 4.125% through February 1,2028, due 2041 through 2045 | |
Secured Long-term debt: | |
Interest rate (as a percent) | 4.125% |
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2017E Burke, Remarketed in 2018 to term rate bonds, 3.25% through February 3,2025, due 2041 through 2045 | |
Secured Long-term debt: | |
Interest rate (as a percent) | 3.25% |
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2017 F Burke, Remarketed in 2018 to term rate bonds, 3.00% through February 1,2023, due 2041 through 2045 | |
Secured Long-term debt: | |
Interest rate (as a percent) | 3.00% |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Cash flows from operating activities: | |||
Net margin | $ 51,199 | $ 51,277 | $ 50,345 |
Adjustments to reconcile net margin to net cash provided by operating activities: | |||
Depreciation and amortization, including nuclear fuel | 371,234 | 374,411 | 362,716 |
Accretion cost | 38,090 | 36,674 | 32,361 |
Amortization of deferred gains | (1,788) | (1,788) | (1,788) |
Allowance for equity funds used during construction | (1,006) | (784) | (788) |
Deferred outage costs | (31,863) | (40,644) | (40,599) |
Loss (gain) on sale of investments | 4,871 | (18,614) | 96 |
Regulatory deferral of costs associated with nuclear decommissioning | (26,511) | (2,605) | (20,440) |
Other | (5,676) | (9,240) | (7,286) |
Change in operating assets and liabilities: | |||
Receivables | 8,424 | (1,182) | (24,578) |
Inventories | 5,487 | (6,388) | 23,947 |
Prepayments and other current assets | 4,544 | 614 | (2,172) |
Accounts payable | 1,360 | 129,187 | (76,495) |
Accrued interest | (18,539) | (14,124) | 34,804 |
Accrued and withheld taxes | (21,351) | (1,531) | 1,102 |
Other current liabilities | 25,723 | (8,646) | (11,937) |
Member power bill prepayments | 69,921 | (15,317) | 6,155 |
Other | 15,578 | ||
Total adjustments | 438,498 | 420,023 | 275,098 |
Net cash provided by operating activities | 489,697 | 471,300 | 325,443 |
Cash flows from investing activities: | |||
Property additions | (1,185,367) | (1,019,695) | (613,019) |
Guarantee settlement proceeds | 0 | 1,104,000 | |
Activity in nuclear decommissioning trust fund - Purchases | (457,909) | (450,113) | (395,506) |
Activity in nuclear decommissioning trust fund - Proceeds | 449,895 | 442,989 | 389,011 |
Decrease (increase) in restricted investments | 229,751 | (414,781) | (80,234) |
Activity in other long-term investments - Purchases | (207,670) | (108,704) | (61,200) |
Activity in other long-term investments - Proceeds | 176,717 | 78,356 | 50,529 |
Other | 9,144 | (43,056) | 13,554 |
Net cash used in investing activities | (985,439) | (411,004) | (696,865) |
Cash flows from financing activities: | |||
Long-term debt proceeds | 813,028 | 544,503 | 790,385 |
Long-term debt payments | (201,354) | (677,641) | (114,702) |
Increase (decrease) in short-term borrowings, net | 246,001 | 88,458 | (159,310) |
Other | (7,010) | 15,789 | 8,301 |
Net cash provided by (used in) financing activities | 850,665 | (28,891) | 524,674 |
Net increase in cash and cash equivalents | 354,923 | 31,405 | 153,252 |
Cash and cash equivalents at beginning of period | 397,695 | 366,290 | 213,038 |
Cash and cash equivalents at end of period | 752,618 | 397,695 | 366,290 |
Cash paid for - | |||
Interest (net of amounts capitalized) | 245,085 | 251,186 | 212,574 |
Supplemental disclosure of non-cash investing and financing activities: | |||
Change in asset retirement obligations | 248,608 | 2,414 | 63,011 |
Accrued property additions at end of period | 121,557 | 134,082 | 26,870 |
Interest paid-in-kind | $ 59,137 | $ 57,144 | $ 47,814 |
CONSOLIDATED STATEMENTS OF PATR
CONSOLIDATED STATEMENTS OF PATRONAGE CAPITAL AND MEMBERSHIP FEES AND ACCUMULATED OTHER COMPREHENSIVE (DEFICIT) MARGIN - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||
Dec. 31, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Increase (Decrease) in Members' Capital | |||||||
Balance | $ 911,087 | $ 859,440 | $ 911,087 | $ 859,440 | $ 809,523 | ||
Components of comprehensive margin: | |||||||
Net margin | $ (4,820) | 27,400 | $ 2,592 | 21,454 | 51,199 | 51,277 | 50,345 |
Unrealized loss on available-for-sale securities | (428) | ||||||
Amounts reclassified to regulatory assets | 370 | ||||||
Total comprehensive margin | 51,199 | 51,647 | 49,917 | ||||
Balance | 962,286 | 911,087 | 962,286 | 911,087 | 859,440 | ||
Patronage Capital and Membership Fees | |||||||
Increase (Decrease) in Members' Capital | |||||||
Balance | $ 911,087 | 859,810 | 911,087 | 859,810 | 809,465 | ||
Components of comprehensive margin: | |||||||
Net margin | 51,199 | 51,277 | 50,345 | ||||
Balance | $ 962,286 | $ 911,087 | $ 962,286 | 911,087 | 859,810 | ||
Accumulated Other Comprehensive (Deficit) Margin | |||||||
Increase (Decrease) in Members' Capital | |||||||
Balance | $ (370) | (370) | 58 | ||||
Components of comprehensive margin: | |||||||
Unrealized loss on available-for-sale securities | (428) | ||||||
Amounts reclassified to regulatory assets | $ 370 | ||||||
Balance | $ (370) |
Summary of significant accounti
Summary of significant accounting policies: | 12 Months Ended |
Dec. 31, 2018 | |
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 7,060 megawatts of summer planning reserve capacity. We also manage and operate Smarr EMC which owns 731 megawatts of summer planning reserve capacity. In addition, we supply financial and management services to Green Power EMC, which purchases energy from renewable energy facilities totaling 120 megawatts of capacity, including 87 megawatts sourced by solar energy. 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 4.1 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, 2018 and 2017 and the reported amounts of revenues and expenses for each of the three years in the period ended December 31, 2018. Actual results could differ from those estimates. 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. 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 2018, 2017 and 2016, we achieved a margins for interest ratio of 1.14. e. Revenue recognition As an electric membership cooperative, our principle business is providing wholesale electric service to our members. Our operating revenues are derived primarily from wholesale power contracts we have with each of our 38 members. These contracts, which extend to December 31, 2050, are substantially identical and obligate our members jointly and severally to pay all expenses associated with owning and operating our power supply business. As a cooperative, we operate on a not-for-profit basis and, accordingly, seek only to generate revenues sufficient to recover our cost of service and to generate margins sufficient to establish reasonable reserves and meet certain financial coverage requirements. While not significant, we also have short-term energy sales to non-members made through industry standard contracts. We do not have multiple operating segments. Pursuant to our contracts, we primarily provide two services, capacity and energy. Capacity and energy revenues are recognized by us upon transfer of control of promised services to our members and non-members in an amount that reflects the consideration we expect to receive in exchange for those services. Capacity and energy are distinct and we account for them as separate performance obligations. The obligations to provide capacity and energy are satisfied over time as the customer simultaneously receives and consumes the benefit of these services. Both performance obligations are provided directly by us and not through a third party. Each of our members is obligated under their wholesale power contract to pay us for capacity and energy we furnish under their wholesale power contract in accordance with rates we establish. We review our rates periodically but are required to do so at least once every year. Revenues from our members are derived through a cost-plus rate structure which is set forth as a formula in the rate schedule to the wholesale power contracts between us and each of our members. The formulary rate provides for the pass-through of our (i) fixed costs (net of any income from other sources) plus a targeted margin as capacity revenues and (ii) variable costs as energy revenues from our members. Power purchase and sale agreements between us and non-members obligate each non-member to pay us for capacity, if any, and energy furnished in accordance with the prices mutually agreed upon. Margins produced from non-member sales are included in our rate schedule formula and reduce revenue requirements from our members. The standard selling price at which we provide capacity services to our members is determined by our formulary rate on an annual basis. As a result, the consideration we receive for providing capacity services is determined annually. Over the course of a year, our member capacity revenues are relatively stable. Capacity revenues may fluctuate year to year largely due to the recovery of fixed operation and maintenance costs. The components of the formulary rate associated with capacity costs include the annual budget of fixed costs, a targeted margin and income from other sources. Capacity revenues, therefore, vary to the extent these components vary. Fixed costs include items such as fixed operation and maintenance expenses, administrative and general expenses, depreciation and interest. Year to year, capacity revenue fluctuations are generally due to the recovery of fixed operation and maintenance costs. Fixed costs also include certain costs, such as major maintenance costs, which will be recognized as expense in future periods. Recognition of revenues associated with these future expenses is deferred pursuant to Accounting Standards Codification (ASC) 980, Regulated Operations. The regulatory liabilities are amortized to revenue in accordance with the associated revenue deferral plan. For information regarding regulatory accounting, see Note 1q. Capacity revenues are recognized by us for standing ready to deliver electricity to our customers. Our capacity revenues are based on the associated costs we expect to recover in a given year and are recognized and billed to our members in equal monthly installments over the course of the year regardless of whether our generation and purchased power resources are dispatched to produce electricity. Non-member capacity revenues, if any, are typically billed and recognized in equal monthly installments over the term of the contract. We have a power bill prepayment program pursuant to which our members may prepay future capacity costs and receive a discount. As this program provides us with significant financing, we adjust our capacity revenues by the amount of the discount, which is based on our avoided cost of borrowing. For additional information regarding our member prepayment program, see Note 1p. We satisfy our performance obligations to deliver energy as energy is delivered to the applicable meter points. We determine the standard selling price for energy we deliver to our members based upon the variable costs incurred to generate or purchase that energy. Fuel expense is the primary variable cost. Energy revenue recognized equals the actual variable expenses incurred in any given accounting period. Our member energy revenues fluctuate from period to period based on several factors, including fuel costs, weather and other seasonal factors, load requirements in our members’ service territories, variable operating costs, the availability of electric generation resources, our decisions of whether to dispatch our owned or purchased resources or member-owned resources over which we have dispatch rights, and by members’ decisions of whether to purchase a portion of their hourly energy requirements from our resources or from other suppliers. We do not provide all of our members’ energy requirements. The standard selling price for our energy revenues from non-members is the price mutually agreed upon. We are required under our first mortgage indenture to produce a margins for interest ratio of at least 1.10 for each fiscal year. For 2018 and 2017, our board approved a targeted margins for interest ratio of 1.14 and for years 2018 and 2017, we achieved a margins for interest ratio of 1.14. Historically, our board of directors has approved adjustments to revenue requirements by year end such that revenue in excess of that required to meet the targeted margins for interest ratio is refunded to the members. Given that our capacity revenues are based upon budgeted expenditures and generally recognized and billed to our members in equal monthly installments over the course of the year, we may recognize capacity revenues that exceed our actual fixed costs and targeted margins in any given interim reporting period. At each interim reporting period we assess our projected revenue requirements through year end to determine if a refund to our members of excess consideration is likely. If required, we reduce our capacity revenues and recognize a refund liability to our members. Refund liabilities, if any, are included in accounts payable on our consolidated balance sheets. At December 31, 2018 and 2017, we recognized refund liabilities totaling $30,870,000 and $29,149,000, respectively that were applied to our members’ bills in January 2019. Based on our current agreements with non-members, we do not refund any consideration received from non-members. Sales to members were as follows: (dollars in thousands) 2018 2017 2016 Capacity revenues $ 927,419 $ 912,421 $ 949,193 Energy revenues 551,960 521,409 557,614 Total $ 1,479,379 $ 1,433,830 $ 1,506,807 The following table reflects members whose revenues accounted for 10% or more of our total operating revenues in 2018, 2017 or 2016: 2018 2017 2016 Jackson EMC 14.1 % 14.7 % 14.3 % Cobb EMC 13.9 % 14.3 % 13.7 % Sawnee EMC n/a n/a 10.5 % Sales to non-members during years 2018, 2017 and 2016 were insignificant. Electric capacity and energy revenues are recognized by us without any obligation for returns, warranties or taxes collected. As our members are jointly and severally obligated to pay all expenses associated with owning and operating our power supply business and we perform an on-going assessment of the credit worthiness of non-members, we have not recorded an allowance for doubtful accounts associated with our receivables from members or non-members. We have a rate management program that allows us to expense and recover interest costs on a current basis that would otherwise be deferred or capitalized. The subscribing members of Vogtle Units No. 3 and No. 4 can elect to participate in this program on an annual basis. The Vogtle program allows for the recovery of financing costs associated with the construction of Vogtle Units No. 3 and No. 4 on a current basis. Under this program, amounts billed to participating members in 2018, 2017 and 2016 were $12,229,000, $11,000,000 and $16,096,000, respectively. The cumulative amount billed since inception of the program totaled $66,316,000. In 2018, we began an additional rate management program that allows us to recover future expense on a current basis. Our members made a one-time election to participate in this program, which in general, allows for additional collections over a five-year period with those amounts then applied to billings over the subsequent five-year period. The program is designed primarily as a mechanism to assist our members to manage the rate impacts associated with the commercial operation of the new Vogtle units. Participating members were billed $15,435,000 under this program in 2018. In conjunction with this program, we are applying regulated operations accounting to defer these revenues and related investment income. Amounts deferred under the program will be amortized to income when applied to members’ bills. f. Receivables A substantial portion of our receivables are related to capacity and energy 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, plus a margin requirement. Receivables from contracts with our members at December 31, 2018, 2017 and 2016 were $122,888,000, $126,211,000 and $136,552,000, respectively. Payment is received the following month in which capacity and energy are billed. Estimated energy charges are billed based on the amount of energy supplied during the month and are adjusted when actual costs are available, generally the following month. The remainder of our receivables is primarily related to transactions with affiliated companies and investment income. Uncollectible amounts, if any, are identified on a specific basis and charged to expense in the period the amounts are determined to be uncollectible. During 2018 and 2017, no impairment losses were recognized on any receivables that arose from contracts with members or non-members. g. Nuclear fuel cost The cost of nuclear fuel is amortized to fuel expense based on usage. The total nuclear fuel expense for 2018, 2017 and 2016 amounted to $85,949,000, $90,520,000, and $83,751,000, respectively. Contracts with the U.S. Department of Energy have been executed to provide for the permanent disposal of spent nuclear fuel produced at Plants 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. In 2014, the U.S. Court of Federal Claims issued a judgment in favor of Georgia Power, to recover spent nuclear fuel storage costs at Plants Hatch and Vogtle Units No. 1 and No. 2 covering the period of 2005 through 2010. Our ownership share of $10,949,000, was recognized in our 2015 financial statements. Georgia Power filed additional claims in 2014 (as amended) and 2017 seeking damages for spent nuclear fuel storage costs at Plant Hatch and Plant Vogtle Units No. 1 and No. 2 covering the periods from January 1, 2011 through December 31, 2014 and January 1, 2015 through December 31, 2017, respectively. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts were recognized in the financial statements as of December 31, 2018 for these additional claims. 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. h. 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 2018. The following table reflects the details of the asset retirement obligations included in the consolidated balance sheets for the years 2018 and 2017. (dollars in thousands) Nuclear Coal Ash Other Total Balance at December 31, 2017 $ 548,574 $ 161,755 $ 24,668 $ 734,997 Liabilities settled (1,686) (1,596) (1,398) (4,680) Accretion 32,857 4,238 995 38,090 Change in cash flow estimates 79,211 161,851 8,094 249,156 Balance at December 31, 2018 $ 658,956 $ 326,248 $ 32,359 $ 1,017,563 (dollars in thousands) Nuclear Coal Ash Other Total Balance at December 31, 2016 $ 517,565 $ 156,465 $ 24,021 $ 698,051 Liabilities settled (17) (943) (1,185) (2,145) Accretion 31,026 4,629 1,019 36,674 Change in cash flow estimates — 1,604 813 2,417 Balance at December 31, 2017 $ 548,574 $ 161,755 $ 24,668 $ 734,997 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, but not limited to, changes in the assumed date of decommissioning, changes in regulatory requirements, changes in technology, and changes in costs of labor, materials and equipment. Our most recent assessment of the nuclear asset obligation resulted in a $79,211,000 increase in the obligation for nuclear decommissioning. In projecting future costs, the escalation rate for labor, materials and equipment was assumed to be 2.8% for the Hatch units and 2.7% for Vogtle Units 1 & 2. The increase in the cash flow estimates in 2018 was primarily attributable to general inflation, labor costs, volume of low-level radioactive waste and spent fuel management, among other factors. Our portion of the estimated costs of decommissioning co-owned nuclear facilities were as follows: (dollars in thousands) Hatch Unit Hatch Unit Vogtle Unit Vogtle Unit 2018 site study No. 1 No. 2 No. 1 No. 2 Expected start date of decommissioning 2034 2038 2047 2049 Estimated costs based on site study in 2018 dollars: Radiated structures $ 209,000 $ 231,000 $ 188,000 $ 206,000 Spent fuel management 54,000 49,000 55,000 51,000 Non-radiated structures 14,000 19,000 23,000 29,000 Total estimated site study costs $ 277,000 $ 299,000 $ 266,000 $ 286,000 We have established funds to comply with the Nuclear Regulatory Commission regulations regarding the decommissioning of our nuclear plants. See Note 1i for information regarding the nuclear decommissioning funds. We apply the provision of regulated operations to nuclear decommissioning transactions such that collections and investment income (interest, dividends and realized gains and losses) of our nuclear decommissioning funds are compared to the associated decommissioning expenses with the difference deferred as regulatory asset or liability. As this difference is largely attributable to the timing of decommissioning fund earnings, the difference is recorded as an adjustment to investment income in our consolidated statements of revenues and expenses. Unrealized gains and losses of the decommissioning funds are recorded directly to the regulatory asset or liability for asset retirement obligations in accordance with our ratemaking treatment. Coal Ash. 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. Our most recent assessment of the coal ash asset retirement obligation resulted in a $161,303,000 increase in the obligation 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 2018 increase in cash flow estimates was primarily attributed to the refinement of site specific closure strategies and the associated costs, including water treatment requirements, and the estimated amount of coal ash to be consolidated. Additional adjustments to the asset retirement obligations are expected periodically due to potential changes in estimates and assumptions. We have internally segregated the funds collected for coal ash pond and landfill decommissioning costs, including earnings thereon. As of December 31, 2018 and December 31, 2017 the fund balances were $60,599,000 and $41,844,000, respectively We apply the provision of regulated operations to coal ash pond and landfill decommissioning transactions such that collections and investment income (interest, dividends and realized gains and losses, if any) are compared to the associated decommissioning expenses with the difference deferred as a regulatory asset. As this difference is attributable to the associated expenses being greater than amounts collected through rates, this difference is recorded as a deferral of expense in our consolidated statements of revenues and expenses. Unrealized gains and losses, if any, of the associated decommissioning fund are recorded directly to the regulatory asset in accordance with our ratemaking treatment. Other. 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 1q. i. 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 2018 and 2017, 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. We record the investment securities held in the nuclear decommissioning trust fund 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. The funds are included in long-term investments on our consolidated balance sheet. In both 2018 and 2017, we contributed $4,750,000 into the internal funds. The following table outlines the fair value of our nuclear decommissioning funds as of December 31, 2018 and December 31, 2017. The funds are invested in a diversified mix of approximately 60% equity and 40% fixed income securities for both 2018 and 2017. 2018 External Trust Funds: Cost Net Unrealized Fair Value 12/31/2017 Purchases Proceeds (1) Gain(Loss) 12/31/2018 Equity $ 203,622 $ 12,186 $ (7,789) $ 49,475 $ 257,494 Debt 164,901 445,353 (443,712) (2,108) 164,434 Other 141 370 (1,621) — (1,110) $ 368,664 $ 457,909 $ (453,122) $ 47,367 $ 420,818 (1) Also included in net proceeds are net realized gains or losses, interest income, dividends, contributions and fees of $4,786,000. 2018 Internal Funds: Cost Net Unrealized Fair Value 12/31/2017 Purchases Proceeds (1) Gain(Loss) 12/31/2018 Equity $ 43,698 $ — $ 596 $ 6,373 $ 50,667 Debt 33,540 161,454 (156,611) (246) 38,137 $ 77,238 $ 161,454 $ (156,015) $ 6,127 $ 88,804 (1) Also included in net proceeds are net realized gains or losses, interest income, dividends, contributions and fees of $689,000. 2017 External Trust Funds: Cost Net Unrealized Fair Value 12/31/2016 Purchases Proceeds (1) Gain(Loss) 12/31/2017 Equity $ 200,595 $ 61,406 $ (44,607) $ 76,221 $ 293,615 Debt 148,011 388,609 (384,199) 170 152,591 Other 351 98 (1,600) — (1,151) $ 348,957 $ 450,113 $ (430,406) $ 76,391 $ 445,055 (1) Also included in net proceeds are net realized gains or losses, interest income, dividends, contributions and fees of $19,707,000. 2017 Internal Funds: Cost Net Unrealized Fair Value 12/31/2016 Purchases Proceeds (1) Gain(Loss) 12/31/2017 Equity $ 38,798 $ — $ 4,900 $ 11,669 $ 55,367 Debt 26,207 73,153 (65,820) — 33,540 $ 65,005 $ 73,153 $ (60,920) $ 11,669 $ 88,907 (1) Also included in net proceeds are net realized gains or losses, interest income, dividends, contributions and fees of $12,232,800. Realized and unrealized gains and losses of the nuclear decommissioning funds that would be recorded in earnings 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. The nuclear decommissioning trust fund has produced an average annualized return of approximately 7.7% in the last ten years and 5.8% since inception in 1990. 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 above assumption, our management believes that increases in cost estimates of decommissioning can be recovered in future rates. j. 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 depreciation rate studies completed in 2015. Site specific depreciation studies are performed every five years. Annual weighted average depreciation rates in effect in 2018, 2017 and 2016 were as follows: Range of Useful Life in years* 2018 2017 2016 Steam production 49-65 2.57 % 2.91 % % Nuclear production 37-60 1.92 % 1.96 % % Hydro production 50 2.00 % % % Other production 30-35 2.61 % 2.58 % % Transmission 36 2.75 % 2.75 % % General 3-50 2.00-33.33 % 2.00-33.33 % 2.00-33.33 % * Depreciation expense for the years 2018, 2017 and 2016 was $227,213,000, $218,027,000, and $211,282,000, respectively. k. Electric plant Electric plant is stated at original cost, which is the cost of the plant when first dedicated to public service, including acquisition adjustments, if any, 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 2018, 2017 and 2016, the allowance for funds used during construction rates were 4.25%, 4.45% and 4.61%, 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 is charged to the accumulated provision for depreciation. Cost of removal, less salvage, is charged to a regulatory liability, accumulated retirement costs for other assets. 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. l. 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. m. Restricted investments Restricted investments consist of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account. We can only utilize these investments for future Rural Utilities Service-guaranteed Federal Financing Bank debt service payments. The funds currently earn interest at a rate of 5% per annum. As of October 1, 2020, deposits will earn interest at 4% per annum and beginning October 1, 2021, the rates will be set at the 1-year floating treasury rate. The program no longer allows additional funds to be deposited into the account. At December 31, 2018 and 2017, we had restricted investments totaling $653,158,000 and $882,909,000, respectively, of which $503,158,000 and $653,585,000, respectively, were classified as long-term. The funds on deposit with the Rural Utilities Service in the Cushion of Credit Account are held by the U.S. Treasury, acting through the Federal Financing Bank. n. 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. 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. 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 December 31, 2018 and December 31, 2017, fossil fuels inventories were $48,709,000 and $54,050,000, respectively. Inventories for spare parts at 2018 and 2017 were $210,379,000 and $212,169,000, respectively. o. Deferred charges and other assets Other deferred charges primarily represent advance deposits to Georgia Power Company related to the Vogtle construction project and progress payments for equipment associated with future nuclear refueling outages. For a discussion regarding regulatory assets, see Note 1q. p. Deferred credits and other liabilities We have a power bill prepayment program pursuant to whi |
Fair Value_
Fair Value: | 12 Months Ended |
Dec. 31, 2018 | |
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. Fair Value Measurements at Reporting Date Using Quoted Prices in Significant Other Significant Active Markets for Observable Unobservable Identical Assets Inputs Inputs December 31, 2018 (Level 1) (Level 2) (Level 3) (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ 136,196 $ 136,196 $ — $ — International equity trust $ 76,852 — 76,852 — Corporate bonds and debt $ 51,356 — 48,853 2,503 US Treasury securities $ 47,712 47,712 — — Mortgage backed securities $ 56,004 — 56,004 — Domestic mutual funds $ 43,359 43,359 — Municipal bonds $ 278 — 278 — Federal agency securities $ 6,066 — 6,066 — Other $ 2,995 2,031 964 — Long-term investments: International equity trust $ 17,382 — 17,382 — Corporate bonds and debt $ 12,571 — 11,366 1,205 US Treasury securities $ 12,062 12,062 — — Mortgage backed securities $ 11,517 — 11,517 — Domestic mutual funds $ 94,494 94,494 — — Federal agency securities $ 941 — 941 — Treasury STRIPS $ 14,113 — 14,113 — Other $ 1,045 1,045 — — Natural gas swaps $ 13,154 — 13,154 — Fair Value Measurements at Reporting Date Using Quoted Prices in Significant Other Significant Active Markets for Observable Unobservable Identical Assets Inputs Inputs December 31, 2017 (Level 1) (Level 2) (Level 3) (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ 142,419 $ 142,419 $ — $ — International equity trust $ 88,820 — 88,820 — Corporate bonds and debt $ 66,317 — 66,317 — US Treasury securities $ 38,791 38,791 — — Mortgage backed securities $ 49,379 — 49,379 — Domestic mutual funds $ 47,833 47,833 — — Municipal bonds $ 92 — 92 — Federal agency securities $ 3,725 — 3,725 — Other $ 7,679 7,679 — — Long-term investments: International equity trust $ 20,071 — 20,071 — Corporate bonds and debt $ 16,215 — 16,215 — US Treasury securities $ 6,670 6,670 — — Mortgage backed securities $ 7,267 — 7,267 — Domestic mutual funds $ 87,011 87,011 — — Federal agency securities $ 259 — 259 — Other $ 3,129 3,129 — — Natural gas swaps $ 6,328 — 6,328 — The Level 2 investments above in corporate bonds and debt, federal agency mortgage backed securities, and mortgage backed securities may not be exchange traded. The fair value measurements for these investments are based on a market approach, including the use of observable inputs. Common inputs include reported trades and broker/dealer bid/ask prices. The fair value of the Level 2 investments above in international equity trust are calculated based on the net asset value per share of the fund. There are no unfunded commitments for the international equity trust and redemption may occur daily with a 3-day redemption notice period. The Level 3 investments above in corporate bonds and debt consist of investments in bank loans which are not exchange traded. Although these securities may be liquid and priced daily, their inputs are not observable. The following table presents the changes in Level 3 assets measured at fair value on a recurring basis at December 31, 2018. Year Ended December 31, 2018 (dollars in thousands) Balance at December 31, 2017 $ — Transfers to Level 3 4,997 Total gains or losses (realized/unrealized): Changes in net assets (1,289) Balance at December 31, 2018 $ 3,708 The estimated fair values of our long-term debt, including current maturities at December 31, 2018 and 2017 were as follows (in thousands): 2018 2017 Carrying Fair Carrying Fair Value Value Value Value Long-term debt $ 9,347,307 $ 9,837,254 $ 8,232,703 $ 9,155,942 The estimated fair value of long-term debt is classified as Level 2 and is based on observed or quoted market prices for the same or similar issues, or based on current rates offered to us for debt of similar maturities. The primary sources of our long-term debt consist of first mortgage bonds, pollution control revenue bonds and long-term debt issued by the Federal Financing Bank that is guaranteed by the Rural Utilities Service or the U.S. Department of Energy. We also have small amounts of long-term debt provided by National Rural Utilities Cooperative Finance Corporation (CFC). The valuations for the first mortgage bonds and the pollution control revenue bonds were obtained from a third party data reporting service, and are based on secondary market trading of our debt. Valuations for debt issued by the Federal Financing Bank are based on U.S. Treasury rates as of December 31, 2018 plus an applicable spread, which reflects our borrowing rate for new loans of this type from the Federal Financing Bank. The rates on the CFC debt are fixed and the valuation is based on rate quotes provided by CFC. For cash, cash equivalents, and receivables, the carrying amount approximates fair value because of the short-term maturity of those instruments. Restricted investments consist of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account and the carrying amount of these investments approximates fair value because of the liquid nature of the deposits with the U.S. Treasury. |
Derivative instruments_
Derivative instruments: | 12 Months Ended |
Dec. 31, 2018 | |
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. 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 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 could cause us to have credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations, we could suffer a financial loss. However, as of December 31, 2018 all of the counterparties with transaction amounts outstanding under our hedging programs are rated investment grade by the major rating agencies or have provided a guaranty from one of their affiliates that is rated investment grade. We have entered into International Swaps and Derivatives Association agreements with our natural gas hedge counterparties that mitigate credit exposure by creating contractual rights relating to creditworthiness, collateral, termination and netting (which, in certain cases, allows us to use the net value of affected transactions with the same counterparty in the event of default by the counterparty or early termination of the agreement). Additionally, we have implemented procedures to monitor the creditworthiness of our counterparties and to evaluate nonperformance in valuing counterparty positions. We have contracted with a third party to assist in monitoring certain of our counterparties’ credit standing and condition. Net liability positions are generally not adjusted as we use derivative transactions as hedges and have the ability and intent to perform under each of our contracts. In the instance of net asset positions, we consider general market conditions and the observable financial health and outlook of specific counterparties, forward looking data such as credit default swaps, when available, and historical default probabilities from credit rating agencies in evaluating the potential impact of nonperformance risk to derivative positions. The contractual agreements contain provisions that could require us or the counterparty to post collateral or credit support. The amount of collateral or credit support that could be required is calculated as the difference between the aggregate fair value of the hedges and pre-established credit thresholds. The credit thresholds are contingent upon each party’s credit ratings from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. 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, 2018 and 2017, the estimated fair value of our natural gas contracts was a net liability of $13,154,000 and $6,328,000, respectively. As of December 31, 2018 and 2017, 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, 2018 due to our credit rating being downgraded below investment grade, we would have been required to post letters of credit of approximately $13,154,000 with our counterparties. The following table reflects the volume activity of our natural gas derivatives as of December 31, 2018 that is expected to settle or mature each year: Natural Gas Swaps Year (MMBTUs) (in millions) 2019 23.4 2020 22.1 2021 19.6 2022 12.6 2023 9.5 Total 87.2 The table below reflects the fair value of derivative instruments and their effect on our consolidated balance sheets at December 31, 2018 and 2017. Balance Sheet Location Fair Value 2018 2017 (dollars in thousands) Assets Natural gas swaps Other current assets $ 226 412 Liabilities Natural gas swaps Other current liabilities $ 2,066 $ 1,575 Natural gas swaps Other deferred credits $ 11,314 $ 5,165 The following table presents the realized gains and (losses) on derivative instruments recognized in margin for the years ended December 31, 2018, 2017 and 2016. Consolidated Statement of Revenues and Expenses Location 2018 2017 2016 (dollars in thousands) Natural Gas Swaps Fuel $ 6,088 $ 3,818 $ 2,445 Natural Gas Swaps Fuel (956) (1,677) (19,697) Total $ 5,132 $ 2,141 $ (17,252) The following table presents the unrealized (gains) and losses on derivative instruments deferred on the balance sheet at December 31, 2018 and 2017. Consolidated Balance Sheet Location 2018 2017 (dollars in thousands) Natural Gas Swaps Regulatory asset $ 13,154 $ 6,328 Total $ 13,154 $ 6,328 |
Investments_
Investments: | 12 Months Ended |
Dec. 31, 2018 | |
Investments: | |
Investments: | 4. Investments: Investments in debt and equity securities Investment securities we hold are recorded at fair value in the accompanying consolidated balance sheets. Prior to October 1, 2017, unrealized gains and losses of investment securities related to nuclear decommissioning were deferred pursuant to regulated operations accounting, while those for all other investment securities were recorded to accumulated other comprehensive (deficit) margin. During the fourth quarter of 2017, we began applying regulated operations accounting to the unrealized gains and losses of all investment securities. All realized and unrealized gains and losses are determined using the specific identification method. At December 31, 2018, approximately 59% of the gross unrealized losses with a fair value of $49,975,000 had been unrealized for a duration of greater than one year, while the remaining gross unrealized losses with a fair value of $351,488,000 had been unrealized for a duration of less than one year. At December 31, 2017, approximately 69% of the gross unrealized losses with a fair value of $60,101,000 had been unrealized for a duration of greater than one year, while the remaining gross unrealized losses with a fair value of $337,444,000 had been unrealized for a duration of less than one year. The following tables summarize debt and equity securities at December 31, 2018 and 2017. (dollars in thousands) Gross Unrealized 2018 Cost Gains Losses Fair Value Equity $ 251,226 $ 64,954 $ (9,105) $ 307,075 Debt 278,030 1,718 (4,955) 274,793 Other 3,075 — — 3,075 Total $ 532,331 $ 66,672 $ (14,060) $ 584,943 (dollars in thousands) Gross Unrealized 2017 Cost Gains Losses Fair Value Equity $ 246,549 $ 91,954 $ (4,064) $ 334,439 Debt 240,878 1,814 (2,262) 240,430 Other 10,807 1 — 10,808 Total $ 498,234 $ 93,769 $ (6,326) $ 585,677 The contractual maturities of debt securities, which are included in the estimated fair value table above, at December 31, 2018 and 2017 are as follows: (dollars in thousands) 2018 2017 Cost Fair Value Cost Fair Value Due within one year $ 65,039 $ 63,925 $ 54,785 $ 54,143 Due after one year through five years 62,293 61,924 53,050 52,834 Due after five years through ten years 50,606 49,855 51,367 51,600 Due after ten years 100,092 99,089 81,676 81,853 Total $ 278,030 $ 274,793 $ 240,878 $ 240,430 The following table summarizes the realized gains and losses and proceeds from sales of securities for the years ended December 31, 2018, 2017 and 2016: (dollars in thousands) 2018 2017 2016 Gross realized gains $ 14,268 $ 35,523 $ 19,934 Gross realized losses (19,139) (16,909) (20,030) Proceeds from sales 626,612 521,345 439,540 Investment in associated companies Investments in associated companies were as follows at December 31, 2018 and 2017: (dollars in thousands) 2018 2017 National Rural Utilities Cooperative Finance Corporation (CFC) $ 24,061 $ 24,056 CT Parts, LLC 10,236 10,243 Georgia Transmission Corporation 30,237 28,690 Georgia System Operations Corporation 9,250 8,500 Other 3,253 3,492 Total $ 77,037 $ 74,981 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 investment in Georgia Transmission represents capital credits. The investment in Georgia System Operations represents loan advances. Repayments of these advances are due by December 2022. 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. Pursuant to a payment undertaking agreement, we have a guarantee for the annual basic rent payments due under the remaining lease. The fair value amount relating to the guarantee of basic rent payment is immaterial to us principally due to the high credit rating of the payment undertaker, Rabobank Nederland. The basic rental payments remaining through the end of the lease, which expires in 2027, are approximately $42,218,000. At the end of the term of the remaining facility lease, we have the option to cause RMLC to purchase the owner trust’s undivided interest in Rocky Mountain at a fixed purchase option price of approximately $112,000,000. The payment undertaking agreement, along with the equity funding agreement with AIG Matched Funding Corp., would fund approximately $74,000,000 and $37,928,000 of this amount, respectively, and these amounts would be paid to the owner trust over five installments in 2027. If we do not elect to cause RMLC to purchase the owner trust’s undivided interest in Rocky Mountain, Georgia Power has an option to purchase the undivided interest. If neither we nor Georgia Power exercise our purchase option, and we return (through RMLC) the undivided interest in Rocky Mountain to the owner trust, the owner trust has several options it can elect, including: · causing RMLC and us to renew the related facility lease and facility sublease for up to an additional 16 years and provide collateral satisfactory to the owner trust, · leasing its undivided interest to a third party under a replacement lease, or · retaining the undivided interest for its own benefit. Under the first two of these options we must arrange new financing for the outstanding amount of the loan used to finance the owner trust’s upfront rental payment made to us when the lease closed on December 31, 1996. At the end of the lease term, the amount of the outstanding loan is anticipated to be approximately $74,000,000. If new financing cannot be arranged, the owner trust can ultimately cause us to purchase 49%, in the case of the first option above, or all, in the case of the second option above, of the loan certificate or cause RMLC to exercise its purchase option or RMLC to renew the facility lease and facility sublease, respectively. The assets of RMLC are not available to pay our creditors. |
Income taxes_
Income taxes: | 12 Months Ended |
Dec. 31, 2018 | |
Income taxes: | |
Income taxes: | 5. Income taxes: While we are a not-for-profit membership corporation formed under the laws of the state 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 our 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: 2018 2017 2016 Statutory federal income tax rate 21.0 % 35.0 % 35.0 % Patronage exclusion (20.8) % (34.1) % (34.7) % AMT credit monetization % 2.2 % 0.0 % Other (0.2) % (0.9) % (0.3) % Effective income tax rate % (2.2) % 0.0 % The tax benefit reflected in the effective income tax rate reconciliation in 2017 relates to the approximate $1,117,000 current tax benefit realized as a result of monetizing the remaining balance of alternative minimum tax credits. This benefit is as a result of a refundable credit, and since it is applied after considering the patronage dividend deduction, it is not allocated to our members, but instead is a source of cash to the taxpayer applied against its normal operating expenses. The benefit is shown as a component of production operating expenses on the statement of revenues and expenses. The components of our net deferred tax assets and liabilities as of December 31, 2018 and 2017 were as follows: (dollars in thousands) 2018 2017 Deferred tax assets Net operating losses $ 3,830 $ 19,668 Tax credits (alternative minimum tax and other) — — Accounting for Rocky Mountain transactions 231,543 231,268 Advance payments 46,708 — Other assets 82,655 75,013 Deferred tax assets 364,736 325,949 Less: Valuation allowance (3,830) (19,668) Net deferred tax assets $ 360,906 $ 306,281 Deferred tax liabilities Depreciation $ 268,039 $ 271,652 Accounting for Rocky Mountain transactions 116,226 114,514 Other liabilities 75,691 78,407 Deferred tax liabilities 459,956 464,573 Net deferred tax liabilities 99,050 158,292 Less: Patronage exclusion (99,050) (158,292) Net deferred taxes $ — $ — As of December 31, 2018, we have federal tax net operating loss carryforwards and alternative minimum tax credits as follows: (dollars in thousands) Alternative Minimum Expiration Date Tax Credits NOLs 2019 — 10,516 2020 — 4,362 $ — $ 14,878 The net operating loss expiration dates start in the year 2019 and end in the year 2020. Due to the tax basis method for allocating patronage dividends and as shown by the above valuation allowance, it is not more likely than not that the deferred tax asset related to the net operating losses will be realized. On December 22, 2017, the President signed into law Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act, or the Act. The Act made significant changes to U.S. federal income tax laws. The Act reduced the federal tax rate for corporations from 35% to 21% effective January 1, 2018 and changed or applied limitations to certain tax deductions. As of December 31, 2018 and 2017, there was no impact to the results of operation when re-measuring the cumulative temporary differences expected to reverse after the effective date using the newly enacted tax rate of 21%. In March 2018, the FASB issued “Income Taxes (Topic 740): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118” (SAB 118). In accordance with the standard and as stated above, we recognized the provisional tax impacts related to the re-measurement of our deferred income tax assets and liabilities as of the year ended December 31, 2017. During the year ended December 31, 2018, we finalized our SAB 118 analysis and there was no impact to the results of operations. In addition to the re-measurement of our cumulative temporary differences, the Act prompted a new cumulative temporary difference related to certain payments that are considered advance payments for tax purposes. Advance payments are no longer deferred for tax purposes but rather are included in taxable income in the year received. The new deferred tax asset recorded as of December 31, 2018 is $46,708,000. 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 2015 and 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 2015 and forward. We have no liabilities recorded for uncertain tax positions. |
Capital leases_
Capital leases: | 12 Months Ended |
Dec. 31, 2018 | |
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. The assumed interest rate at inception of the lease in 1985 was 11.05%. Three of the leases have lease terms through December 31, 2027, and one lease extends through June 30, 2031. At the end of the lease, we can elect to: · Renew the leases for a period of not less than one year and not more than five years at fair market value, · Purchase the undivided interest at fair market value, or · Redeliver the undivided interest to the lessors The minimum lease payments under the capital leases together with the present value of the net minimum lease payments as of December 31, 2018 are as follows: (dollars in Year Ending December 31, thousands) 2019 $ 14,949 2020 14,949 2021 14,949 2022 7,474 2023 22,424 2024-2031 70,483 Total minimum lease payments $ 145,228 Less: Amount representing interest (58,036) Present value of net minimum lease payments $ 87,192 Less: Current portion (5,462) Long-term balance $ 81,730 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. Capital lease amortization is recorded in depreciation and amortization expense. |
Debt_
Debt: | 12 Months Ended |
Dec. 31, 2018 | |
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 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 CFC first mortgage notes. Maturities for long-term debt and capital lease obligations through 2023 are as follows: (dollars in thousands) 2019 2020 2021 2022 2023 FFB $ 164,782 $ 180,107 $ 185,476 $ 189,176 $ 195,483 FMBs 351,010 1,010 1,010 1,010 1,010 PCBs (1) — 133,550 93,379 18,676 — CFC 1,035 391 — — — $ 516,827 $ 315,058 $ 279,865 $ 208,862 $ 196,493 Capital Leases 5,462 6,082 6,772 7,541 8,398 Total $ 522,289 $ 321,140 $ 286,637 $ 216,403 $ 204,891 (1) In addition to regularly scheduled principal payments included are amounts that would be due if the letters of credit supporting the Series 2009 and Series 2010 bonds were drawn upon and became payable in accordance with their terms, such as would occur if the credit facility the letters of credit were issued under was not renewed or extended at its expiration date. These amounts equal $133.6 million in 2020, $93.4 million in 2021 and $18.7 million in 2022. 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, 2018 and 2017 was 4.24% and 4.17%, respectively. Long-term debt outstanding and the associated unamortized debt issuance costs and debt discounts at December 31, 2018 and 2017 are as follows: 2018 2017 Unamortized Debt Unamortized Debt Issuance Costs and Issuance Costs and Principal Debt Discounts Principal Debt Discounts (dollars in thousands) FFB $ 4,372,422 $ 50,210 $ 4,192,450 $ 51,593 FMBs 3,556,062 41,509 3,057,072 34,673 PCBs 980,770 11,612 980,770 9,347 CFC 1,426 — 2,411 — $ 8,910,680 $ 103,331 $ 8,232,703 $ 95,613 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, we and the U.S. Department of Energy, acting by and through the Secretary of Energy, entered into a Loan Guarantee Agreement on February 20, 2014 pursuant to which the Department of Energy agreed to guarantee our obligations under a Note Purchase Agreement, dated as of February 20, 2014 (the Original Note Purchase Agreement), among us, the Federal Financing Bank and the Department of Energy and two future advance promissory notes, each dated February 20, 2014, made by us to the Federal Financing Bank in the aggregate amount of $3,057,069,461 (the Original FFB Notes and together with the Original Note Purchase Agreement, the Original FFB Documents). Following the bankruptcy of Westinghouse in 2017 (as described in Note 8), we and the Department of Energy amended the loan guarantee agreement to restrict further advances pending the satisfaction of certain conditions, including an amendment to the loan guarantee agreement. In September 2017, the Department of Energy issued a conditional commitment to us to guarantee an additional $1,619,679,706 of funding from the Federal Financing Bank. On March 7, 2019, we entered into an amendment and waiver of the loan guarantee agreement under which we received an advance of $585,000,000. On March 22, 2019, we and the Department of Energy entered into an Amended and Restated Loan Guarantee Agreement (as amended, the Loan Guarantee Agreement) which increased the aggregate amount guaranteed by the Department of Energy to $4,676,749,167 and permits us to draw the remaining amount under the Original FFB Notes. We also entered into a Note Purchase Agreement dated as of March 22, 2019 (the Additional Note Purchase Agreement), among us, the Federal Financing Bank and the Department of Energy and a future advance promissory note, dated March 22, 2019, made by us to the Federal Financing Bank in the amount of $1,619,679,706 (the Additional FFB Note and together with the Additional Note Purchase Agreement, the Additional FFB Documents). Together, the Original FFB Documents and Additional FFB Documents provide for a multi-advance term loan facility (the Facility) under which we may make long-term loan borrowings through the Federal Financing Bank. Proceeds of advances made under the Facility are used to reimburse us for a portion of certain costs of construction relating to Vogtle Units No. 3 and No. 4 that are eligible for financing under the Title XVII loan guarantee program (Eligible Project Costs). Borrowings under the Original FFB Notes may not exceed $3,057,069,461, of which $335,471,604 is designated for capitalized interest. Borrowings under the Additional FFB Note may not exceed (i) $1,619,679,706 or (ii) an amount that, when aggregated with borrowings under the Original FFB Notes, equals 70% of Eligible Project Costs less the $1,104,000,000 guarantee payment we received from Toshiba Corporation in December 2017. Total borrowings under the Facility will not exceed $4,676,749,167. At December 31, 2018, aggregate Department of Energy-guaranteed borrowings totaled $1,794,723,000, including capitalized interest. On March 15, 2019, we received a $585,000,000 advance under the Original FFB Notes. In conjunction with this advance, we repaid $436,600,000 of outstanding commercial paper, which was classified as long-term debt at December 31, 2018. We have no amounts outstanding under the Additional FFB Note. Under the Loan Guarantee Agreement, we are obligated to reimburse the Department of Energy in the event it is required to make any payments to the Federal Financing Bank under its guarantee. Our payment obligations to the Federal Financing Bank under the FFB Notes and reimbursement obligations to the Department of Energy under its guarantee, but not our covenants to the Department of Energy under the Loan Guarantee Agreement, are secured equally and ratably with all of our other obligations issued under our first mortgage indenture. The final maturity date for each advance is February 20, 2044. Interest is payable quarterly in arrears and principal payments on all advances under the FFB Notes will begin on February 20, 2020. Interest rates on borrowings during the applicable interest rate periods will equal the current average yield on U.S. Treasuries of comparable maturity at the beginning of the interest rate period, plus a spread equal to 0.375%. Advances under the Original FFB Notes may be requested on a quarterly basis through December 31, 2020. Advances under the Additional FFB Note may be requested on a quarterly basis through November 30, 2023, one year beyond the current anticipated commercial operation date of Vogtle Unit No. 4. Future advances under the Facility are subject to satisfaction of customary conditions, as well as (i) certification of compliance with the requirements of the Title XVII loan guarantee program, (ii) accuracy of project-related representations and warranties, (iii) delivery of updated project-related information, (iv) no Project Adverse Event (as described in Note 8) having occurred or, if a Project Adverse Event has occurred, that Co-owners (as described in Note 8) representing at least 90% of the ownership interests have voted to continue construction, have not deferred construction and we have provided the Department of Energy with certain additional information, (v) certification regarding Georgia Power’s compliance with certain obligations relating to the Cargo Preference Act, as amended, (vi) evidence of compliance with the applicable wage requirements of the Davis-Bacon Act, as amended, (vii) certification from the Department of Energy’s consulting engineer that proceeds of the advance are used to reimburse Eligible Project Costs and (viii) if either the Services Agreement or the Bechtel Agreement (each, as described in Note 8) are terminated, or rejected in bankruptcy proceedings, the Department of Energy has approved the replacement agreement. We may voluntarily prepay outstanding borrowings under the Facility. Under the FFB Documents, any prepayment will be subject to a make-whole premium or discount, as applicable. Any amounts prepaid may not be re-borrowed. Under the Loan Guarantee Agreement, we are subject to customary borrower affirmative and negative covenants and events of default. In addition, we are subject to project-related reporting requirements and other project-specific covenants and events of default. If certain events occur, referred to as an “Alternate Amortization Event,” at the Department of Energy’s option the Federal Financing Bank’s commitment to make further advances under the Facility will terminate and we will be required to repay the outstanding principal amount of all borrowings under the Facility over a period of five years, with level principal amortization. These events include (i) abandonment of the Vogtle Units No. 3 and No. 4 project, including a decision by Georgia Power to cancel the project, (ii) cessation of the construction of Vogtle Units No. 3 and No. 4 for twelve consecutive months, (iii) termination of the Services Agreement or rejection of the Services Agreement in bankruptcy, if Georgia Power does not maintain access to certain related intellectual property rights, (iv) termination of the Services Agreement by Westinghouse or termination of the Bechtel Agreement by Bechtel Power Corporation, (v) delivery of certain notices by the Co-owners to the Department of Energy of their intent to cancel construction of Vogtle Units No. 3 and No. 4 coupled with termination by the Co-owners of the Services Agreement or the Bechtel Agreement, (vi) failure of the Co-owners to enter into a replacement contract with respect to the Services Agreement or the Bechtel Agreement following the Co-owners’ termination of such agreement with the intent to replace it, (vii) the Department of Energy’s takeover of construction of Vogtle Units No. 3 and No. 4 under certain conditions, (viii) the occurrence of any Project Adverse Event that results in a cancellation of the Vogtle Units No. 3 and No. 4 project or the cessation or deferral of construction beyond the periods permitted under the Amended Loan Guarantee Amendment, (ix) loss of or failure to receive necessary regulatory approvals under certain circumstances, (x) loss of access to intellectual property rights necessary to construct or operate Vogtle Units No. 3 and No. 4 under certain circumstances, (xi) our failure to fund our share of operation and maintenance expenses for Vogtle Units No. 3 and No. 4 for twelve consecutive months, (xii) change of control of Oglethorpe and (xiii) certain events of loss or condemnation. If we receive proceeds from an event of condemnation relating to Vogtle Units No. 3 and No. 4, such proceeds must be applied to immediately prepay outstanding borrowings under the Facility. b) Rural Utilities Service Guaranteed Loans: During 2018, we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling $313,028,000 for long-term financing of general and environmental improvements at existing plants. In February 2019, we received an additional $47,940,000 in advances on Rural Utilities Service-guaranteed Federal Financing Bank loans for long-term financing of general and environmental improvements at existing plants. c) Pollution Control Revenue Bonds: On December 28, 2017, the Development Authority of Burke County (Georgia) issued, on our behalf, $399,785,000 (Series 2017C, D, E, F Burke) in aggregate principal amount of tax-exempt pollution control revenue bonds to refinance costs associated with certain of our pollution control facilities. The bonds were directly purchased by two banks and the proceeds defeased our obligations under $399,785,000 of pollution control revenue bonds issued in 2008 that were callable on or after January 1, 2018. Those 2008 bonds were fully redeemed on their call date. Each series of the 2017 bonds bore interest at an indexed variable rate until February 1, 2018 when we converted the bonds into fixed interest rate modes. We converted the (i) $200,000,000 Series 2017C and Series 2017D bonds to a fixed rate of 4.125% per annum to maturity with an optional call at par on February 1, 2028, (ii) $100,000,000 Series 2017E bonds to a fixed term rate of 3.25% per annum to the mandatory tender date of February 3, 2025 and (iii) $99,785,000 Series 2017F bonds to a fixed term rate of 3.00% per annum to the mandatory tender date of February 1, 2023. The Series 2017C, D, E, F bonds are scheduled to mature in 2041 through 2045. Our payment obligations related to these bonds are secured under our first mortgage indenture. d) First Mortgage Bonds: On October 30, 2018, we issued $500,000,000 of 5.05% first mortgage bonds, Series 2018A, for the purpose of providing long-term financing for expenditures related to the construction of Vogtle Units No. 3 and No. 4. The bonds are due to mature October 2048 and are secured under our first mortgage indenture. e) Credit Facilities: As of December 31, 2018, we had a total of $1,610,000,000 of committed credit arrangements comprised of four separate facilities with maturity dates that range from March 2020 to December 2023. 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, 2018, 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, 2018, 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) $436,627,000 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, 2018 and December 31, 2017 was 2.98% and 1.58%, respectively. |
Electric plant, construction an
Electric plant, construction and related agreements: | 12 Months Ended |
Dec. 31, 2018 | |
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 their 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, 2018 and 2017 is as follows: 2018 2017 (dollars in thousands) Accumulated Accumulated Plant Investment Depreciation Investment Depreciation In-service (1) Owned property Vogtle Units No. 1 & No. 2 (Nuclear – 30% ownership) $ 2,975,727 $ (1,775,569) $ 2,916,852 $ (1,751,558) Vogtle Units No. 3 & No. 4 (Nuclear – 30% ownership) 55,861 (3,479) 36,745 (2,514) Hatch Units No. 1 & No. 2 (Nuclear – 30% ownership) 910,259 (441,240) 824,890 (420,000) Wansley Units No. 1 & No. 2 (Fossil – 30% ownership) 655,618 (311,606) 587,436 (236,155) Scherer Unit No. 1 (Fossil – 60% ownership) 1,222,538 (442,840) 1,102,085 (399,774) Doyle (Combustion Turbine – 100% ownership) 137,133 (109,509) 136,351 (106,370) Rocky Mountain Units No. 1, No. 2 & No. 3 (Hydro – 75% ownership) 618,621 (258,359) 609,048 (246,758) Hartwell (Combustion Turbine – 100% ownership) 226,156 (105,540) 225,808 (104,269) Hawk Road (Combustion Turbine – 100% ownership) 254,925 (75,308) 251,671 (73,998) Talbot (Combustion Turbine – 100% ownership) 293,638 (136,007) 292,250 (128,344) Chattahoochee (Combined cycle – 100% ownership) 315,463 (141,279) 313,587 (133,378) Smith (Combined cycle – 100% ownership) 648,464 (179,486) 642,732 (170,366) Wansley (Combustion Turbine – 30% ownership) 3,887 (3,626) 3,887 (3,552) Transmission plant 95,861 (56,973) 92,929 (55,502) Other 93,503 (56,193) 92,179 (54,927) Property under capital lease: Scherer Unit No. 2 (Fossil – 60% leasehold) 776,316 (447,391) 757,957 (414,867) Total in-service $ 9,283,970 $ (4,544,405) $ 8,886,407 $ (4,302,332) Construction work in progress Vogtle Units No. 3 & No. 4 (2) $ 3,600,631 $ 2,721,949 Environmental and other generation improvements 263,146 212,476 Other 2,265 1,443 Total construction work in progress $ 3,866,042 $ 2,935,868 (1) Amounts include plant acquisition adjustments at December 31, 2018 and 2017 of $197,000,000. (2) The 2017 amount is net of a $1,104,000,000 credit recorded as a result of payments received from Toshiba under the Guarantee Settlement Agreement as described in Note 8b. 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 Vogtle Units No. 3 and No. 4 We, Georgia Power Company, the Municipal Electric Authority of Georgia (MEAG), and the City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, doing business as Dalton Utilities (collectively, the Co-owners) are parties to an Ownership Participation Agreement that, along with other agreements, governs our participation in two additional nuclear units at Plant Vogtle, Units No. 3 and No. 4. The Co-owners appointed Georgia Power to act as agent under this agreement. Our ownership interest and proportionate share of the cost to construct these units is 30%. Pursuant to this agreement, Georgia Power has designated Southern Nuclear Operating Company, Inc. as its agent for licensing, engineering, procurement, contract management, construction and pre-operation services. In 2008, Georgia Power, acting for itself and as agent for the Co-owners, entered into an Engineering, Procurement and Construction Agreement (the EPC Agreement) with Westinghouse Electric Company LLC and Stone & Webster, Inc., which was subsequently acquired by Westinghouse and changed its name to WECTEC Global Project Services Inc. (collectively, Westinghouse). Pursuant to the EPC Agreement, Westinghouse agreed to design, engineer, procure, construct and test two 1,100 megawatt nuclear units using the Westinghouse AP1000 technology and related facilities at Plant Vogtle. Until March 2017, construction on Units No. 3 and No. 4 continued under the substantially fixed price EPC Agreement. In March 2017, Westinghouse filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. Effective in July 2017, Georgia Power, acting for itself and as agent for the other Co-owners, and Westinghouse entered into a services agreement (the Services Agreement), pursuant to which Westinghouse is providing facility design and engineering services, procurement and technical support and staff augmentation on a time and materials cost basis. The Services Agreement provides that it will continue until the start-up and testing of Vogtle Units No. 3 and No. 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Co-owners upon 30 days’ written notice. In October 2017, Georgia Power, acting for itself and as agent for the other Co-owners, entered into a construction completion agreement with Bechtel Power Corporation, pursuant to which Bechtel serves as the primary contractor for the remaining construction activities for Vogtle Units No. 3 and No. 4 (the Bechtel Agreement). The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel’s performance against cost and schedule targets. Each Co-owner is severally, and not jointly, liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Co-owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Co-owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Co-owner suspensions of work, certain breaches of the Bechtel Agreement by the Co-owners, Co-owner insolvency and certain other events. In November 2017, the Co-owners entered into an amendment to their joint ownership agreements for Vogtle Units No. 3 and No. 4 to provide for, among other conditions, additional Co-owner approval requirements. These joint ownership agreements, including the Co-owner approval requirements, were subsequently amended, effective August 31, 2018. As described below, certain provisions of the Joint Ownership Agreements were modified further on September 26, 2018 by the Term Sheet that was memorialized on February 18, 2019 when the Co-owners entered into certain amendments (the Global Amendments) to the Joint Ownership Agreements (as amended, the Joint Ownership Agreements). On December 21, 2017, the Georgia Public Service Commission took a series of actions related to the construction of Vogtle Units No. 3 and No. 4 and issued its related order on January 11, 2018. Among other actions, the Public Service Commission (i) accepted Georgia Power’s recommendation to continue construction of Vogtle Units No. 3 and No. 4, with Southern Nuclear serving as construction manager and Bechtel as primary contractor and (ii) approved the revised schedule placing Unit No. 3 in service in November 2021 and Unit No. 4 in service in November 2022. In its January 11, 2018 order, the Public Service Commission stated if certain conditions change and assumptions upon which Georgia Power’s seventeenth Vogtle construction monitoring (VCM) report are based do not materialize, the Public Service Commission reserved the right to reconsider the decision to continue construction. Third parties have filed two petitions with the Fulton County Superior Court appealing the Georgia Public Service Commission’s January 11, 2018 order. On December 21, 2018, the Superior Court granted Georgia Power’s motion to dismiss the two appeals. On January 9, 2019, those parties appealed that decision to the Georgia Court of Appeals. Georgia Power has stated that it believes the appeal has no merit; however, an adverse outcome in the appeal combined with subsequent adverse action by the Public Service Commission could have a material impact on our financial condition and results of operations. In 2018, Georgia Power advised us that it became aware that the estimated future Vogtle project costs were projected to exceed the corresponding budgeted amounts included in its seventeenth VCM report. Upon discovery of these variances, the Co-owners requested Southern Nuclear perform a full cost analysis and reforecast the cost to complete the project and engaged a third party to independently assess this analysis, forecast, and existing project controls for identifying budget variances. Following this analysis, Georgia Power proposed an increased construction budget and included a revised estimate to complete in its nineteenth VCM report filed with the Georgia Public Service Commission in August 2018. This revised estimate included an approximate $1.5 billion increase in capital costs (our 30% share is approximately $450 million) and a project-level contingency in an amount of $800 million (our 30% share is $240 million). The increase in the revised budget is primarily attributable to Bechtel and subcontractor construction costs, including craft labor incentives, as well as expenses for project management, oversight and support. The scheduled in-service dates of November 2021 and November 2022 for Vogtle Units No. 3 and No. 4, respectively, did not change in connection with these budget revisions. Further, Georgia Power informed the Public Service Commission in its nineteenth VCM report that it did not intend to seek rate recovery for its proportionate share of the additional capital costs identified in that report. As a result of Georgia Power’s decision not to seek rate recovery of its allocation of these costs and the increased construction budget, the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 were required to vote to continue construction. In September 2018, the Co-owners voted to continue construction of Vogtle Units No. 3 and No. 4. In connection with our vote to continue construction with Vogtle Units No. 3 and No. 4, we approved a revised budget of $7.5 billion for our 30% ownership interest. The impact of the additional project costs on our budget was substantially mitigated by nearly $500 million of contingency included in our prior budget. As with our prior budgets and consistent with our conservative budget practices, our revised budget includes a separate Oglethorpe-level contingency amount in addition to capital costs, allowance for funds used during construction, and our allocation of the project-level contingency. We and some of our members have implemented various rate management programs to lessen the impact on rates when Vogtle Units No. 3 and No. 4 reach commercial operation. As of December 31, 2018, our total investment in the additional Vogtle units was approximately $3.9 billion. As construction continues, risks remain that construction-related challenges, including management of contractors, subcontractors, and vendors; labor productivity, availability, and/or cost escalation; procurement, fabrication, delivery, assembly and/or installation and testing, including any required engineering changes, of plant systems, structures and components; or other issues could further impact the projected schedule and cost. Monthly construction production targets required to maintain the current project schedule will continue to increase significantly throughout 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers must be retained and deployed. Aspects of the Westinghouse AP1000 design are based on new technologies that only recently began commercial operation in the global nuclear industry at this scale. Georgia Power and Southern Nuclear are in the process of validating recent construction progress in comparison to the projected schedule and verifying and updating quantities of commodities remaining to install, labor productivity, and forecasted staffing needs. This verification process, led by Southern Nuclear, is expected to be completed during the second quarter of 2019. Although the verification is not complete, we currently do not anticipate any material changes to our project budget of $7.5 billion or the Public Service Commission approved in-service dates of November 2021 and November 2022 as a result of this verification process. However, the current schedule being utilized to manage construction at the Vogtle site, which targets in-service dates in advance of November 2021 and November 2022, may be adjusted to reflect updated information provided by the verification process. The ultimate impact on cost and schedule, if any, will not be known until the verification process is completed. Georgia Power has stated that it is required to report the results and any project impacts to the Public Service Commission by May 15, 2019. There have been technical and procedural challenges to the construction and licensing of Vogtle Units No. 3 and No. 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the Nuclear Regulatory Commission that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the Nuclear Regulatory Commission. Various design and other licensing-based compliance matters, including the timely resolution of inspections, tests, analyses, and acceptance criteria and the related approvals by the Nuclear Regulatory Commission, may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be further delays in the project schedule that could result in increased costs to the Co-owners. In connection with the September 2018 vote to continue construction, Georgia Power entered into a binding term sheet with the other Co-owners and MEAG’s wholly-owned subsidiaries MEAG Power SPVJ, LLC, MEAG Power SPVM, LLC, and MEAG Power SPVP, LLC that mitigated certain financial exposure for the other Co-owners and offered to purchase production tax credits from each of the other Co-Owners, at that Co-owner’s option (the Term Sheet). On February 18, 2019, the Co-owners entered into the Global Amendments to memorialize the provisions of the Term Sheet. Pursuant to the Global Amendments and consistent with the Term Sheet, the Joint Ownership Agreements provide that: · each Co-owner is obligated to pay its proportionate share of construction costs for Vogtle Units No. 3 and No. 4 based on its ownership interest up to (i) the estimated cost at completion (“EAC”) for Vogtle Units No. 3 and No. 4 which formed the basis of Georgia Power’s forecast of $8.4 billion in Georgia Power’s nineteenth VCM report filed with the Georgia Public Service Commission plus (ii) $800 million of additional construction costs; · Georgia Power will be responsible for 55.7% of construction costs, subject to exceptions, that exceed the EAC in the nineteenth VCM report by $800 million to $1.6 billion (resulting in up to $80 million of potential additional costs to Georgia Power which would save Oglethorpe up to $44 million), with the remaining Co-owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests (equal to 24.5% for our 30% ownership interest); and · Georgia Power will be responsible for 65.7% of construction costs, subject to exceptions, that exceed the EAC in the nineteenth VCM report by $1.6 billion to $2.1 billion (resulting in up to a further $100 million of potential additional costs to Georgia Power which would save Oglethorpe up to an additional $55 million), with the remaining Co-owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests (equal to 19.0% for our 30% ownership interest). If the EAC is revised and exceeds the EAC in the nineteenth VCM report by more than $2.1 billion, each of the Co-owners, other than Georgia Power, will have a one-time option at the time the project budget forecast is so revised to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power’s agreement to pay 100% of such Co-owner’s remaining share of construction costs in excess of the EAC in the nineteenth VCM report plus $2.1 billion. In this event, Georgia Power would have the option of cancelling the project in lieu of purchasing a portion of the ownership interest of any other Co-owner. If Georgia Power accepts the offer to purchase a portion of another Co-owner’s ownership interest in Vogtle Units No. 3 and No. 4, the ownership interest to be conveyed from the tendering Co-owner to Georgia Power will be calculated based on the proportion of the cumulative amount of construction costs paid by each such tendering Co-owner and by Georgia Power as of the commercial operation date of Vogtle Unit No. 4. For purposes of this calculation, payments made by Georgia Power on behalf of another Co-owner in accordance with the second and third bullets above will be treated as payments made by the applicable Co-owner. This option to tender a portion of our interest to Georgia Power upon such a budget increase would allow us to freeze our construction budget associated with the Vogtle project in exchange for a portion of our 30% ownership interest. In the event the actual costs of construction at completion of a unit are less than the EAC reflected in the nineteenth VCM report and (i) Vogtle Unit No. 3 is placed in service by the currently scheduled date of November 2021 or (ii) Vogtle Unit No. 4 is placed in service by the currently scheduled date of November 2022, Georgia Power will be entitled to 60.7% of the cost savings with respect to the relevant unit and the remaining Co-owners will be entitled to 39.3% of such savings on a pro rata basis in accordance with their respective ownership interests. Pursuant to the Global Amendments, the Co-owners will continue to retain a third party to independently consult, advise and report to the Co-owners on issues pertaining to (i) project management and controls, (ii) organizational controls, (iii) commercial management plans and (iv) interim project reports until released by 67% of the Co-owners. Pursuant to the Joint Ownership Agreements, as amended by the Global Amendments, the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 must vote to continue construction, or can vote to suspend construction, if certain adverse events occur, including: (i) the bankruptcy of Toshiba Corporation; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement, the Bechtel Agreement or the agency agreement with Southern Nuclear; (iii) Georgia Power publicly announces its intention not to submit for rate recovery any portion of its investment in Vogtle Units No. 3 and No. 4 (or associated financing costs) or the Georgia Public Service Commission determines that any of Georgia Power’s costs relating to the construction of Vogtle Units No. 3 and No. 4 will not be recovered in retail rates, excluding any additional amounts paid by Georgia Power on behalf of the other Co-owners pursuant to the Global Amendment provisions described above and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Public Service Commission for recovery, or for which Georgia Power elects not to seek cost recovery, through retail rates or (iv) an incremental extension of one year or more over the most recently approved schedule. In addition, pursuant to the Joint Ownership Agreements, the required approval of holders of ownership interests in Vogtle Units No. 3 and No. 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement. The Global Amendments provide that Georgia Power may cancel the project at any time at its sole discretion. In the event that Georgia Power determines to cancel the project or fewer than 90% of the Co-owners vote to continue construction upon the occurrence of a subsequent project adverse event, we and the other Co-owners would assess our options for the Vogtle project. If the investment were to be written off, we would seek regulatory accounting treatment to amortize the investment over a long-term period, which requires the approval of our board of directors, and we would submit the regulatory accounting treatment details to the Rural Utilities Service for its approval. Further, if Georgia Power or the Co-owners decided to cancel the project, the Department of Energy would have the discretion to require that we repay all amounts outstanding under our loan guarantee agreement with the Department of Energy over a five-year period as discussed in Note 7. We have an aggregate amount of $4,676,749,167 in federal loans from the Federal Financing Bank guaranteed by the Department of Energy, pursuant to which we have borrowed $1,794,723,000 as of December 31, 2018. On March 15, 2019, we received an advance of an additional $585,000,000 of funding guaranteed by the Department of Energy. For additional information regarding these loans and the related loan guarantee, including conditions for future advances, potential repayment over a five-year period, covenants and events of default under the loan guarantee agreement with the Department of Energy, see Note 7. We have also financed $1,887,000,000 of the capital costs of the Vogtle units through capital market debt issuances. We anticipate financing any project costs not guaranteed by the Department of Energy in the capital markets. The ultimate outcome of these matters cannot be determined at this time. |
Employee benefit plans_
Employee benefit plans: | 12 Months Ended |
Dec. 31, 2018 | |
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. 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 $1,497,000, $1,436,000 and $1,371,000 in 2018, 2017 and 2016, respectively. Our 401(k) plan also includes an employer retirement contribution feature, which subject to IRS limitations, contributes 11% of an employee’s eligible annual compensation. Our contributions to the employer retirement contribution feature of the 401(k) plan were approximately $3,903,000, $3,791,000 and $3,678,000 in 2018, 2017 and 2016, respectively. We also sponsor two deferred compensation plans for eligible employees. Eligible employees are defined as highly compensated individuals within the definition of the Internal Revenue Code. The plans offer investment options to all eligible participants without regard to salary limits. In addition, one plan enables us to continue employer retirement contributions to highly compensated employees who exceed Internal Revenue Code salary limits for retirement plan contributions. The value of the plans is recorded as an asset and an equal offsetting liability with balances of $2,387,000 and $2,145,000 in 2018 and 2017, respectively. |
Nuclear insurance_
Nuclear insurance: | 12 Months Ended |
Dec. 31, 2018 | |
Nuclear insurance: | |
Nuclear insurance: | 10. Nuclear insurance: The Price-Anderson Act limits public liability claims that could arise from a single nuclear incident to $14,100,000,000. 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 $450,000,000, a licensee of a nuclear power plant could be assessed a deferred premium of up to $138,000,000 per incident for each licensed reactor operated by it, but not more than $20,000,000 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 $165,000,000 per incident, but not more than $25,000,000 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, 2023. 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 and non-nuclear policies 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 $42,000,000. 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, 2018 | |
Commitments: | |
Commitments: | 11. Commitments: a. Operating leases As of December 31, 2018, our estimated minimum rental commitments are as follows: (dollars in thousands) 2019 $ 3,730 2020 1,413 2021 798 2022 608 2023 386 Thereafter 1,157 Our rental commitments are primarily for leases of railcars which are used to deliver coal to our coal-fired facilities. These railcar leasing costs are added to the cost of the fossil inventories and are recognized in fuel expense as the inventories are consumed. Rental expenses totaled $4,562,000, $4,919,000 and $4,456,000 in 2018, 2017 and 2016, respectively. We are assessing our future railcar needs and evaluating leasing options. b. Fuel To supply a portion of the fuel requirements to our generating units, Georgia Power, on our behalf for coal and Southern Nuclear on our behalf for nuclear fuel, 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. We have entered into long-term agreements with various counterparties to provide firm natural gas transportation to our natural gas-fired facilities. The value of these agreements is based on fixed rates as provided in the contracts and does not include variable costs. We have also entered into long-term maintenance agreements for certain of our natural gas-fired facilities. In most cases, these agreements include provisions for price escalation and performance bonuses and, if applicable, are included in the values; timing of expenditures is based on current operational assumptions. Certain agreements contain significant cancellation for convenience penalties and, therefore, amounts in the table below include total estimated expenditures over the life of the agreement. If these agreements were terminated by us in 2019 for convenience, our cancellation obligation would be approximately $80,000,000. We have asset retirement obligations which are legal obligations to retire long-lived assets. These obligations are primarily for the decommissioning of our nuclear units and coal ash ponds. Expenditures are based on estimates determined through decommissioning studies and include provisions for price escalation and other factors. See Note 1h for information regarding our asset retirement obligations. As of December 31, 2018, our estimated commitments are as follows: (dollars in thousands) Gas Maintenance Asset Retirement Coal Nuclear Fuel Transportation Agreements Obligations 2019 $ 22,065 $ 49,100 $ 64,497 $ 29,510 $ 8,664 2020 7,091 27,500 63,260 53,911 11,274 2021 2,348 30,300 62,737 14,461 11,215 2022 — 25,400 53,796 14,929 11,200 2023 — 18,400 47,513 3,330 37,743 Thereafter — 35,100 848,609 281,938 3,536,362 |
Contingencies and Regulatory Ma
Contingencies and Regulatory Matters: | 12 Months Ended |
Dec. 31, 2018 | |
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. 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. 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. The ultimate impact of any environmental regulations 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. |
Quarterly financial data (unaud
Quarterly financial data (unaudited): | 12 Months Ended |
Dec. 31, 2018 | |
Quarterly financial data (unaudited): | |
Quarterly financial data (unaudited): | 13. Quarterly financial data (unaudited): Summarized quarterly financial information for 2018 and 2017 is as follows: First Second Third Fourth Quarter Quarter Quarter Quarter (dollars in thousands) 2018 Operating revenues $ 373,646 $ 365,921 $ 384,644 $ 355,902 Operating margin 69,931 60,849 54,845 39,351 Net margin 27,400 17,285 11,334 (4,820) 2017 Operating revenues $ 354,170 $ 361,369 $ 376,656 $ 342,001 Operating margin 69,330 63,472 59,520 46,548 Net margin 21,454 15,676 11,555 2,592 The negative net margins in the fourth quarter of 2018 were due to reductions to revenue requirements in order to achieve, but not exceed, the targeted margins for interest ratio of 1.14. |
Summary of significant accoun_2
Summary of significant accounting policies: (Policies) | 12 Months Ended |
Dec. 31, 2018 | |
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 7,060 megawatts of summer planning reserve capacity. We also manage and operate Smarr EMC which owns 731 megawatts of summer planning reserve capacity. In addition, we supply financial and management services to Green Power EMC, which purchases energy from renewable energy facilities totaling 120 megawatts of capacity, including 87 megawatts sourced by solar energy. 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 4.1 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, 2018 and 2017 and the reported amounts of revenues and expenses for each of the three years in the period ended December 31, 2018. Actual results could differ from those estimates. |
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. |
Margin policy | d. 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 2018, 2017 and 2016, we achieved a margins for interest ratio of 1.14. |
Revenue recognition | e. Revenue recognition As an electric membership cooperative, our principle business is providing wholesale electric service to our members. Our operating revenues are derived primarily from wholesale power contracts we have with each of our 38 members. These contracts, which extend to December 31, 2050, are substantially identical and obligate our members jointly and severally to pay all expenses associated with owning and operating our power supply business. As a cooperative, we operate on a not-for-profit basis and, accordingly, seek only to generate revenues sufficient to recover our cost of service and to generate margins sufficient to establish reasonable reserves and meet certain financial coverage requirements. While not significant, we also have short-term energy sales to non-members made through industry standard contracts. We do not have multiple operating segments. Pursuant to our contracts, we primarily provide two services, capacity and energy. Capacity and energy revenues are recognized by us upon transfer of control of promised services to our members and non-members in an amount that reflects the consideration we expect to receive in exchange for those services. Capacity and energy are distinct and we account for them as separate performance obligations. The obligations to provide capacity and energy are satisfied over time as the customer simultaneously receives and consumes the benefit of these services. Both performance obligations are provided directly by us and not through a third party. Each of our members is obligated under their wholesale power contract to pay us for capacity and energy we furnish under their wholesale power contract in accordance with rates we establish. We review our rates periodically but are required to do so at least once every year. Revenues from our members are derived through a cost-plus rate structure which is set forth as a formula in the rate schedule to the wholesale power contracts between us and each of our members. The formulary rate provides for the pass-through of our (i) fixed costs (net of any income from other sources) plus a targeted margin as capacity revenues and (ii) variable costs as energy revenues from our members. Power purchase and sale agreements between us and non-members obligate each non-member to pay us for capacity, if any, and energy furnished in accordance with the prices mutually agreed upon. Margins produced from non-member sales are included in our rate schedule formula and reduce revenue requirements from our members. The standard selling price at which we provide capacity services to our members is determined by our formulary rate on an annual basis. As a result, the consideration we receive for providing capacity services is determined annually. Over the course of a year, our member capacity revenues are relatively stable. Capacity revenues may fluctuate year to year largely due to the recovery of fixed operation and maintenance costs. The components of the formulary rate associated with capacity costs include the annual budget of fixed costs, a targeted margin and income from other sources. Capacity revenues, therefore, vary to the extent these components vary. Fixed costs include items such as fixed operation and maintenance expenses, administrative and general expenses, depreciation and interest. Year to year, capacity revenue fluctuations are generally due to the recovery of fixed operation and maintenance costs. Fixed costs also include certain costs, such as major maintenance costs, which will be recognized as expense in future periods. Recognition of revenues associated with these future expenses is deferred pursuant to Accounting Standards Codification (ASC) 980, Regulated Operations. The regulatory liabilities are amortized to revenue in accordance with the associated revenue deferral plan. For information regarding regulatory accounting, see Note 1q. Capacity revenues are recognized by us for standing ready to deliver electricity to our customers. Our capacity revenues are based on the associated costs we expect to recover in a given year and are recognized and billed to our members in equal monthly installments over the course of the year regardless of whether our generation and purchased power resources are dispatched to produce electricity. Non-member capacity revenues, if any, are typically billed and recognized in equal monthly installments over the term of the contract. We have a power bill prepayment program pursuant to which our members may prepay future capacity costs and receive a discount. As this program provides us with significant financing, we adjust our capacity revenues by the amount of the discount, which is based on our avoided cost of borrowing. For additional information regarding our member prepayment program, see Note 1p. We satisfy our performance obligations to deliver energy as energy is delivered to the applicable meter points. We determine the standard selling price for energy we deliver to our members based upon the variable costs incurred to generate or purchase that energy. Fuel expense is the primary variable cost. Energy revenue recognized equals the actual variable expenses incurred in any given accounting period. Our member energy revenues fluctuate from period to period based on several factors, including fuel costs, weather and other seasonal factors, load requirements in our members’ service territories, variable operating costs, the availability of electric generation resources, our decisions of whether to dispatch our owned or purchased resources or member-owned resources over which we have dispatch rights, and by members’ decisions of whether to purchase a portion of their hourly energy requirements from our resources or from other suppliers. We do not provide all of our members’ energy requirements. The standard selling price for our energy revenues from non-members is the price mutually agreed upon. We are required under our first mortgage indenture to produce a margins for interest ratio of at least 1.10 for each fiscal year. For 2018 and 2017, our board approved a targeted margins for interest ratio of 1.14 and for years 2018 and 2017, we achieved a margins for interest ratio of 1.14. Historically, our board of directors has approved adjustments to revenue requirements by year end such that revenue in excess of that required to meet the targeted margins for interest ratio is refunded to the members. Given that our capacity revenues are based upon budgeted expenditures and generally recognized and billed to our members in equal monthly installments over the course of the year, we may recognize capacity revenues that exceed our actual fixed costs and targeted margins in any given interim reporting period. At each interim reporting period we assess our projected revenue requirements through year end to determine if a refund to our members of excess consideration is likely. If required, we reduce our capacity revenues and recognize a refund liability to our members. Refund liabilities, if any, are included in accounts payable on our consolidated balance sheets. At December 31, 2018 and 2017, we recognized refund liabilities totaling $30,870,000 and $29,149,000, respectively that were applied to our members’ bills in January 2019. Based on our current agreements with non-members, we do not refund any consideration received from non-members. Sales to members were as follows: (dollars in thousands) 2018 2017 2016 Capacity revenues $ 927,419 $ 912,421 $ 949,193 Energy revenues 551,960 521,409 557,614 Total $ 1,479,379 $ 1,433,830 $ 1,506,807 The following table reflects members whose revenues accounted for 10% or more of our total operating revenues in 2018, 2017 or 2016: 2018 2017 2016 Jackson EMC 14.1 % 14.7 % 14.3 % Cobb EMC 13.9 % 14.3 % 13.7 % Sawnee EMC n/a n/a 10.5 % Sales to non-members during years 2018, 2017 and 2016 were insignificant. Electric capacity and energy revenues are recognized by us without any obligation for returns, warranties or taxes collected. As our members are jointly and severally obligated to pay all expenses associated with owning and operating our power supply business and we perform an on-going assessment of the credit worthiness of non-members, we have not recorded an allowance for doubtful accounts associated with our receivables from members or non-members. We have a rate management program that allows us to expense and recover interest costs on a current basis that would otherwise be deferred or capitalized. The subscribing members of Vogtle Units No. 3 and No. 4 can elect to participate in this program on an annual basis. The Vogtle program allows for the recovery of financing costs associated with the construction of Vogtle Units No. 3 and No. 4 on a current basis. Under this program, amounts billed to participating members in 2018, 2017 and 2016 were $12,229,000, $11,000,000 and $16,096,000, respectively. The cumulative amount billed since inception of the program totaled $66,316,000. In 2018, we began an additional rate management program that allows us to recover future expense on a current basis. Our members made a one-time election to participate in this program, which in general, allows for additional collections over a five-year period with those amounts then applied to billings over the subsequent five-year period. The program is designed primarily as a mechanism to assist our members to manage the rate impacts associated with the commercial operation of the new Vogtle units. Participating members were billed $15,435,000 under this program in 2018. In conjunction with this program, we are applying regulated operations accounting to defer these revenues and related investment income. Amounts deferred under the program will be amortized to income when applied to members’ bills. |
Receivables | f. Receivables A substantial portion of our receivables are related to capacity and energy 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, plus a margin requirement. Receivables from contracts with our members at December 31, 2018, 2017 and 2016 were $122,888,000, $126,211,000 and $136,552,000, respectively. Payment is received the following month in which capacity and energy are billed. Estimated energy charges are billed based on the amount of energy supplied during the month and are adjusted when actual costs are available, generally the following month. The remainder of our receivables is primarily related to transactions with affiliated companies and investment income. Uncollectible amounts, if any, are identified on a specific basis and charged to expense in the period the amounts are determined to be uncollectible. During 2018 and 2017, no impairment losses were recognized on any receivables that arose from contracts with members or non-members. |
Nuclear fuel cost | g. Nuclear fuel cost The cost of nuclear fuel is amortized to fuel expense based on usage. The total nuclear fuel expense for 2018, 2017 and 2016 amounted to $85,949,000, $90,520,000, and $83,751,000, respectively. Contracts with the U.S. Department of Energy have been executed to provide for the permanent disposal of spent nuclear fuel produced at Plants 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. In 2014, the U.S. Court of Federal Claims issued a judgment in favor of Georgia Power, to recover spent nuclear fuel storage costs at Plants Hatch and Vogtle Units No. 1 and No. 2 covering the period of 2005 through 2010. Our ownership share of $10,949,000, was recognized in our 2015 financial statements. Georgia Power filed additional claims in 2014 (as amended) and 2017 seeking damages for spent nuclear fuel storage costs at Plant Hatch and Plant Vogtle Units No. 1 and No. 2 covering the periods from January 1, 2011 through December 31, 2014 and January 1, 2015 through December 31, 2017, respectively. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts were recognized in the financial statements as of December 31, 2018 for these additional claims. 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 | h. 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 2018. The following table reflects the details of the asset retirement obligations included in the consolidated balance sheets for the years 2018 and 2017. (dollars in thousands) Nuclear Coal Ash Other Total Balance at December 31, 2017 $ 548,574 $ 161,755 $ 24,668 $ 734,997 Liabilities settled (1,686) (1,596) (1,398) (4,680) Accretion 32,857 4,238 995 38,090 Change in cash flow estimates 79,211 161,851 8,094 249,156 Balance at December 31, 2018 $ 658,956 $ 326,248 $ 32,359 $ 1,017,563 (dollars in thousands) Nuclear Coal Ash Other Total Balance at December 31, 2016 $ 517,565 $ 156,465 $ 24,021 $ 698,051 Liabilities settled (17) (943) (1,185) (2,145) Accretion 31,026 4,629 1,019 36,674 Change in cash flow estimates — 1,604 813 2,417 Balance at December 31, 2017 $ 548,574 $ 161,755 $ 24,668 $ 734,997 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, but not limited to, changes in the assumed date of decommissioning, changes in regulatory requirements, changes in technology, and changes in costs of labor, materials and equipment. Our most recent assessment of the nuclear asset obligation resulted in a $79,211,000 increase in the obligation for nuclear decommissioning. In projecting future costs, the escalation rate for labor, materials and equipment was assumed to be 2.8% for the Hatch units and 2.7% for Vogtle Units 1 & 2. The increase in the cash flow estimates in 2018 was primarily attributable to general inflation, labor costs, volume of low-level radioactive waste and spent fuel management, among other factors. Our portion of the estimated costs of decommissioning co-owned nuclear facilities were as follows: (dollars in thousands) Hatch Unit Hatch Unit Vogtle Unit Vogtle Unit 2018 site study No. 1 No. 2 No. 1 No. 2 Expected start date of decommissioning 2034 2038 2047 2049 Estimated costs based on site study in 2018 dollars: Radiated structures $ 209,000 $ 231,000 $ 188,000 $ 206,000 Spent fuel management 54,000 49,000 55,000 51,000 Non-radiated structures 14,000 19,000 23,000 29,000 Total estimated site study costs $ 277,000 $ 299,000 $ 266,000 $ 286,000 We have established funds to comply with the Nuclear Regulatory Commission regulations regarding the decommissioning of our nuclear plants. See Note 1i for information regarding the nuclear decommissioning funds. We apply the provision of regulated operations to nuclear decommissioning transactions such that collections and investment income (interest, dividends and realized gains and losses) of our nuclear decommissioning funds are compared to the associated decommissioning expenses with the difference deferred as regulatory asset or liability. As this difference is largely attributable to the timing of decommissioning fund earnings, the difference is recorded as an adjustment to investment income in our consolidated statements of revenues and expenses. Unrealized gains and losses of the decommissioning funds are recorded directly to the regulatory asset or liability for asset retirement obligations in accordance with our ratemaking treatment. Coal Ash. 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. Our most recent assessment of the coal ash asset retirement obligation resulted in a $161,303,000 increase in the obligation 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 2018 increase in cash flow estimates was primarily attributed to the refinement of site specific closure strategies and the associated costs, including water treatment requirements, and the estimated amount of coal ash to be consolidated. Additional adjustments to the asset retirement obligations are expected periodically due to potential changes in estimates and assumptions. We have internally segregated the funds collected for coal ash pond and landfill decommissioning costs, including earnings thereon. As of December 31, 2018 and December 31, 2017 the fund balances were $60,599,000 and $41,844,000, respectively We apply the provision of regulated operations to coal ash pond and landfill decommissioning transactions such that collections and investment income (interest, dividends and realized gains and losses, if any) are compared to the associated decommissioning expenses with the difference deferred as a regulatory asset. As this difference is attributable to the associated expenses being greater than amounts collected through rates, this difference is recorded as a deferral of expense in our consolidated statements of revenues and expenses. Unrealized gains and losses, if any, of the associated decommissioning fund are recorded directly to the regulatory asset in accordance with our ratemaking treatment. Other. 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 1q. |
Nuclear decommissioning funds | i. 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 2018 and 2017, 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. We record the investment securities held in the nuclear decommissioning trust fund 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. The funds are included in long-term investments on our consolidated balance sheet. In both 2018 and 2017, we contributed $4,750,000 into the internal funds. The following table outlines the fair value of our nuclear decommissioning funds as of December 31, 2018 and December 31, 2017. The funds are invested in a diversified mix of approximately 60% equity and 40% fixed income securities for both 2018 and 2017. 2018 External Trust Funds: Cost Net Unrealized Fair Value 12/31/2017 Purchases Proceeds (1) Gain(Loss) 12/31/2018 Equity $ 203,622 $ 12,186 $ (7,789) $ 49,475 $ 257,494 Debt 164,901 445,353 (443,712) (2,108) 164,434 Other 141 370 (1,621) — (1,110) $ 368,664 $ 457,909 $ (453,122) $ 47,367 $ 420,818 (1) Also included in net proceeds are net realized gains or losses, interest income, dividends, contributions and fees of $4,786,000. 2018 Internal Funds: Cost Net Unrealized Fair Value 12/31/2017 Purchases Proceeds (1) Gain(Loss) 12/31/2018 Equity $ 43,698 $ — $ 596 $ 6,373 $ 50,667 Debt 33,540 161,454 (156,611) (246) 38,137 $ 77,238 $ 161,454 $ (156,015) $ 6,127 $ 88,804 (1) Also included in net proceeds are net realized gains or losses, interest income, dividends, contributions and fees of $689,000. 2017 External Trust Funds: Cost Net Unrealized Fair Value 12/31/2016 Purchases Proceeds (1) Gain(Loss) 12/31/2017 Equity $ 200,595 $ 61,406 $ (44,607) $ 76,221 $ 293,615 Debt 148,011 388,609 (384,199) 170 152,591 Other 351 98 (1,600) — (1,151) $ 348,957 $ 450,113 $ (430,406) $ 76,391 $ 445,055 (1) Also included in net proceeds are net realized gains or losses, interest income, dividends, contributions and fees of $19,707,000. 2017 Internal Funds: Cost Net Unrealized Fair Value 12/31/2016 Purchases Proceeds (1) Gain(Loss) 12/31/2017 Equity $ 38,798 $ — $ 4,900 $ 11,669 $ 55,367 Debt 26,207 73,153 (65,820) — 33,540 $ 65,005 $ 73,153 $ (60,920) $ 11,669 $ 88,907 (1) Also included in net proceeds are net realized gains or losses, interest income, dividends, contributions and fees of $12,232,800. Realized and unrealized gains and losses of the nuclear decommissioning funds that would be recorded in earnings 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. The nuclear decommissioning trust fund has produced an average annualized return of approximately 7.7% in the last ten years and 5.8% since inception in 1990. 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 above assumption, our management believes that increases in cost estimates of decommissioning can be recovered in future rates. |
Depreciation | j. 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 depreciation rate studies completed in 2015. Site specific depreciation studies are performed every five years. Annual weighted average depreciation rates in effect in 2018, 2017 and 2016 were as follows: Range of Useful Life in years* 2018 2017 2016 Steam production 49-65 2.57 % 2.91 % % Nuclear production 37-60 1.92 % 1.96 % % Hydro production 50 2.00 % % % Other production 30-35 2.61 % 2.58 % % Transmission 36 2.75 % 2.75 % % General 3-50 2.00-33.33 % 2.00-33.33 % 2.00-33.33 % * Depreciation expense for the years 2018, 2017 and 2016 was $227,213,000, $218,027,000, and $211,282,000, respectively. |
Electric plant | k. Electric plant Electric plant is stated at original cost, which is the cost of the plant when first dedicated to public service, including acquisition adjustments, if any, 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 2018, 2017 and 2016, the allowance for funds used during construction rates were 4.25%, 4.45% and 4.61%, 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 is charged to the accumulated provision for depreciation. Cost of removal, less salvage, is charged to a regulatory liability, accumulated retirement costs for other assets. 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 | l. 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 investments | m. Restricted investments Restricted investments consist of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account. We can only utilize these investments for future Rural Utilities Service-guaranteed Federal Financing Bank debt service payments. The funds currently earn interest at a rate of 5% per annum. As of October 1, 2020, deposits will earn interest at 4% per annum and beginning October 1, 2021, the rates will be set at the 1-year floating treasury rate. The program no longer allows additional funds to be deposited into the account. At December 31, 2018 and 2017, we had restricted investments totaling $653,158,000 and $882,909,000, respectively, of which $503,158,000 and $653,585,000, respectively, were classified as long-term. The funds on deposit with the Rural Utilities Service in the Cushion of Credit Account are held by the U.S. Treasury, acting through the Federal Financing Bank. |
Inventories | n. 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. 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. 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 December 31, 2018 and December 31, 2017, fossil fuels inventories were $48,709,000 and $54,050,000, respectively. Inventories for spare parts at 2018 and 2017 were $210,379,000 and $212,169,000, respectively. |
Deferred charges and other assets | o. Deferred charges and other assets Other deferred charges primarily represent advance deposits to Georgia Power Company related to the Vogtle construction project and progress payments for equipment associated with future nuclear refueling outages. For a discussion regarding regulatory assets, see Note 1q. |
Deferred credits and other liabilities | p. 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 January 2023, with the majority of the balance scheduled to be credited by the end of 2019. Deferred credits and other liabilities also consists of asset retirement obligations as discussed in Note 1h and regulatory liabilities in Note 1q. |
Regulatory assets and liabilities | q. 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 established under the wholesale power contracts we have with each of our members. These contracts 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. 2018 2017 (dollars in thousands) Regulatory Assets: Premium and loss on reacquired debt (a) $ 46,315 $ 52,989 Amortization on capital leases (b) 34,918 33,846 Outage costs (c) 36,352 40,525 Asset retirement obligations – Ashpond and other (k) 137,835 68,289 Asset retirement obligations – Nuclear (k) 7,031 0 Depreciation expense (d) 41,244 42,667 Deferred charges related to Vogtle Units No. 3 and No. 4 training costs (e) 51,549 48,702 Interest rate options cost (f) 116,960 112,102 Deferral of effects on net margin – Smith Energy Facility (g) 160,509 166,454 Other regulatory assets (m) 22,350 19,510 Total Regulatory Assets $ 655,063 $ 585,084 Regulatory Liabilities: Accumulated retirement costs for other obligations (h) $ 13,873 $ 12,813 Deferral of effects on net margin – Hawk Road Energy Facility (g) 19,101 19,553 Major maintenance reserve (i) 45,547 47,087 Amortization on capital leases (b) 17,156 20,055 Deferred debt service adder (j) 105,192 95,695 Asset retirement obligations – Nuclear (k) 0 53,571 Revenue deferral plan (l) 15,670 0 Other regulatory liabilities (m) 2,459 2,875 Total Regulatory Liabilities $ 218,998 $ 251,649 Net regulatory assets $ 436,065 $ 333,435 (a) Represents premiums paid, together with unamortized transaction costs related to reacquired debt that are being amortized over the lives of the refunding debt, which range up to 25 years. (b) Represents the difference between expense recognized for rate-making purposes versus financial statement purposes related to 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 periods up to 48 months, depending on the operating cycle of each unit. Nuclear refueling outage costs are amortized on a straight‑line basis to expense over the 18 or 24 -month operating cycles of each unit. (d) Prior to Nuclear Regulatory Commission (NRC) approval of a 20 -year license extension for Plant Vogtle, 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. (e) Deferred charges consist of training related costs, including interest and carrying costs of such training. Amortization will commence effective with the commercial operation date of each unit and amortized to expense over the life of the units. (f) Deferral of premiums paid to purchase interest rate options used to hedge interest rates on certain borrowings, related carrying costs and other incidentals associated with construction of Vogtle Units No. 3 and No. 4. Amortization will commence in February 2020 and continue through February 2044, the life of the DOE-guaranteed loan which is financing a portion of the construction project. (g) Effects on net margin for Smith and Hawk Road Energy Facilities were deferred through the end of 2015 and are being amortized over the remaining life of each respective plant. (h) Represents the accrual of retirement costs associated with long-lived assets for which there are no legal obligations to retire the assets. (i) Represents collections for future major maintenance costs; revenues are recognized as major maintenance costs are incurred. (j) Represents collections to fund certain debt payments to be made through the end of 2025 which will be in excess of amounts collected through depreciation expense; the deferred credits will be amortized over the remaining useful life of the plants. (k) Represents the difference in the timing of recognition of decommissioning costs for financial statement purposes versus ratemaking purposes, as well as the deferral of unrealized gains and losses of funds set aside for decommissioning. (l) Deferred revenues under a rate management program that allows for additional collections over a five-year period beginning in 2018. These amounts will be amortized to income and applied to member billings over the subsequent five-year period. (m) The amortization periods for other regulatory assets range up to 31 years and the amortization periods of other regulatory liabilities range up to 8 years. |
Related parties | r. 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 owned facilities. For 2018, 2017, and 2016, we incurred expenses from Georgia Transmission of $30,428,000, $28,410,000, and $27,399,000, 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 2018, 2017, and 2016, we incurred expenses from Georgia Systems Operations of $25,578,000, $25,597,000, and $23,994,000, respectively. |
Other income | s. Other income Other income includes net revenue from Georgia Transmission and Georgia Systems Operations for administrative costs, as well as capital credits from investments in associated organizations and other miscellaneous income. |
Recently issued or adopted accounting pronouncements | t. Recently issued or adopted 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. In addition, Topic 606 requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. We adopted the new revenue standard effective January 1, 2018, using the full retrospective method, which requires us to restate each prior reporting period presented. The most significant impact of the new revenue standard to us relates to the potential recognition of refund liabilities in interim reporting periods. The adoption of the new revenue standard did not change the nature, amounts or timing of revenues we recognize within an annual reporting period and, therefore, restatement of the annual periods was not required. Refund liabilities, if any, are included in accounts payable on our consolidated balance sheets. For years 2018 and 2017, we recognized refund liabilities totaling $30,870,000 and $29,149,000, respectively. Adoption of the new revenue standard had no impact to cash from or used in operating, financing, or investing on our consolidated cash flows statements. In January 2016, the FASB issued "Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities." The amendments in this update address certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. The new standard is effective for us for annual reporting periods beginning after December 15, 2017, and interim periods therein. Certain provisions within this update can be adopted early. Certain provisions within this update should be applied by means of a cumulative effect adjustment to the balance sheet of the fiscal year of adoption and certain provisions should be applied prospectively. One of the provisions in this standard requires our equity investments, except those accounted for under the equity method of accounting or those that result in consolidation of our subsidiary, to be measured at fair value with changes in fair value recognized in net margin. None of the other provisions in this standard will have any impact to our consolidated financial statements. As disclosed within Note 1i, we previously adopted regulatory accounting treatment with respect to unrealized gains and losses on our debt and equity securities within our nuclear decommissioning funds. During the fourth quarter of 2017, we adopted regulatory accounting treatment with respect to unrealized gains and losses on all other equity investments. Upon applying regulatory accounting treatment, unrealized gains on our equity investments are recorded as a regulatory liability and, conversely, unrealized losses on our equity investments are recorded as a regulatory asset, at the end of each reporting period. As of December 31, 2018 and December 31, 2017, we recorded, excluding our regulatory accounting treatment related to our nuclear decommissioning funds, $975,000 and $618,000, respectively, of unrealized losses on our equity investments as a regulatory asset. On January 1, 2018, we adopted the amendments within this standard. The adoption of this standard did not have any impact to our consolidated financial statements due to our regulatory accounting treatment for unrealized gains and/or losses on our equity investments. 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. Quantitative and qualitative disclosures will also be required surrounding significant judgments made by management. The new lease standard does not substantially change lessor accounting. The new leases standard is effective for us on a modified retrospective approach for annual reporting periods beginning after December 15, 2018, and interim periods therein. Early adoption is permitted. During 2018, the FASB issued additional guidance related to the new leases standard, including a practical expedient that allows entities to not evaluate existing and expired land easements that were not previously accounted for as leases upon adoption of Topic 842 and an additional transition method that allows entities to not apply the new leases guidance in the comparative periods entities present in their financial statements in the year of adoption. We have fully completed our implementation of the new leases standard and the adoption of the standard did not have a material impact on our consolidated financial statements. We have a relatively small portfolio of leases with the most significant being our 60% undivided interest in Scherer Unit No. 2 and railcar leases for the transportation of coal. We also have a minor number of various nominal leases. We account for the Scherer Unit No. 2 leases as capital leases and the railcar leases as operating leases under the current lease accounting model. The key changes in our adoption of the new leases standard is how we account for our operating leases that are currently off-balance sheet. Our evaluation process included, but was not limited to, reviewing all forms of leases, performing a completeness assessment over the lease population and analyzing the practical expedients available to us. On January 1, 2019, we adopted the new leases standard using the optional transition method to apply the new lease guidance as of January 1, 2019, rather than as of the earliest period presented. Upon adoption of the new leases standard, we recognized right-of-use assets and offsetting lease liabilities totaling approximately $6,983,000. In June 2016, the FASB issued "Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments." The amendments in this update replace the current incurred loss impairment methodology with a methodology that reflects expected credit losses. The new standard is effective for us prospectively for annual reporting periods beginning after December 15, 2019, and interim periods therein. The amendments in this update can be adopted earlier as of the fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted. We are currently evaluating the future impact of this standard on our consolidated financial statements. In March 2018, the FASB issued “Income Taxes (Topic 740): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118.” In accordance with the standard, we recognized the provisional tax impacts related to the re-measurement of our deferred income tax assets and liabilities as of the year ended December 31, 2017. During the year ended December 31, 2018, we finalized our Staff Accounting Bulletin 118 analysis and there was no impact to the results of operations. In August 2018, the FASB issued “Fair Value Measurement (Topic 820): Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurement.” This standard eliminates, adds and modifies certain disclosure requirements for fair value measurements as part of the FASB’s disclosure framework project. Entities will no longer be required to disclose the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, the policy for timing of transfers between levels and the valuation processes for Level 3 fair value measurements. However, public business entities will be required to disclose the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. The amendments in this update are effective for all entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. An entity is permitted to early adopt any removed or modified disclosures upon issuance of this update and delay adoption of the additional disclosures until their effective date. As the standard relates only to disclosures, we do not expect the adoption of this standard to have a material impact on our consolidated financial statements. We are currently evaluating the standard and whether we will early adopt the standard. |
Summary of significant accoun_3
Summary of significant accounting policies: (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Summary of significant accounting policies: | |
Schedule of sales to members | (dollars in thousands) 2018 2017 2016 Capacity revenues $ 927,419 $ 912,421 $ 949,193 Energy revenues 551,960 521,409 557,614 Total $ 1,479,379 $ 1,433,830 $ 1,506,807 |
Schedule of members whose revenues accounted for 10% or more of total operating revenues | 2018 2017 2016 Jackson EMC 14.1 % 14.7 % 14.3 % Cobb EMC 13.9 % 14.3 % 13.7 % Sawnee EMC n/a n/a 10.5 % |
Schedule reflecting details of asset retirement obligations included in the consolidated balance sheets | (dollars in thousands) Nuclear Coal Ash Other Total Balance at December 31, 2017 $ 548,574 $ 161,755 $ 24,668 $ 734,997 Liabilities settled (1,686) (1,596) (1,398) (4,680) Accretion 32,857 4,238 995 38,090 Change in cash flow estimates 79,211 161,851 8,094 249,156 Balance at December 31, 2018 $ 658,956 $ 326,248 $ 32,359 $ 1,017,563 (dollars in thousands) Nuclear Coal Ash Other Total Balance at December 31, 2016 $ 517,565 $ 156,465 $ 24,021 $ 698,051 Liabilities settled (17) (943) (1,185) (2,145) Accretion 31,026 4,629 1,019 36,674 Change in cash flow estimates — 1,604 813 2,417 Balance at December 31, 2017 $ 548,574 $ 161,755 $ 24,668 $ 734,997 |
Schedule of estimated costs of decommissioning of co-owned nuclear facilities | (dollars in thousands) Hatch Unit Hatch Unit Vogtle Unit Vogtle Unit 2018 site study No. 1 No. 2 No. 1 No. 2 Expected start date of decommissioning 2034 2038 2047 2049 Estimated costs based on site study in 2018 dollars: Radiated structures $ 209,000 $ 231,000 $ 188,000 $ 206,000 Spent fuel management 54,000 49,000 55,000 51,000 Non-radiated structures 14,000 19,000 23,000 29,000 Total estimated site study costs $ 277,000 $ 299,000 $ 266,000 $ 286,000 |
Schedule of external and internal trust funds by type of investment | 2018 External Trust Funds: Cost Net Unrealized Fair Value 12/31/2017 Purchases Proceeds (1) Gain(Loss) 12/31/2018 Equity $ 203,622 $ 12,186 $ (7,789) $ 49,475 $ 257,494 Debt 164,901 445,353 (443,712) (2,108) 164,434 Other 141 370 (1,621) — (1,110) $ 368,664 $ 457,909 $ (453,122) $ 47,367 $ 420,818 (1) Also included in net proceeds are net realized gains or losses, interest income, dividends, contributions and fees of $4,786,000. 2018 Internal Funds: Cost Net Unrealized Fair Value 12/31/2017 Purchases Proceeds (1) Gain(Loss) 12/31/2018 Equity $ 43,698 $ — $ 596 $ 6,373 $ 50,667 Debt 33,540 161,454 (156,611) (246) 38,137 $ 77,238 $ 161,454 $ (156,015) $ 6,127 $ 88,804 (1) Also included in net proceeds are net realized gains or losses, interest income, dividends, contributions and fees of $689,000. 2017 External Trust Funds: Cost Net Unrealized Fair Value 12/31/2016 Purchases Proceeds (1) Gain(Loss) 12/31/2017 Equity $ 200,595 $ 61,406 $ (44,607) $ 76,221 $ 293,615 Debt 148,011 388,609 (384,199) 170 152,591 Other 351 98 (1,600) — (1,151) $ 348,957 $ 450,113 $ (430,406) $ 76,391 $ 445,055 (1) Also included in net proceeds are net realized gains or losses, interest income, dividends, contributions and fees of $19,707,000. 2017 Internal Funds: Cost Net Unrealized Fair Value 12/31/2016 Purchases Proceeds (1) Gain(Loss) 12/31/2017 Equity $ 38,798 $ — $ 4,900 $ 11,669 $ 55,367 Debt 26,207 73,153 (65,820) — 33,540 $ 65,005 $ 73,153 $ (60,920) $ 11,669 $ 88,907 (1) Also included in net proceeds are net realized gains or losses, interest income, dividends, contributions and fees of $12,232,800. |
Schedule of annual depreciation rates | Range of Useful Life in years* 2018 2017 2016 Steam production 49-65 2.57 % 2.91 % % Nuclear production 37-60 1.92 % 1.96 % % Hydro production 50 2.00 % % % Other production 30-35 2.61 % 2.58 % % Transmission 36 2.75 % 2.75 % % General 3-50 2.00-33.33 % 2.00-33.33 % 2.00-33.33 % * |
Schedule of regulatory assets and liabilities | 2018 2017 (dollars in thousands) Regulatory Assets: Premium and loss on reacquired debt (a) $ 46,315 $ 52,989 Amortization on capital leases (b) 34,918 33,846 Outage costs (c) 36,352 40,525 Asset retirement obligations – Ashpond and other (k) 137,835 68,289 Asset retirement obligations – Nuclear (k) 7,031 0 Depreciation expense (d) 41,244 42,667 Deferred charges related to Vogtle Units No. 3 and No. 4 training costs (e) 51,549 48,702 Interest rate options cost (f) 116,960 112,102 Deferral of effects on net margin – Smith Energy Facility (g) 160,509 166,454 Other regulatory assets (m) 22,350 19,510 Total Regulatory Assets $ 655,063 $ 585,084 Regulatory Liabilities: Accumulated retirement costs for other obligations (h) $ 13,873 $ 12,813 Deferral of effects on net margin – Hawk Road Energy Facility (g) 19,101 19,553 Major maintenance reserve (i) 45,547 47,087 Amortization on capital leases (b) 17,156 20,055 Deferred debt service adder (j) 105,192 95,695 Asset retirement obligations – Nuclear (k) 0 53,571 Revenue deferral plan (l) 15,670 0 Other regulatory liabilities (m) 2,459 2,875 Total Regulatory Liabilities $ 218,998 $ 251,649 Net regulatory assets $ 436,065 $ 333,435 (a) Represents premiums paid, together with unamortized transaction costs related to reacquired debt that are being amortized over the lives of the refunding debt, which range up to 25 years. (b) Represents the difference between expense recognized for rate-making purposes versus financial statement purposes related to 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 periods up to 48 months, depending on the operating cycle of each unit. Nuclear refueling outage costs are amortized on a straight‑line basis to expense over the 18 or 24 -month operating cycles of each unit. (d) Prior to Nuclear Regulatory Commission (NRC) approval of a 20 -year license extension for Plant Vogtle, 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. (e) Deferred charges consist of training related costs, including interest and carrying costs of such training. Amortization will commence effective with the commercial operation date of each unit and amortized to expense over the life of the units. (f) Deferral of premiums paid to purchase interest rate options used to hedge interest rates on certain borrowings, related carrying costs and other incidentals associated with construction of Vogtle Units No. 3 and No. 4. Amortization will commence in February 2020 and continue through February 2044, the life of the DOE-guaranteed loan which is financing a portion of the construction project. (g) Effects on net margin for Smith and Hawk Road Energy Facilities were deferred through the end of 2015 and are being amortized over the remaining life of each respective plant. (h) Represents the accrual of retirement costs associated with long-lived assets for which there are no legal obligations to retire the assets. (i) Represents collections for future major maintenance costs; revenues are recognized as major maintenance costs are incurred. (j) Represents collections to fund certain debt payments to be made through the end of 2025 which will be in excess of amounts collected through depreciation expense; the deferred credits will be amortized over the remaining useful life of the plants. (k) Represents the difference in the timing of recognition of decommissioning costs for financial statement purposes versus ratemaking purposes, as well as the deferral of unrealized gains and losses of funds set aside for decommissioning. (l) Deferred revenues under a rate management program that allows for additional collections over a five-year period beginning in 2018. These amounts will be amortized to income and applied to member billings over the subsequent five-year period. (m) The amortization periods for other regulatory assets range up to 31 years and the amortization periods of other regulatory liabilities range up to 8 years. |
Fair Value_ (Tables)
Fair Value: (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Fair Value: | |
Schedule of assets and liabilities measured at fair value on a recurring basis | Fair Value Measurements at Reporting Date Using Quoted Prices in Significant Other Significant Active Markets for Observable Unobservable Identical Assets Inputs Inputs December 31, 2018 (Level 1) (Level 2) (Level 3) (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ 136,196 $ 136,196 $ — $ — International equity trust $ 76,852 — 76,852 — Corporate bonds and debt $ 51,356 — 48,853 2,503 US Treasury securities $ 47,712 47,712 — — Mortgage backed securities $ 56,004 — 56,004 — Domestic mutual funds $ 43,359 43,359 — Municipal bonds $ 278 — 278 — Federal agency securities $ 6,066 — 6,066 — Other $ 2,995 2,031 964 — Long-term investments: International equity trust $ 17,382 — 17,382 — Corporate bonds and debt $ 12,571 — 11,366 1,205 US Treasury securities $ 12,062 12,062 — — Mortgage backed securities $ 11,517 — 11,517 — Domestic mutual funds $ 94,494 94,494 — — Federal agency securities $ 941 — 941 — Treasury STRIPS $ 14,113 — 14,113 — Other $ 1,045 1,045 — — Natural gas swaps $ 13,154 — 13,154 — Fair Value Measurements at Reporting Date Using Quoted Prices in Significant Other Significant Active Markets for Observable Unobservable Identical Assets Inputs Inputs December 31, 2017 (Level 1) (Level 2) (Level 3) (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ 142,419 $ 142,419 $ — $ — International equity trust $ 88,820 — 88,820 — Corporate bonds and debt $ 66,317 — 66,317 — US Treasury securities $ 38,791 38,791 — — Mortgage backed securities $ 49,379 — 49,379 — Domestic mutual funds $ 47,833 47,833 — — Municipal bonds $ 92 — 92 — Federal agency securities $ 3,725 — 3,725 — Other $ 7,679 7,679 — — Long-term investments: International equity trust $ 20,071 — 20,071 — Corporate bonds and debt $ 16,215 — 16,215 — US Treasury securities $ 6,670 6,670 — — Mortgage backed securities $ 7,267 — 7,267 — Domestic mutual funds $ 87,011 87,011 — — Federal agency securities $ 259 — 259 — Other $ 3,129 3,129 — — Natural gas swaps $ 6,328 — 6,328 — |
Schedule of changes in Level 3 assets measured at fair value on a recurring basis | Year Ended December 31, 2018 (dollars in thousands) Balance at December 31, 2017 $ — Transfers to Level 3 4,997 Total gains or losses (realized/unrealized): Changes in net assets (1,289) Balance at December 31, 2018 $ 3,708 |
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, 2018 and 2017 were as follows (in thousands): 2018 2017 Carrying Fair Carrying Fair Value Value Value Value Long-term debt $ 9,347,307 $ 9,837,254 $ 8,232,703 $ 9,155,942 |
Derivative instruments_ (Tables
Derivative instruments: (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Derivative instruments: | |
Schedule of notional volume of natural gas derivatives that is expected to settle or mature each year | Natural Gas Swaps Year (MMBTUs) (in millions) 2019 23.4 2020 22.1 2021 19.6 2022 12.6 2023 9.5 Total 87.2 |
Schedule of fair value of derivative instruments and effect on consolidated balance sheets | Balance Sheet Location Fair Value 2018 2017 (dollars in thousands) Assets Natural gas swaps Other current assets $ 226 412 Liabilities Natural gas swaps Other current liabilities $ 2,066 $ 1,575 Natural gas swaps Other deferred credits $ 11,314 $ 5,165 |
Schedule of the realized gains and (losses) on derivative instruments recognized in margin | Consolidated Statement of Revenues and Expenses Location 2018 2017 2016 (dollars in thousands) Natural Gas Swaps Fuel $ 6,088 $ 3,818 $ 2,445 Natural Gas Swaps Fuel (956) (1,677) (19,697) Total $ 5,132 $ 2,141 $ (17,252) |
Schedule of unrealized gains and (losses) on derivative instruments deferred on the balance sheet | Consolidated Balance Sheet Location 2018 2017 (dollars in thousands) Natural Gas Swaps Regulatory asset $ 13,154 $ 6,328 Total $ 13,154 $ 6,328 |
Investments_ (Tables)
Investments: (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Investments: | |
Summary of debt and equity securities | (dollars in thousands) Gross Unrealized 2018 Cost Gains Losses Fair Value Equity $ 251,226 $ 64,954 $ (9,105) $ 307,075 Debt 278,030 1,718 (4,955) 274,793 Other 3,075 — — 3,075 Total $ 532,331 $ 66,672 $ (14,060) $ 584,943 (dollars in thousands) Gross Unrealized 2017 Cost Gains Losses Fair Value Equity $ 246,549 $ 91,954 $ (4,064) $ 334,439 Debt 240,878 1,814 (2,262) 240,430 Other 10,807 1 — 10,808 Total $ 498,234 $ 93,769 $ (6,326) $ 585,677 |
Schedule of contractual maturities of debt securities | (dollars in thousands) 2018 2017 Cost Fair Value Cost Fair Value Due within one year $ 65,039 $ 63,925 $ 54,785 $ 54,143 Due after one year through five years 62,293 61,924 53,050 52,834 Due after five years through ten years 50,606 49,855 51,367 51,600 Due after ten years 100,092 99,089 81,676 81,853 Total $ 278,030 $ 274,793 $ 240,878 $ 240,430 |
Summary of realized gains and losses and proceeds from sales of securities | (dollars in thousands) 2018 2017 2016 Gross realized gains $ 14,268 $ 35,523 $ 19,934 Gross realized losses (19,139) (16,909) (20,030) Proceeds from sales 626,612 521,345 439,540 |
Schedule of investments in associated companies | (dollars in thousands) 2018 2017 National Rural Utilities Cooperative Finance Corporation (CFC) $ 24,061 $ 24,056 CT Parts, LLC 10,236 10,243 Georgia Transmission Corporation 30,237 28,690 Georgia System Operations Corporation 9,250 8,500 Other 3,253 3,492 Total $ 77,037 $ 74,981 |
Income taxes_ (Tables)
Income taxes: (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Income taxes: | |
Summary of difference between statutory federal income tax rate on income before income taxes and effective income tax rate | 2018 2017 2016 Statutory federal income tax rate 21.0 % 35.0 % 35.0 % Patronage exclusion (20.8) % (34.1) % (34.7) % AMT credit monetization % 2.2 % 0.0 % Other (0.2) % (0.9) % (0.3) % Effective income tax rate % (2.2) % 0.0 % |
Schedule of components of net deferred tax assets and liabilities | (dollars in thousands) 2018 2017 Deferred tax assets Net operating losses $ 3,830 $ 19,668 Tax credits (alternative minimum tax and other) — — Accounting for Rocky Mountain transactions 231,543 231,268 Advance payments 46,708 — Other assets 82,655 75,013 Deferred tax assets 364,736 325,949 Less: Valuation allowance (3,830) (19,668) Net deferred tax assets $ 360,906 $ 306,281 Deferred tax liabilities Depreciation $ 268,039 $ 271,652 Accounting for Rocky Mountain transactions 116,226 114,514 Other liabilities 75,691 78,407 Deferred tax liabilities 459,956 464,573 Net deferred tax liabilities 99,050 158,292 Less: Patronage exclusion (99,050) (158,292) Net deferred taxes $ — $ — |
Schedule of federal tax net operating loss carryforwards and alternative minimum tax credits | As of December 31, 2018, we have federal tax net operating loss carryforwards and alternative minimum tax credits as follows: (dollars in thousands) Alternative Minimum Expiration Date Tax Credits NOLs 2019 — 10,516 2020 — 4,362 $ — $ 14,878 |
Capital leases_ (Tables)
Capital leases: (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
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, 2018 are as follows: (dollars in Year Ending December 31, thousands) 2019 $ 14,949 2020 14,949 2021 14,949 2022 7,474 2023 22,424 2024-2031 70,483 Total minimum lease payments $ 145,228 Less: Amount representing interest (58,036) Present value of net minimum lease payments $ 87,192 Less: Current portion (5,462) Long-term balance $ 81,730 |
Debt_ (Tables)
Debt: (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Debt: | |
Schedule of maturities for long-term debt and capital lease obligations | (dollars in thousands) 2019 2020 2021 2022 2023 FFB $ 164,782 $ 180,107 $ 185,476 $ 189,176 $ 195,483 FMBs 351,010 1,010 1,010 1,010 1,010 PCBs (1) — 133,550 93,379 18,676 — CFC 1,035 391 — — — $ 516,827 $ 315,058 $ 279,865 $ 208,862 $ 196,493 Capital Leases 5,462 6,082 6,772 7,541 8,398 Total $ 522,289 $ 321,140 $ 286,637 $ 216,403 $ 204,891 (1) In addition to regularly scheduled principal payments included are amounts that would be due if the letters of credit supporting the Series 2009 and Series 2010 bonds were drawn upon and became payable in accordance with their terms, such as would occur if the credit facility the letters of credit were issued under was not renewed or extended at its expiration date. These amounts equal $133.6 million in 2020, $93.4 million in 2021 and $18.7 million in 2022. 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. |
Schedule of long-term debt outstanding and the associated unamortized debt issuance costs and debt discounts | 2018 2017 Unamortized Debt Unamortized Debt Issuance Costs and Issuance Costs and Principal Debt Discounts Principal Debt Discounts (dollars in thousands) FFB $ 4,372,422 $ 50,210 $ 4,192,450 $ 51,593 FMBs 3,556,062 41,509 3,057,072 34,673 PCBs 980,770 11,612 980,770 9,347 CFC 1,426 — 2,411 — $ 8,910,680 $ 103,331 $ 8,232,703 $ 95,613 |
Electric plant, construction _2
Electric plant, construction and related agreements: (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Electric plant, construction and related agreements: | |
Summary of plant investments and related accumulated depreciation | 2018 2017 (dollars in thousands) Accumulated Accumulated Plant Investment Depreciation Investment Depreciation In-service (1) Owned property Vogtle Units No. 1 & No. 2 (Nuclear – 30% ownership) $ 2,975,727 $ (1,775,569) $ 2,916,852 $ (1,751,558) Vogtle Units No. 3 & No. 4 (Nuclear – 30% ownership) 55,861 (3,479) 36,745 (2,514) Hatch Units No. 1 & No. 2 (Nuclear – 30% ownership) 910,259 (441,240) 824,890 (420,000) Wansley Units No. 1 & No. 2 (Fossil – 30% ownership) 655,618 (311,606) 587,436 (236,155) Scherer Unit No. 1 (Fossil – 60% ownership) 1,222,538 (442,840) 1,102,085 (399,774) Doyle (Combustion Turbine – 100% ownership) 137,133 (109,509) 136,351 (106,370) Rocky Mountain Units No. 1, No. 2 & No. 3 (Hydro – 75% ownership) 618,621 (258,359) 609,048 (246,758) Hartwell (Combustion Turbine – 100% ownership) 226,156 (105,540) 225,808 (104,269) Hawk Road (Combustion Turbine – 100% ownership) 254,925 (75,308) 251,671 (73,998) Talbot (Combustion Turbine – 100% ownership) 293,638 (136,007) 292,250 (128,344) Chattahoochee (Combined cycle – 100% ownership) 315,463 (141,279) 313,587 (133,378) Smith (Combined cycle – 100% ownership) 648,464 (179,486) 642,732 (170,366) Wansley (Combustion Turbine – 30% ownership) 3,887 (3,626) 3,887 (3,552) Transmission plant 95,861 (56,973) 92,929 (55,502) Other 93,503 (56,193) 92,179 (54,927) Property under capital lease: Scherer Unit No. 2 (Fossil – 60% leasehold) 776,316 (447,391) 757,957 (414,867) Total in-service $ 9,283,970 $ (4,544,405) $ 8,886,407 $ (4,302,332) Construction work in progress Vogtle Units No. 3 & No. 4 (2) $ 3,600,631 $ 2,721,949 Environmental and other generation improvements 263,146 212,476 Other 2,265 1,443 Total construction work in progress $ 3,866,042 $ 2,935,868 (1) Amounts include plant acquisition adjustments at December 31, 2018 and 2017 of $197,000,000. (2) The 2017 amount is net of a $1,104,000,000 credit recorded as a result of payments received from Toshiba under the Guarantee Settlement Agreement as described in Note 8b. |
Commitments_ (Tables)
Commitments: (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Commitments: | |
Schedule of estimated minimum rental commitments | As of December 31, 2018, our estimated minimum rental commitments are as follows: (dollars in thousands) 2019 $ 3,730 2020 1,413 2021 798 2022 608 2023 386 Thereafter 1,157 |
Schedule of estimated minimum long-term commitments | As of December 31, 2018, our estimated commitments are as follows: (dollars in thousands) Gas Maintenance Asset Retirement Coal Nuclear Fuel Transportation Agreements Obligations 2019 $ 22,065 $ 49,100 $ 64,497 $ 29,510 $ 8,664 2020 7,091 27,500 63,260 53,911 11,274 2021 2,348 30,300 62,737 14,461 11,215 2022 — 25,400 53,796 14,929 11,200 2023 — 18,400 47,513 3,330 37,743 Thereafter — 35,100 848,609 281,938 3,536,362 |
Quarterly financial data (una_2
Quarterly financial data (unaudited): (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Quarterly financial data (unaudited): | |
Summary of quarterly financial information | First Second Third Fourth Quarter Quarter Quarter Quarter (dollars in thousands) 2018 Operating revenues $ 373,646 $ 365,921 $ 384,644 $ 355,902 Operating margin 69,931 60,849 54,845 39,351 Net margin 27,400 17,285 11,334 (4,820) 2017 Operating revenues $ 354,170 $ 361,369 $ 376,656 $ 342,001 Operating margin 69,330 63,472 59,520 46,548 Net margin 21,454 15,676 11,555 2,592 |
Summary of significant accoun_4
Summary of significant accounting policies: - Business Description (Details) | 12 Months Ended |
Dec. 31, 2018itemMW | |
Business description | |
Number of electric distribution cooperative members | item | 38 |
Summer planning reserve capacity of generating units (in megawatts) | 7,060 |
Number of people to whom energy is distributed on a retail basis by the entity's members | item | 4,100,000 |
Smarr EMC | |
Business description | |
Summer planning reserve capacity of generating units (in megawatts) | 731 |
Green Power EMC | |
Business description | |
Summer planning reserve capacity of generating units (in megawatts) | 120 |
Green Power EMC | Solar energy | |
Business description | |
Summer planning reserve capacity of generating units (in megawatts) | 87 |
Summary of significant accoun_5
Summary of significant accounting policies: - Patronage capital and membership fees and Margin policy (Details) | 12 Months Ended | ||
Dec. 31, 2018USD ($) | Dec. 31, 2017 | Dec. 31, 2016 | |
Patronage capital and membership fees | |||
Membership fees | $ 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% | ||
Margin policy | |||
Minimum margins for interest ratio under the first mortgage indenture | 1.10 | 1.10 | 1.10 |
Achieved margins for interest ratio | 1.14 | 1.14 | 1.14 |
Summary of significant accoun_6
Summary of significant accounting policies: - Revenue recognition (Details) | 12 Months Ended | ||
Dec. 31, 2018USD ($)item | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | |
Revenue Recognition | |||
Number of electric distribution cooperative members | item | 38 | ||
Number of services provided | item | 2 | ||
Minimum margins for interest ratio under the first mortgage indenture | 1.10 | 1.10 | 1.10 |
Targeted margins for interest ratio | 1.14 | 1.14 | |
Achieved margins for interest ratio | 1.14 | 1.14 | 1.14 |
Refund liability | $ 30,870,000 | $ 29,149,000 | |
Total revenues | 1,480,113,000 | 1,434,196,000 | $ 1,507,231,000 |
Vogtle Units No. 3 & No. 4 | |||
Operating revenues | |||
Recovery of financing costs | 12,229,000 | 11,000,000 | 16,096,000 |
Cumulative recovery of financing costs | $ 66,316,000 | ||
Additional collection period (in years) | 5 years | ||
Billed amount | $ 15,435,000 | ||
Members | |||
Revenue Recognition | |||
Total revenues | $ 1,479,379,000 | $ 1,433,830,000 | $ 1,506,807,000 |
Jackson EMC | Total operating revenues | Revenues of members | |||
Operating revenues | |||
Concentration risk (as a percent) | 14.10% | 14.70% | 14.30% |
Cobb EMC | Total operating revenues | Revenues of members | |||
Operating revenues | |||
Concentration risk (as a percent) | 13.90% | 14.30% | 13.70% |
Sawnee EMC | Total operating revenues | Revenues of members | |||
Operating revenues | |||
Concentration risk (as a percent) | 10.50% | ||
Capacity revenues | Members | |||
Revenue Recognition | |||
Total revenues | $ 927,419,000 | $ 912,421,000 | $ 949,193,000 |
Energy revenues | Members | |||
Revenue Recognition | |||
Total revenues | $ 551,960,000 | $ 521,409,000 | $ 557,614,000 |
Summary of significant accoun_7
Summary of significant accounting policies: - Receivables (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Receivables | |||
Impairment losses | $ 0 | $ 0 | |
Members | |||
Receivables | |||
Receivables | $ 122,888,000 | $ 126,211,000 | $ 136,552,000 |
Summary of significant accoun_8
Summary of significant accounting policies: - Nuclear fuel cost (Details) - USD ($) | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Nuclear fuel cost | ||||
Nuclear fuel expense | $ 85,949,000 | $ 90,520,000 | $ 83,751,000 | |
Nuclear fuel disposal cost litigation for period from January 2005 To December 2010 | Settled litigation | Plant Hatch and Plant Vogtle | ||||
Nuclear fuel cost | ||||
Litigation settlement amount | $ 10,949,000 | |||
Nuclear fuel disposal cost litigation for period from January 2011 through December 31, 2014 and January 1, 2015 through December 31, 2017 | Pending litigation | Plant Hatch and Plant Vogtle | ||||
Nuclear fuel cost | ||||
Damages receivable | $ 0 |
Summary of significant accoun_9
Summary of significant accounting policies: - Asset retirement obligations and other retirement costs (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Asset retirement obligations | |||
Balance at the beginning of the period | $ 734,997,000 | $ 698,051,000 | |
Liabilities settled | (4,680,000) | (2,145,000) | |
Accretion | 38,090,000 | 36,674,000 | $ 32,361,000 |
Change in cash flow estimates | 249,156,000 | 2,417,000 | |
Balance at the end of the period | 1,017,563,000 | 734,997,000 | 698,051,000 |
Coal Ash | |||
Increase in the obligation for coal ash decommissioning | 161,303,000 | ||
Fund balances for coal ash pond and landfill decommissioning | $ 60,599,000 | 41,844,000 | |
Hatch Units No. 1 & No. 2 | |||
Nuclear Decommissioning | |||
Assumed escalation rate for labor, material and equipment (as a percent) | 2.80% | ||
Hatch Unit No. 1 | |||
Nuclear Decommissioning | |||
Estimated costs based on site study | $ 277,000,000 | ||
Hatch Unit No. 1 | Radiated structures | |||
Nuclear Decommissioning | |||
Estimated costs based on site study | 209,000,000 | ||
Hatch Unit No. 1 | Spent fuel management | |||
Nuclear Decommissioning | |||
Estimated costs based on site study | 54,000,000 | ||
Hatch Unit No. 1 | Non-radiated structures | |||
Nuclear Decommissioning | |||
Estimated costs based on site study | 14,000,000 | ||
Hatch Unit No. 2 | |||
Nuclear Decommissioning | |||
Estimated costs based on site study | 299,000,000 | ||
Hatch Unit No. 2 | Radiated structures | |||
Nuclear Decommissioning | |||
Estimated costs based on site study | 231,000,000 | ||
Hatch Unit No. 2 | Spent fuel management | |||
Nuclear Decommissioning | |||
Estimated costs based on site study | 49,000,000 | ||
Hatch Unit No. 2 | Non-radiated structures | |||
Nuclear Decommissioning | |||
Estimated costs based on site study | $ 19,000,000 | ||
Vogtle Units No. 1 & No. 2 | |||
Nuclear Decommissioning | |||
Assumed escalation rate for labor, material and equipment (as a percent) | 2.70% | ||
Vogtle Unit No. 1 | |||
Nuclear Decommissioning | |||
Estimated costs based on site study | $ 266,000,000 | ||
Vogtle Unit No. 1 | Radiated structures | |||
Nuclear Decommissioning | |||
Estimated costs based on site study | 188,000,000 | ||
Vogtle Unit No. 1 | Spent fuel management | |||
Nuclear Decommissioning | |||
Estimated costs based on site study | 55,000,000 | ||
Vogtle Unit No. 1 | Non-radiated structures | |||
Nuclear Decommissioning | |||
Estimated costs based on site study | 23,000,000 | ||
Vogtle Unit No. 2 | |||
Nuclear Decommissioning | |||
Estimated costs based on site study | 286,000,000 | ||
Vogtle Unit No. 2 | Radiated structures | |||
Nuclear Decommissioning | |||
Estimated costs based on site study | 206,000,000 | ||
Vogtle Unit No. 2 | Spent fuel management | |||
Nuclear Decommissioning | |||
Estimated costs based on site study | 51,000,000 | ||
Vogtle Unit No. 2 | Non-radiated structures | |||
Nuclear Decommissioning | |||
Estimated costs based on site study | 29,000,000 | ||
Asset retirement obligations - Nuclear | |||
Asset retirement obligations | |||
Balance at the beginning of the period | 548,574,000 | 517,565,000 | |
Liabilities settled | (1,686,000) | (17,000) | |
Accretion | 32,857,000 | 31,026,000 | |
Change in cash flow estimates | 79,211,000 | ||
Balance at the end of the period | 658,956,000 | 548,574,000 | 517,565,000 |
Asset retirement obligations - Coal Ash | |||
Asset retirement obligations | |||
Balance at the beginning of the period | 161,755,000 | 156,465,000 | |
Liabilities settled | (1,596,000) | (943,000) | |
Accretion | 4,238,000 | 4,629,000 | |
Change in cash flow estimates | 161,851,000 | 1,604,000 | |
Balance at the end of the period | 326,248,000 | 161,755,000 | 156,465,000 |
Asset retirement obligations - Other | |||
Asset retirement obligations | |||
Balance at the beginning of the period | 24,668,000 | 24,021,000 | |
Liabilities settled | (1,398,000) | (1,185,000) | |
Accretion | 995,000 | 1,019,000 | |
Change in cash flow estimates | 8,094,000 | 813,000 | |
Balance at the end of the period | $ 32,359,000 | $ 24,668,000 | $ 24,021,000 |
Summary of significant accou_10
Summary of significant accounting policies: - Nuclear decommissioning funds (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Nuclear decommissioning funds | |||
Additional contribution to external trust funds | $ 0 | $ 0 | |
Additional amount collected for nuclear decommissioning | $ 4,750,000 | $ 4,750,000 | |
Percentage of decommissioning fund classified as equity | 60.00% | 60.00% | |
Percentage of decommissioning funds classified as fixed income securities | 40.00% | 40.00% | |
External and Internal Trust Funds: | |||
Purchases | $ 457,909,000 | $ 450,113,000 | $ 395,506,000 |
Fair Value | $ 420,818,000 | 445,055,000 | |
Average annualized rate of return over the past ten years | 7.70% | ||
Average annualized rate of return since inception | 5.80% | ||
External Trust Funds | |||
External and Internal Trust Funds: | |||
Cost | 368,664,000 | 348,957,000 | |
Purchases | $ 457,909,000 | 450,113,000 | |
Net Proceeds | (453,122,000) | (430,406,000) | |
Unrealized Gain (Loss) | 47,367,000 | 76,391,000 | |
Fair Value | 420,818,000 | 445,055,000 | |
Net realized gains or losses, interest income and dividends, contributions and fees | 4,786,000 | 19,707,000 | |
Internal Funds | |||
External and Internal Trust Funds: | |||
Cost | 77,238,000 | 65,005,000 | |
Purchases | 161,454,000 | 73,153,000 | |
Net Proceeds | (156,015,000) | (60,920,000) | |
Unrealized Gain (Loss) | 6,127,000 | 11,669,000 | |
Fair Value | 88,804,000 | 88,907,000 | |
Net realized gains or losses, interest income and dividends, contributions and fees | 689,000 | 12,232,800 | |
Equity | External Trust Funds | |||
External and Internal Trust Funds: | |||
Cost | 203,622,000 | 200,595,000 | |
Purchases | 12,186,000 | 61,406,000 | |
Net Proceeds | (7,789,000) | (44,607,000) | |
Unrealized Gain (Loss) | 49,475,000 | 76,221,000 | |
Fair Value | 257,494,000 | 293,615,000 | |
Equity | Internal Funds | |||
External and Internal Trust Funds: | |||
Cost | 43,698,000 | 38,798,000 | |
Net Proceeds | 596,000 | 4,900,000 | |
Unrealized Gain (Loss) | 6,373,000 | 11,669,000 | |
Fair Value | 50,667,000 | 55,367,000 | |
Debt | External Trust Funds | |||
External and Internal Trust Funds: | |||
Cost | 164,901,000 | 148,011,000 | |
Purchases | 445,353,000 | 388,609,000 | |
Net Proceeds | (443,712,000) | (384,199,000) | |
Unrealized Gain (Loss) | (2,108,000) | 170,000 | |
Fair Value | 164,434,000 | 152,591,000 | |
Debt | Internal Funds | |||
External and Internal Trust Funds: | |||
Cost | 33,540,000 | 26,207,000 | |
Purchases | 161,454,000 | 73,153,000 | |
Net Proceeds | (156,611,000) | (65,820,000) | |
Unrealized Gain (Loss) | (246,000) | ||
Fair Value | 38,137,000 | 33,540,000 | |
Other | External Trust Funds | |||
External and Internal Trust Funds: | |||
Cost | 141,000 | $ 351,000 | |
Purchases | 370,000 | 98,000 | |
Net Proceeds | (1,621,000) | (1,600,000) | |
Fair Value | $ (1,110,000) | $ (1,151,000) |
Summary of significant accou_11
Summary of significant accounting policies: - Depreciation and Electric plant (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Depreciation | |||
Depreciation expense | $ 227,213,000 | $ 218,027,000 | $ 211,282,000 |
Electric plant | |||
Allowance for funds used during construction (as a percent) | 4.25% | 4.45% | 4.61% |
Steam production | |||
Depreciation | |||
Annual depreciation rates (as a percent) | 2.57% | 2.91% | 2.84% |
Steam production | Minimum | |||
Depreciation | |||
Useful Life | 49 years | 49 years | 49 years |
Steam production | Maximum | |||
Depreciation | |||
Useful Life | 65 years | 65 years | 65 years |
Nuclear production | |||
Depreciation | |||
Annual depreciation rates (as a percent) | 1.92% | 1.96% | 1.96% |
Nuclear production | Minimum | |||
Depreciation | |||
Useful Life | 37 years | 37 years | 37 years |
Nuclear production | Maximum | |||
Depreciation | |||
Useful Life | 60 years | 60 years | 60 years |
Hydro production | |||
Depreciation | |||
Useful Life | 50 years | 50 years | 50 years |
Annual depreciation rates (as a percent) | 2.00% | 2.00% | 2.00% |
Other production | |||
Depreciation | |||
Annual depreciation rates (as a percent) | 2.61% | 2.58% | 2.55% |
Other production | Minimum | |||
Depreciation | |||
Useful Life | 30 years | 30 years | 30 years |
Other production | Maximum | |||
Depreciation | |||
Useful Life | 35 years | 35 years | 35 years |
Transmission plant | |||
Depreciation | |||
Useful Life | 36 years | 36 years | 36 years |
Annual depreciation rates (as a percent) | 2.75% | 2.75% | 2.75% |
General | Minimum | |||
Depreciation | |||
Useful Life | 3 years | 3 years | 3 years |
Annual depreciation rates (as a percent) | 2.00% | 2.00% | 2.00% |
General | Maximum | |||
Depreciation | |||
Useful Life | 50 years | 50 years | 50 years |
Annual depreciation rates (as a percent) | 33.33% | 33.33% | 33.33% |
Summary of significant accou_12
Summary of significant accounting policies: - Restricted investments and Inventories (Details) - USD ($) | Oct. 01, 2020 | Dec. 31, 2018 | Dec. 31, 2017 |
Restricted investments | |||
Guaranteed interest rate on deposit (as a percent) | 5.00% | 5.00% | |
Restricted investments | $ 653,158,000 | $ 882,909,000 | |
Restricted investments, long-term | 503,158,000 | 653,585,000 | |
Inventories | |||
Fossil fuels inventories | 48,709,000 | 54,050,000 | |
Spare parts | $ 210,379,000 | $ 212,169,000 | |
Forecast | |||
Restricted investments | |||
Guaranteed interest rate on deposit (as a percent) | 4.00% |
Summary of significant accou_13
Summary of significant accounting policies: - Regulatory assets and liabilities (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | $ 655,063 | $ 585,084 |
Total Regulatory Liabilities | 218,998 | 251,649 |
Net Regulatory Assets | 436,065 | 333,435 |
Accumulated retirement costs for other obligations | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Liabilities | 13,873 | 12,813 |
Deferral of effects on net margin | Hawk Road Energy Facility | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Liabilities | 19,101 | 19,553 |
Major maintenance reserve | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Liabilities | 45,547 | 47,087 |
Amortization on capital leases | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Liabilities | 17,156 | 20,055 |
Deferred debt service adder | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Liabilities | 105,192 | 95,695 |
Asset retirement obligations - Nuclear | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Liabilities | 0 | 53,571 |
Revenue deferral plan | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Liabilities | $ 15,670 | 0 |
Amortization period, other regulatory liabilities | 5 years | |
Other regulatory liabilities | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Liabilities | $ 2,459 | 2,875 |
Other regulatory liabilities | Maximum | ||
Regulatory Assets and Liabilities | ||
Amortization period, other regulatory liabilities | 8 years | |
Premium and loss on reacquired debt | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | $ 46,315 | 52,989 |
Premium and loss on reacquired debt | Maximum | ||
Regulatory Assets and Liabilities | ||
Amortization period, other regulatory assets | 25 years | |
Amortization on capital leases | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | $ 34,918 | 33,846 |
Outage costs | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | $ 36,352 | 40,525 |
Coal-fired maintenance outage costs | Maximum | ||
Regulatory Assets and Liabilities | ||
Amortization period, other regulatory assets | 48 months | |
Nuclear refueling outage costs | Minimum | ||
Regulatory Assets and Liabilities | ||
Amortization period, other regulatory assets | 18 months | |
Nuclear refueling outage costs | Maximum | ||
Regulatory Assets and Liabilities | ||
Amortization period, other regulatory assets | 24 months | |
Asset retirement obligations - Ashpond and other | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | $ 137,835 | 68,289 |
Asset retirement obligations - Nuclear | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | 7,031 | 0 |
Depreciation expense | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | $ 41,244 | 42,667 |
Depreciation expense | Plant Vogtle | ||
Regulatory Assets and Liabilities | ||
Operating license expected extension period for Plant Vogtle | 20 years | |
Operating license period | 40 years | |
Deferred charges related to Vogtle Units No. 3 and No. 4 training costs | Vogtle Units No. 3 & No. 4 | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | $ 51,549 | 48,702 |
Interest rate options cost | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | 116,960 | 112,102 |
Deferral of effects on net margin | Smith Energy Facility | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | 160,509 | 166,454 |
Other regulatory assets | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | $ 22,350 | $ 19,510 |
Other regulatory assets | Maximum | ||
Regulatory Assets and Liabilities | ||
Amortization period, other regulatory assets | 31 years |
Summary of significant accou_14
Summary of significant accounting policies: - Related parties (Details) | 12 Months Ended | ||
Dec. 31, 2018USD ($)item | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | |
Related parties | |||
Number of electric distribution cooperative members | 38 | ||
Georgia Transmission Corporation | |||
Related parties | |||
Number of electric distribution cooperative members | 38 | ||
Expenses incurred for transmission services, system operations services and administrative support services | $ | $ 30,428,000 | $ 28,410,000 | $ 27,399,000 |
Georgia System Operations Corporation | |||
Related parties | |||
Number of electric distribution cooperative members | 38 | ||
Expenses incurred for transmission services, system operations services and administrative support services | $ | $ 25,578,000 | $ 25,597,000 | $ 23,994,000 |
Summary of significant accou_15
Summary of significant accounting policies: - Recently issued or adopted accounting pronouncements (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2018 | Jan. 01, 2019 | Dec. 31, 2017 | |
Recently Issued or Adopted Accounting Pronouncements | |||
Regulatory assets | $ 655,063,000 | $ 585,084,000 | |
Refund liability | 30,870,000 | 29,149,000 | |
ASU 2014-09 | |||
Recently Issued or Adopted Accounting Pronouncements | |||
Refund liability | 30,870,000 | 29,149,000 | |
ASU 2016-01 | |||
Recently Issued or Adopted Accounting Pronouncements | |||
Regulatory assets | $ 975,000 | $ 618,000 | |
ASU 2016-02 | Scherer Unit No. 2 | |||
Recently Issued or Adopted Accounting Pronouncements | |||
Percentage of undivided interest | 60.00% | ||
ASU 2016-02 | Adjustments | |||
Recently Issued or Adopted Accounting Pronouncements | |||
Lease assets | $ 6,983,000 | ||
Lease liabilities | $ 6,983,000 |
Fair Value_ - Asset and liabili
Fair Value: - Asset and liabilities measured at fair value on a recurring basis (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Fair value | ||
Nuclear decommissioning trust fund | $ 420,818,000 | $ 445,055,000 |
Long-term investments | 164,125,000 | 140,622,000 |
Natural gas swaps | ||
Fair value | ||
Derivative liabilities | 13,154,000 | 6,328,000 |
International equity trust | ||
Fair value | ||
Unfunded commitments | $ 0 | |
Redemption notice period | 3 days | |
Recurring basis | Natural gas swaps | ||
Fair value | ||
Derivative liabilities | $ 13,154,000 | 6,328,000 |
Recurring basis | Domestic equity | ||
Fair value | ||
Nuclear decommissioning trust fund | 136,196,000 | 142,419,000 |
Recurring basis | International equity trust | ||
Fair value | ||
Nuclear decommissioning trust fund | 76,852,000 | 88,820,000 |
Long-term investments | 17,382,000 | 20,071,000 |
Recurring basis | Corporate bonds and debt | ||
Fair value | ||
Nuclear decommissioning trust fund | 51,356,000 | 66,317,000 |
Long-term investments | 12,571,000 | 16,215,000 |
Recurring basis | US Treasury securities | ||
Fair value | ||
Nuclear decommissioning trust fund | 47,712,000 | 38,791,000 |
Long-term investments | 12,062,000 | 6,670,000 |
Recurring basis | Mortgage backed securities | ||
Fair value | ||
Nuclear decommissioning trust fund | 56,004,000 | 49,379,000 |
Long-term investments | 11,517,000 | 7,267,000 |
Recurring basis | Domestic mutual funds | ||
Fair value | ||
Nuclear decommissioning trust fund | 43,359,000 | 47,833,000 |
Long-term investments | 94,494,000 | 87,011,000 |
Recurring basis | Municipal bonds | ||
Fair value | ||
Nuclear decommissioning trust fund | 278,000 | 92,000 |
Recurring basis | Federal agency securities | ||
Fair value | ||
Nuclear decommissioning trust fund | 6,066,000 | 3,725,000 |
Long-term investments | 941,000 | 259,000 |
Recurring basis | Treasury STRIPS | ||
Fair value | ||
Long-term investments | 14,113,000 | |
Recurring basis | Other | ||
Fair value | ||
Nuclear decommissioning trust fund | 2,995,000 | 7,679,000 |
Long-term investments | 1,045,000 | 3,129,000 |
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic equity | ||
Fair value | ||
Nuclear decommissioning trust fund | 136,196,000 | 142,419,000 |
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | US Treasury securities | ||
Fair value | ||
Nuclear decommissioning trust fund | 47,712,000 | 38,791,000 |
Long-term investments | 12,062,000 | 6,670,000 |
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic mutual funds | ||
Fair value | ||
Nuclear decommissioning trust fund | 43,359,000 | 47,833,000 |
Long-term investments | 94,494,000 | 87,011,000 |
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other | ||
Fair value | ||
Nuclear decommissioning trust fund | 2,031,000 | 7,679,000 |
Long-term investments | 1,045,000 | 3,129,000 |
Recurring basis | Significant Other Observable Inputs (Level 2) | Natural gas swaps | ||
Fair value | ||
Derivative liabilities | 13,154,000 | 6,328,000 |
Recurring basis | Significant Other Observable Inputs (Level 2) | International equity trust | ||
Fair value | ||
Nuclear decommissioning trust fund | 76,852,000 | 88,820,000 |
Long-term investments | 17,382,000 | 20,071,000 |
Recurring basis | Significant Other Observable Inputs (Level 2) | Corporate bonds and debt | ||
Fair value | ||
Nuclear decommissioning trust fund | 48,853,000 | 66,317,000 |
Long-term investments | 11,366,000 | 16,215,000 |
Recurring basis | Significant Other Observable Inputs (Level 2) | Mortgage backed securities | ||
Fair value | ||
Nuclear decommissioning trust fund | 56,004,000 | 49,379,000 |
Long-term investments | 11,517,000 | 7,267,000 |
Recurring basis | Significant Other Observable Inputs (Level 2) | Municipal bonds | ||
Fair value | ||
Nuclear decommissioning trust fund | 278,000 | 92,000 |
Recurring basis | Significant Other Observable Inputs (Level 2) | Federal agency securities | ||
Fair value | ||
Nuclear decommissioning trust fund | 6,066,000 | 3,725,000 |
Long-term investments | 941,000 | $ 259,000 |
Recurring basis | Significant Other Observable Inputs (Level 2) | Treasury STRIPS | ||
Fair value | ||
Long-term investments | 14,113,000 | |
Recurring basis | Significant Other Observable Inputs (Level 2) | Other | ||
Fair value | ||
Nuclear decommissioning trust fund | 964,000 | |
Recurring basis | Significant Other Unobservable Inputs (Level 3) | Corporate bonds and debt | ||
Fair value | ||
Nuclear decommissioning trust fund | 2,503,000 | |
Long-term investments | $ 1,205,000 |
Fair Value_ - Changes in Level
Fair Value: - Changes in Level 3 assets (Details) - Significant Other Unobservable Inputs (Level 3) - Recurring basis $ in Thousands | 12 Months Ended |
Dec. 31, 2018USD ($) | |
Changes in Level 3 assets and liabilities measured at fair value on a recurring basis | |
Transfers to Level 3 | $ 4,997 |
Total gains or losses (realized/unrealized) | |
Changes in net assets | (1,289) |
Balance at the end of the period | $ 3,708 |
Fair Value_ - Estimated fair va
Fair Value: - Estimated fair value of long-term debt (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Carrying Value | ||
Fair Value | ||
Long-term debt | $ 9,347,307 | $ 8,232,703 |
Fair Value | Significant Other Observable Inputs (Level 2) | ||
Fair Value | ||
Long-term debt | $ 9,837,254 | $ 9,155,942 |
Derivative Instruments_ - Gas h
Derivative Instruments: - Gas hedges (Details) - Natural gas swaps item in Millions | Dec. 31, 2018USD ($)item | Dec. 31, 2017USD ($) |
Derivative Instruments | ||
Derivative liabilities | $ | $ 13,154,000 | $ 6,328,000 |
Collateral or 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 | $ | $ 13,154,000 | |
Notional volume of natural gas derivatives (in MMBTUs) | 87.2 | |
2019 | ||
Derivative Instruments | ||
Notional volume of natural gas derivatives (in MMBTUs) | 23.4 | |
2020 | ||
Derivative Instruments | ||
Notional volume of natural gas derivatives (in MMBTUs) | 22.1 | |
2021 | ||
Derivative Instruments | ||
Notional volume of natural gas derivatives (in MMBTUs) | 19.6 | |
2022 | ||
Derivative Instruments | ||
Notional volume of natural gas derivatives (in MMBTUs) | 12.6 | |
2023 | ||
Derivative Instruments | ||
Notional volume of natural gas derivatives (in MMBTUs) | 9.5 |
Derivative Instruments_ - Fair
Derivative Instruments: - Fair value of derivative instruments not designated as hedging (Details) - Natural gas swaps - USD ($) | Dec. 31, 2018 | Dec. 31, 2017 |
Liabilities: | ||
Fair value of liabilities | $ 13,154,000 | $ 6,328,000 |
Not designated as hedges | Other current assets | ||
Assets: | ||
Fair value of assets | 226,000 | 412,000 |
Not designated as hedges | Other current liabilities | ||
Liabilities: | ||
Fair value of liabilities | 2,066,000 | 1,575,000 |
Not designated as hedges | Other deferred credits | ||
Liabilities: | ||
Fair value of liabilities | $ 11,314,000 | $ 5,165,000 |
Derivative Instruments_ - Reali
Derivative Instruments: - Realized and unrealized gains and (losses) on derivative instruments (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Gains and (losses) on derivative instruments | |||
Net unrealized losses on derivative instruments | $ 13,154 | $ 6,328 | |
Natural gas swaps | Regulatory asset | |||
Gains and (losses) on derivative instruments | |||
Net unrealized losses on derivative instruments | 13,154 | 6,328 | |
Natural gas swaps | Fuel | |||
Gains and (losses) on derivative instruments | |||
Gains | 6,088 | 3,818 | $ 2,445 |
Losses | (956) | (1,677) | (19,697) |
Total | $ 5,132 | $ 2,141 | $ (17,252) |
Investments_ - Investments in D
Investments: - Investments in Debt and Equity Securities (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Investments: | ||
Percent of gross unrealized losses which have been unrealized for greater than one year | 59.00% | 69.00% |
Gross unrealized losses greater than one year | $ 49,975,000 | $ 60,101,000 |
Gross unrealized losses less than one year | 351,488,000 | 337,444,000 |
Cost | ||
Equity | 251,226,000 | 246,549,000 |
Debt | 278,030,000 | 240,878,000 |
Other | 3,075,000 | 10,807,000 |
Total | 532,331,000 | 498,234,000 |
Gains | ||
Equity | 64,954,000 | 91,954,000 |
Debt | 1,718,000 | 1,814,000 |
Other | 1,000 | |
Total | 66,672,000 | 93,769,000 |
Losses | ||
Equity | (9,105,000) | (4,064,000) |
Debt | (4,955,000) | (2,262,000) |
Total | (14,060,000) | (6,326,000) |
Fair Value | ||
Equity | 307,075,000 | 334,439,000 |
Debt | 274,793,000 | 240,430,000 |
Other | 3,075,000 | 10,808,000 |
Total | $ 584,943,000 | $ 585,677,000 |
Investments_ - Contractual Matu
Investments: - Contractual Maturities of Debt Securities (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Cost | ||
Due within one year | $ 65,039 | $ 54,785 |
Due after one year through five years | 62,293 | 53,050 |
Due after five years through ten years | 50,606 | 51,367 |
Due after ten years | 100,092 | 81,676 |
Total | 278,030 | 240,878 |
Fair Value | ||
Due within one year | 63,925 | 54,143 |
Due after one year through five years | 61,924 | 52,834 |
Due after five years through ten years | 49,855 | 51,600 |
Due after ten years | 99,089 | 81,853 |
Total | $ 274,793 | $ 240,430 |
Investments_ - Gross realized g
Investments: - Gross realized gains, losses and proceeds from sales of securities (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Investments: | |||
Gross realized gains | $ 14,268 | $ 35,523 | $ 19,934 |
Gross realized losses | (19,139) | (16,909) | (20,030) |
Proceeds from sales | $ 626,612 | $ 521,345 | $ 439,540 |
Investments_ - Investment in as
Investments: - Investment in associated companies (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Investment in associated companies | ||
Investments in associated companies | $ 77,037 | $ 74,981 |
National Rural Utilities Cooperative Finance Corporation | ||
Investment in associated companies | ||
Investments in associated companies | 24,061 | 24,056 |
CT Parts, LLC | ||
Investment in associated companies | ||
Investments in associated companies | 10,236 | 10,243 |
Georgia Transmission Corporation | ||
Investment in associated companies | ||
Investments in associated companies | 30,237 | 28,690 |
Georgia System Operations Corporation | ||
Investment in associated companies | ||
Investments in associated companies | 9,250 | 8,500 |
Other | ||
Investment in associated companies | ||
Investments in associated companies | $ 3,253 | $ 3,492 |
Investments_ - Rocky Mountain t
Investments: - Rocky Mountain transactions (Details) - Rocky Mountain | 2 Months Ended | 12 Months Ended |
Jan. 31, 1997item | Dec. 31, 2012USD ($)installmentitem | |
Rocky Mountain transactions | ||
Number of long-term lease transactions | item | 6 | |
Percentage of undivided ownership interest | 74.61% | |
Number of separate owner trusts to whom undivided interest was leased | item | 6 | |
Number of investors in ownership trusts | item | 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 | item | 5 | |
Percentage of leases which remained in place | 10.00% | |
Basic rental payments due | $ 42,218,000 | |
Purchase option price | 112,000,000 | |
Outstanding loan amount | $ 74,000,000 | |
Percentage to be purchased under first option if financing cannot be arranged | 49.00% | |
Maximum | ||
Rocky Mountain transactions | ||
Additional term of sublease | 16 years | |
AIG Matched Funding Corp | ||
Rocky Mountain transactions | ||
Fund amount under payment undertaking agreement | $ 74,000,000 | |
Fund amount under equity funding agreement | $ 37,928,000 | |
Number of installments available to pay to the owner trust | installment | 5 |
Income taxes_ - Statutory feder
Income taxes: - Statutory federal and effective income tax rate and components of deferred tax assets and liabilities (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
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) | 21.00% | 35.00% | 35.00% |
Patronage exclusion (as a percent) | (20.80%) | (34.10%) | (34.70%) |
AMT credit monetization (as a percent) | (0.00%) | (2.20%) | (0.00%) |
Other (as a percent) | (0.20%) | (0.90%) | (0.30%) |
Effective income tax rate (as a percent) | 0.00% | (2.20%) | 0.00% |
Deferred tax assets | |||
Net operating losses | $ 3,830,000 | $ 19,668,000 | |
Accounting for Rocky Mountain transactions | 231,543,000 | 231,268,000 | |
Advance payments | 46,708,000 | ||
Other assets | 82,655,000 | 75,013,000 | |
Deferred tax assets | 364,736,000 | 325,949,000 | |
Less: Valuation allowance | (3,830,000) | (19,668,000) | |
Net deferred tax assets | 360,906,000 | 306,281,000 | |
Deferred tax liabilities | |||
Depreciation | 268,039,000 | 271,652,000 | |
Accounting for Rocky Mountain transactions | 116,226,000 | 114,514,000 | |
Other liabilities | 75,691,000 | 78,407,000 | |
Deferred tax liabilities | 459,956,000 | 464,573,000 | |
Net deferred tax liabilities | 99,050,000 | 158,292,000 | |
Less: Patronage exclusion | (99,050,000) | (158,292,000) | |
Net deferred taxes | $ 0 | 0 | |
Alternative Minimum Tax Credits | |||
Difference between statutory federal income tax rate on income before income taxes and effective income tax rate | |||
Tax benefit reflected in effective income tax rate | $ 1,117,000 |
Income taxes_ - NOLs and altern
Income taxes: - NOLs and alternative minimum tax credits (Details) $ in Thousands | Dec. 31, 2018USD ($) |
Income taxes | |
NOLs | $ 14,878 |
2019 | |
Income taxes | |
NOLs | 10,516 |
2020 | |
Income taxes | |
NOLs | $ 4,362 |
Income taxes_ - Other tax infor
Income taxes: - Other tax information (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income taxes | |||
Federal tax rate (as a percent) | 21.00% | 35.00% | 35.00% |
Advance payments | $ 46,708,000 | ||
Uncertain tax positions | $ 0 | ||
State jurisdictions | Minimum | |||
Income taxes | |||
Statute of limitations for filing an income tax return | 3 years | ||
State jurisdictions | Maximum | |||
Income taxes | |||
Period during which state impact of any federal changes remains subject to examination by various states | 1 year | ||
Statute of limitations for filing an income tax return | 5 years |
Capital leases_ (Details)
Capital leases: (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2018USD ($)item | Dec. 31, 1985item | Dec. 31, 2017USD ($) | |
Minimum lease payments under the capital leases together with the present value of the net minimum lease payments | |||
Long-term balance | $ 81,730 | $ 87,192 | |
Scherer Unit No. 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% | ||
Assumed interest rate on lease (as a percent) | 11.05% | ||
Minimum lease payments under the capital leases together with the present value of the net minimum lease payments | |||
2019 | 14,949 | ||
2020 | 14,949 | ||
2021 | 14,949 | ||
2022 | 7,474 | ||
2023 | 22,424 | ||
2024-2031 | 70,483 | ||
Total minimum lease payments | 145,228 | ||
Less: Amount representing interest | (58,036) | ||
Present value of net minimum lease payments | 87,192 | ||
Less: Current portion | (5,462) | ||
Long-term balance | $ 81,730 | ||
Scherer Unit No. 2 | Minimum | |||
Capital leases | |||
Leases renewal period | 1 year | ||
Scherer Unit No. 2 | Maximum | |||
Capital leases | |||
Leases renewal period | 5 years | ||
Scherer Unit No. 2 | Lease renewal through December 31, 2027 | |||
Capital leases | |||
Number of leases for which lease term is extended | item | 3 | ||
Scherer Unit No. 2 | Lease renewal through June 30, 2031 | |||
Capital leases | |||
Number of leases for which lease term is extended | item | 1 |
Debt_ - Maturities for long-ter
Debt: - Maturities for long-term debt and capital lease obligations and debt outstanding (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Maturities for long-term debt and capital lease obligations | ||
2019 | $ 522,289 | |
2020 | 321,140 | |
2021 | 286,637 | |
2022 | 216,403 | |
2023 | 204,891 | |
Long-term debt outstanding and the associated unamortized debt issuance costs and debt discounts | ||
Principal | 8,910,680 | $ 8,232,703 |
Long-term debt | ||
Maturities for long-term debt and capital lease obligations | ||
2019 | 516,827 | |
2020 | 315,058 | |
2021 | 279,865 | |
2022 | 208,862 | |
2023 | $ 196,493 | |
Weighted average interest rate on long-term debt | 4.24% | 4.17% |
Long-term debt outstanding and the associated unamortized debt issuance costs and debt discounts | ||
Principal | $ 8,910,680 | $ 8,232,703 |
Unamortized Debt Issuance Costs and Debt Discounts | 103,331 | 95,613 |
Capital Lease Obligations | ||
Maturities for long-term debt and capital lease obligations | ||
2019 | 5,462 | |
2020 | 6,082 | |
2021 | 6,772 | |
2022 | 7,541 | |
2023 | 8,398 | |
FFB | Long-term debt | ||
Maturities for long-term debt and capital lease obligations | ||
2019 | 164,782 | |
2020 | 180,107 | |
2021 | 185,476 | |
2022 | 189,176 | |
2023 | 195,483 | |
Long-term debt outstanding and the associated unamortized debt issuance costs and debt discounts | ||
Principal | 4,372,422 | 4,192,450 |
Unamortized Debt Issuance Costs and Debt Discounts | 50,210 | 51,593 |
FMBs | Long-term debt | ||
Maturities for long-term debt and capital lease obligations | ||
2019 | 351,010 | |
2020 | 1,010 | |
2021 | 1,010 | |
2022 | 1,010 | |
2023 | 1,010 | |
Long-term debt outstanding and the associated unamortized debt issuance costs and debt discounts | ||
Principal | 3,556,062 | 3,057,072 |
Unamortized Debt Issuance Costs and Debt Discounts | 41,509 | 34,673 |
PCBs | Long-term debt | ||
Maturities for long-term debt and capital lease obligations | ||
2020 | 133,550 | |
2021 | 93,379 | |
2022 | 18,676 | |
Long-term debt outstanding and the associated unamortized debt issuance costs and debt discounts | ||
Principal | 980,770 | 980,770 |
Unamortized Debt Issuance Costs and Debt Discounts | 11,612 | 9,347 |
Series 2009 and Series 2010 bonds | Long-term debt | ||
Maturities for long-term debt and capital lease obligations | ||
2020 | 133,600 | |
2021 | 93,400 | |
2022 | 18,700 | |
CFC | Long-term debt | ||
Maturities for long-term debt and capital lease obligations | ||
2019 | 1,035 | |
2020 | 391 | |
Long-term debt outstanding and the associated unamortized debt issuance costs and debt discounts | ||
Principal | $ 1,426 | $ 2,411 |
Debt_ - Department of Energy Lo
Debt: - Department of Energy Loan Guarantee (Details) | Mar. 15, 2019USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Mar. 22, 2019USD ($) | Sep. 30, 2017USD ($) | Sep. 28, 2017USD ($) | Sep. 22, 2017USD ($) | Feb. 20, 2014USD ($)item |
Debt | |||||||||
Aggregate borrowings including capitalized interest | $ 9,347,307,000 | $ 8,232,703,000 | |||||||
Long-term debt proceeds | $ 813,028,000 | 544,503,000 | $ 790,385,000 | ||||||
Vogtle Units No. 3 & No. 4 | |||||||||
Debt | |||||||||
Guarantee Obligations Maximum Exposure Received | $ 1,104,000,000 | ||||||||
Commercial paper | Subsequent Event | |||||||||
Debt | |||||||||
Repayment of outstanding commercial paper | $ 436,600,000 | ||||||||
Long-term debt | |||||||||
Debt | |||||||||
Maximum borrowing capacity | $ 4,676,749,167 | ||||||||
Ownership interests voting required to continue construction (as a percent) | 90.00% | ||||||||
Long-term debt | Department of Energy guarantee | |||||||||
Debt | |||||||||
Aggregate borrowings including capitalized interest | $ 1,794,723,000 | ||||||||
Long-term debt | FFB | |||||||||
Debt | |||||||||
Number of future advance promissory notes | item | 2 | ||||||||
Maximum borrowing capacity | $ 4,676,749,167 | $ 1,619,679,706 | $ 3,057,069,461 | ||||||
Long-term debt | FFB | Subsequent Event | |||||||||
Debt | |||||||||
Aggregate borrowings including capitalized interest | $ 585,000,000 | ||||||||
Long-term debt | FFB | Vogtle Units No. 3 & No. 4 | |||||||||
Debt | |||||||||
Term of debt | 5 years | ||||||||
Period of cessation of construction activities which would result in prepayment of outstanding principal | 12 months | ||||||||
Period of failure to fund operation and maintenance expenses which would result in prepayment of outstanding principal | 12 months | ||||||||
Long-term debt | FFB | Maximum | |||||||||
Debt | |||||||||
Maximum borrowing capacity designated for capitalized interest | $ 335,471,604 | ||||||||
Aggregate borrowings including capitalized interest | $ 3,057,069,461 | ||||||||
Long-term debt | FFB | Department of Energy guarantee | |||||||||
Debt | |||||||||
Aggregate borrowings including capitalized interest | $ 1,619,679,706 | ||||||||
Long-term debt | FFB | Department of Energy guarantee | Subsequent Event | Services Agreement | |||||||||
Debt | |||||||||
Guarantee Obligations Maximum Exposure Received | $ 4,676,749,167 | ||||||||
Long-term debt | FFB | US Treasury Securities, Current Yield | |||||||||
Debt | |||||||||
Spread on variable rate (as a percent) | 0.375% |
Debt_ - Rural Utilities Service
Debt: - Rural Utilities Service Guaranteed Loans (Details) - USD ($) | 1 Months Ended | 12 Months Ended |
Feb. 28, 2019 | Dec. 31, 2018 | |
Long-term debt | FFB | Rural Utilities Service Guaranteed Loans | ||
Debt | ||
Advances received on loans | $ 47,940,000 | $ 313,028,000 |
Debt_ - Pollution Control Reven
Debt: - Pollution Control Revenue Bonds (Details) - Long-term debt | Dec. 28, 2017USD ($)item |
First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2017 CDEF Burke | |
Debt | |
Principal amount | $ 399,785,000 |
Number of banks | item | 2 |
Repayments of debt, defeasance | $ 399,785,000 |
Pollution Control Revenue Bonds Series 2017C and Series 2017D | |
Debt | |
Principal amount | $ 200,000,000 |
Interest rate (as a percent) | 4.125% |
Pollution Control Revenue Bonds Series 2017E | |
Debt | |
Principal amount | $ 100,000,000 |
Interest rate (as a percent) | 3.25% |
Pollution Control Revenue Bonds Series 2017F | |
Debt | |
Principal amount | $ 99,785,000 |
Interest rate (as a percent) | 3.00% |
Debt_ - First Mortgage Bonds (D
Debt: - First Mortgage Bonds (Details) - Long-term debt - First Mortgage Bonds Payable: Series 2018A First Mortgage Bonds, 5.05% Due 2048 | Oct. 30, 2018USD ($) |
Debt | |
Principal amount | $ 500,000,000 |
Interest rate (as a percent) | 5.05% |
Debt_ - Credit Facilities (Deta
Debt: - Credit Facilities (Details) | Dec. 31, 2018USD ($)item | Dec. 31, 2017 |
Line of credit | ||
Debt | ||
Maximum borrowing capacity | $ 1,610,000,000 | |
Number of separate facilities | item | 4 | |
Weighted average interest rate on short-term borrowings (as a percent) | 2.98% | 1.58% |
Letter of credit | ||
Debt | ||
Maximum borrowing capacity | $ 760,000,000 | |
Available borrowing capacity | 509,000,000 | |
Letters of credit, amount outstanding | 251,000,000 | |
Commercial paper | ||
Debt | ||
Line of credit, amount outstanding | $ 436,627,000 |
Electric plant, construction _3
Electric plant, construction and related agreements: - Electric plant (Details) - USD ($) | Dec. 31, 2018 | Dec. 31, 2017 |
Public Utility Property Plant and Equipment | ||
Investment | $ 9,283,970,000 | $ 8,886,407,000 |
Accumulated Depreciation | (4,544,405,000) | (4,302,332,000) |
Total construction work in progress | 3,866,042,000 | 2,935,868,000 |
Plant acquisition adjustments | 197,000,000 | 197,000,000 |
Vogtle Units No. 1 & No. 2 | ||
Public Utility Property Plant and Equipment | ||
Investment | 2,975,727,000 | 2,916,852,000 |
Accumulated Depreciation | $ (1,775,569,000) | (1,751,558,000) |
Ownership interest (as a percent) | 30.00% | |
Vogtle Units No. 3 & No. 4 | ||
Public Utility Property Plant and Equipment | ||
Investment | $ 55,861,000 | 36,745,000 |
Accumulated Depreciation | $ (3,479,000) | (2,514,000) |
Ownership interest (as a percent) | 30.00% | |
Total construction work in progress | $ 3,600,631,000 | 2,721,949,000 |
Guarantee obligations, maximum exposure received | 1,104,000,000 | |
Hatch Units No. 1 & No. 2 | ||
Public Utility Property Plant and Equipment | ||
Investment | 910,259,000 | 824,890,000 |
Accumulated Depreciation | $ (441,240,000) | (420,000,000) |
Ownership interest (as a percent) | 30.00% | |
Wansley Units No. 1 & No. 2 | ||
Public Utility Property Plant and Equipment | ||
Investment | $ 655,618,000 | 587,436,000 |
Accumulated Depreciation | $ (311,606,000) | (236,155,000) |
Ownership interest (as a percent) | 30.00% | |
Scherer Unit No. 1 | ||
Public Utility Property Plant and Equipment | ||
Investment | $ 1,222,538,000 | 1,102,085,000 |
Accumulated Depreciation | $ (442,840,000) | (399,774,000) |
Ownership interest (as a percent) | 60.00% | |
Doyle | ||
Public Utility Property Plant and Equipment | ||
Investment | $ 137,133,000 | 136,351,000 |
Accumulated Depreciation | $ (109,509,000) | (106,370,000) |
Ownership interest (as a percent) | 100.00% | |
Rocky Mountain Units No. 1, No. 2 & No. 3 | ||
Public Utility Property Plant and Equipment | ||
Investment | $ 618,621,000 | 609,048,000 |
Accumulated Depreciation | $ (258,359,000) | (246,758,000) |
Ownership interest (as a percent) | 75.00% | |
Hartwell | ||
Public Utility Property Plant and Equipment | ||
Investment | $ 226,156,000 | 225,808,000 |
Accumulated Depreciation | $ (105,540,000) | (104,269,000) |
Ownership interest (as a percent) | 100.00% | |
Hawk Road Energy Facility | ||
Public Utility Property Plant and Equipment | ||
Investment | $ 254,925,000 | 251,671,000 |
Accumulated Depreciation | $ (75,308,000) | (73,998,000) |
Ownership interest (as a percent) | 100.00% | |
Talbot | ||
Public Utility Property Plant and Equipment | ||
Investment | $ 293,638,000 | 292,250,000 |
Accumulated Depreciation | $ (136,007,000) | (128,344,000) |
Ownership interest (as a percent) | 100.00% | |
Chattahoochee | ||
Public Utility Property Plant and Equipment | ||
Investment | $ 315,463,000 | 313,587,000 |
Accumulated Depreciation | $ (141,279,000) | (133,378,000) |
Ownership interest (as a percent) | 100.00% | |
Smith Energy Facility | ||
Public Utility Property Plant and Equipment | ||
Investment | $ 648,464,000 | 642,732,000 |
Accumulated Depreciation | $ (179,486,000) | (170,366,000) |
Ownership interest (as a percent) | 100.00% | |
Wansley | ||
Public Utility Property Plant and Equipment | ||
Investment | $ 3,887,000 | 3,887,000 |
Accumulated Depreciation | $ (3,626,000) | (3,552,000) |
Ownership interest (as a percent) | 30.00% | |
Transmission plant | ||
Public Utility Property Plant and Equipment | ||
Investment | $ 95,861,000 | 92,929,000 |
Accumulated Depreciation | (56,973,000) | (55,502,000) |
Other production | ||
Public Utility Property Plant and Equipment | ||
Investment | 93,503,000 | 92,179,000 |
Accumulated Depreciation | (56,193,000) | (54,927,000) |
Scherer Unit No. 2 | ||
Public Utility Property Plant and Equipment | ||
Investment | 776,316,000 | 757,957,000 |
Accumulated Depreciation | $ (447,391,000) | (414,867,000) |
Ownership interest (as a percent) | 60.00% | |
Environmental and other generation improvements | ||
Public Utility Property Plant and Equipment | ||
Total construction work in progress | $ 263,146,000 | 212,476,000 |
Other Construction Work In Progress | ||
Public Utility Property Plant and Equipment | ||
Total construction work in progress | $ 2,265,000 | $ 1,443,000 |
Electric plant, construction _4
Electric plant, construction and related agreements: - Construction (Details) | Mar. 15, 2019USD ($) | Sep. 30, 2018USD ($) | Dec. 31, 2018USD ($)item | Dec. 31, 2008itemMW | Sep. 30, 2017USD ($) | Sep. 28, 2017USD ($) | Feb. 20, 2014USD ($) |
Long-term debt | |||||||
Electric plant, construction and related agreements | |||||||
Ownership interests voting required to continue construction (as a percent) | 90.00% | ||||||
Maximum borrowing capacity | $ 4,676,749,167 | ||||||
Long-term debt | FFB | |||||||
Electric plant, construction and related agreements | |||||||
Maximum borrowing capacity | $ 4,676,749,167 | $ 1,619,679,706 | $ 3,057,069,461 | ||||
Aggregate Department of Energy-guaranteed borrowings | $ 1,794,723,000 | ||||||
Long-term debt | FFB | Maximum | Subsequent Event | |||||||
Electric plant, construction and related agreements | |||||||
Advances received on loans | $ 585,000,000 | ||||||
Global Amendments to Term Sheet | Long-term debt | |||||||
Electric plant, construction and related agreements | |||||||
Term of credit facility (in years) | 5 years | ||||||
Vogtle Units No. 3 & No. 4 | |||||||
Electric plant, construction and related agreements | |||||||
Number of additional nuclear units | item | 2 | ||||||
Ownership interest (as a percent) | 30.00% | ||||||
Number of petitions filed by parties | 2 | ||||||
Estimated additional costs of completion | $ 450,000,000 | ||||||
Estimated construction project-level contingency | 240,000,000 | ||||||
Capital market debt issuances | $ 1,887,000,000 | ||||||
Vogtle Units No. 3 & No. 4 | Long-term debt | FFB | |||||||
Electric plant, construction and related agreements | |||||||
Term of credit facility (in years) | 5 years | ||||||
Vogtle Units No. 3 & No. 4 | Ownership participation agreement | |||||||
Electric plant, construction and related agreements | |||||||
Project budget | $ 7,500,000,000 | ||||||
Estimated construction contingency | $ 500,000,000 | ||||||
Total investment in additional Vogtle units | $ 3,900,000,000 | ||||||
Vogtle Units No. 3 & No. 4 | Ownership participation agreement | Occurrence of certain adverse events | |||||||
Electric plant, construction and related agreements | |||||||
Project extension term | 1 year | ||||||
Vogtle Units No. 3 & No. 4 | Ownership participation agreement | Minimum | Occurrence of certain adverse events | |||||||
Electric plant, construction and related agreements | |||||||
Ownership interests voting required to continue construction (as a percent) | 90.00% | ||||||
Vogtle Units No. 3 & No. 4 | EPC Agreement | Westinghouse Electric Company LLC and Stone & Webster, Inc. | |||||||
Electric plant, construction and related agreements | |||||||
Number of nuclear units | item | 2 | ||||||
Generating capacity of each nuclear unit | MW | 1,100 | ||||||
Vogtle Units No. 3 & No. 4 | Services Agreement | Westinghouse Electric Company LLC and Stone & Webster, Inc. | |||||||
Electric plant, construction and related agreements | |||||||
Written notice period for termination of agreement | 30 days | ||||||
Vogtle Units No. 3 & No. 4 | Global Amendments to Term Sheet | |||||||
Electric plant, construction and related agreements | |||||||
Project budget | $ 8,400,000,000 | ||||||
Additional construction costs | $ 800,000,000 | ||||||
Percentage of number of Co-owners | 67.00% | ||||||
Vogtle Units No. 3 & No. 4 | Global Amendments to Term Sheet | Occurrence of certain adverse events | |||||||
Electric plant, construction and related agreements | |||||||
Percentage of costs disallowed for recovery | 6.00% | ||||||
Vogtle Units No. 3 & No. 4 | Global Amendments to Term Sheet | EAC exceeds by $800 million to $1.6 billion | |||||||
Electric plant, construction and related agreements | |||||||
Percentage of construction costs to be responsible by each Co-owner | 24.50% | ||||||
Vogtle Units No. 3 & No. 4 | Global Amendments to Term Sheet | EAC exceeds by $1.6 billion to $2.1 billion | |||||||
Electric plant, construction and related agreements | |||||||
Percentage of construction costs to be responsible by each Co-owner | 19.00% | ||||||
Vogtle Units No. 3 & No. 4 | Global Amendments to Term Sheet | Minimum | Occurrence of certain adverse events | |||||||
Electric plant, construction and related agreements | |||||||
Ownership interests voting required to continue construction (as a percent) | 90.00% | ||||||
Ownership approval to change primary construction contractor (as a percent) | 90.00% | ||||||
Ownership approval required for material amendments (as a percent) | 67.00% | ||||||
Vogtle Units No. 3 & No. 4 | Global Amendments to Term Sheet | Minimum | EAC exceeds by $800 million to $1.6 billion | |||||||
Electric plant, construction and related agreements | |||||||
Additional construction costs exceeds EAC | $ 800,000,000 | ||||||
Vogtle Units No. 3 & No. 4 | Global Amendments to Term Sheet | Minimum | EAC exceeds by $1.6 billion to $2.1 billion | |||||||
Electric plant, construction and related agreements | |||||||
Additional construction costs exceeds EAC | 1,600,000,000 | ||||||
Vogtle Units No. 3 & No. 4 | Global Amendments to Term Sheet | Minimum | EAC exceeds more than $2.1 billion | |||||||
Electric plant, construction and related agreements | |||||||
Additional construction costs exceeds EAC | 2,100,000,000 | ||||||
Vogtle Units No. 3 & No. 4 | Global Amendments to Term Sheet | Maximum | EAC exceeds by $800 million to $1.6 billion | |||||||
Electric plant, construction and related agreements | |||||||
Additional construction costs exceeds EAC | 1,600,000,000 | ||||||
Construction costs savings | 44,000,000 | ||||||
Vogtle Units No. 3 & No. 4 | Global Amendments to Term Sheet | Maximum | EAC exceeds by $1.6 billion to $2.1 billion | |||||||
Electric plant, construction and related agreements | |||||||
Additional construction costs exceeds EAC | 2,100,000,000 | ||||||
Construction costs savings | 55,000,000 | ||||||
Co-owners | Vogtle Units No. 3 & No. 4 | |||||||
Electric plant, construction and related agreements | |||||||
Estimated additional costs of completion | 1,500,000,000 | ||||||
Estimated construction project-level contingency | $ 800,000,000 | ||||||
Georgia Power | Vogtle Units No. 3 & No. 4 | Global Amendments to Term Sheet | EAC exceeds by $800 million to $1.6 billion | |||||||
Electric plant, construction and related agreements | |||||||
Percentage of construction costs to be responsible by each Co-owner | 55.70% | ||||||
Georgia Power | Vogtle Units No. 3 & No. 4 | Global Amendments to Term Sheet | EAC exceeds by $1.6 billion to $2.1 billion | |||||||
Electric plant, construction and related agreements | |||||||
Percentage of construction costs to be responsible by each Co-owner | 65.70% | ||||||
Georgia Power | Vogtle Units No. 3 & No. 4 | Global Amendments to Term Sheet | EAC exceeds more than $2.1 billion | |||||||
Electric plant, construction and related agreements | |||||||
Percentage of construction costs to be responsible by each Co-owner | 100.00% | ||||||
Georgia Power | Vogtle Units No. 3 & No. 4 | Global Amendments to Term Sheet | Actual cost at completion less than EAC | |||||||
Electric plant, construction and related agreements | |||||||
Percentage of cost savings entitled | 60.70% | ||||||
Georgia Power | Vogtle Units No. 3 & No. 4 | Global Amendments to Term Sheet | Maximum | EAC exceeds by $800 million to $1.6 billion | |||||||
Electric plant, construction and related agreements | |||||||
Potential Additional Costs | $ 80,000,000 | ||||||
Georgia Power | Vogtle Units No. 3 & No. 4 | Global Amendments to Term Sheet | Maximum | EAC exceeds by $1.6 billion to $2.1 billion | |||||||
Electric plant, construction and related agreements | |||||||
Potential Additional Costs | $ 100,000,000 | ||||||
Co-owners excluding Georgia Power | Global Amendments to Term Sheet | Actual cost at completion less than EAC | |||||||
Electric plant, construction and related agreements | |||||||
Percentage of cost savings entitled | 39.30% | ||||||
Co-owners excluding Georgia Power | Vogtle Units No. 3 & No. 4 | Global Amendments to Term Sheet | EAC exceeds by $800 million to $1.6 billion | |||||||
Electric plant, construction and related agreements | |||||||
Percentage of construction costs to be responsible by each Co-owner | 44.30% | ||||||
Co-owners excluding Georgia Power | Vogtle Units No. 3 & No. 4 | Global Amendments to Term Sheet | EAC exceeds by $1.6 billion to $2.1 billion | |||||||
Electric plant, construction and related agreements | |||||||
Percentage of construction costs to be responsible by each Co-owner | 34.30% |
Employee benefit plans_ (Detail
Employee benefit plans: (Details) | 12 Months Ended | ||
Dec. 31, 2018USD ($)item | Dec. 31, 2017USD ($)item | Dec. 31, 2016USD ($) | |
401(k) plan | |||
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 | $ 1,497,000 | $ 1,436,000 | $ 1,371,000 |
Contribution to employer retirement contribution feature (as a percent) | 11.00% | ||
Amount of contributions to the employer retirement contribution feature of the 401(k) plan | $ 3,903,000 | $ 3,791,000 | $ 3,678,000 |
Deferred compensation plans | |||
Number of deferred compensation plans | item | 2 | 2 | |
Deferred compensation plan assets | $ 2,387,000 | $ 2,145,000 | |
Deferred compensation liability | $ 2,387,000 | $ 2,145,000 |
Nuclear insurance_ (Details)
Nuclear insurance: (Details) | 12 Months Ended |
Dec. 31, 2018USD ($)item | |
Nuclear insurance: | |
Maximum fund for public liability claims arising from a single nuclear incident under Price-Anderson Act | $ 14,100,000,000 |
Maximum insurance coverage provided by American Nuclear Insurers to each nuclear plant | 450,000,000 |
Maximum amount that a company could be assessed per incident for each licensed reactor | 138,000,000 |
Maximum aggregate amount that a reactor can assess in a calendar period for each incident | $ 20,000,000 |
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 | $ 165,000,000 |
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 | $ 25,000,000 |
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 | 42,000,000 |
Aggregate payment for claims resulting from terrorist acts in one year period | $ 3,200,000,000 |
Commitments_ - Operating Leases
Commitments: - Operating Leases (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Operating leases | |||
2019 | $ 3,730,000 | ||
2020 | 1,413,000 | ||
2021 | 798,000 | ||
2022 | 608,000 | ||
2023 | 386,000 | ||
Thereafter | 1,157,000 | ||
Rental expenses | $ 4,562,000 | $ 4,919,000 | $ 4,456,000 |
Commitments_ - Fuel (Details)
Commitments: - Fuel (Details) | 12 Months Ended |
Dec. 31, 2018USD ($) | |
Coal | |
Fuel | |
2019 | $ 22,065,000 |
2020 | 7,091,000 |
2021 | 2,348,000 |
Nuclear Fuel | |
Fuel | |
2019 | 49,100,000 |
2020 | 27,500,000 |
2021 | 30,300,000 |
2022 | 25,400,000 |
2023 | 18,400,000 |
Thereafter | 35,100,000 |
Gas Transportation | |
Fuel | |
2019 | 64,497,000 |
2020 | 63,260,000 |
2021 | 62,737,000 |
2022 | 53,796,000 |
2023 | 47,513,000 |
Thereafter | 848,609,000 |
Maintenance Agreements | |
Fuel | |
2019 | 29,510,000 |
2020 | 53,911,000 |
2021 | 14,461,000 |
2022 | 14,929,000 |
2023 | 3,330,000 |
Thereafter | 281,938,000 |
Cancellation obligation | 80,000,000 |
Asset Retirement Obligations | |
Fuel | |
2019 | 8,664,000 |
2020 | 11,274,000 |
2021 | 11,215,000 |
2022 | 11,200,000 |
2023 | 37,743,000 |
Thereafter | $ 3,536,362,000 |
Quarterly financial data (una_3
Quarterly financial data (unaudited): (Details) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018USD ($) | Sep. 30, 2018USD ($) | Jun. 30, 2018USD ($) | Mar. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Sep. 30, 2017USD ($) | Jun. 30, 2017USD ($) | Mar. 31, 2017USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | |
Operating revenues | $ 355,902 | $ 384,644 | $ 365,921 | $ 373,646 | $ 342,001 | $ 376,656 | $ 361,369 | $ 354,170 | |||
Operating margin | 39,351 | 54,845 | 60,849 | 69,931 | 46,548 | 59,520 | 63,472 | 69,330 | $ 224,976 | $ 238,870 | $ 255,664 |
Net margin | $ (4,820) | $ 11,334 | $ 17,285 | $ 27,400 | $ 2,592 | $ 11,555 | $ 15,676 | $ 21,454 | $ 51,199 | $ 51,277 | $ 50,345 |
Targeted margins for interest ratio | 1.14 | 1.14 | |||||||||
Maximum | |||||||||||
Targeted margins for interest ratio | 1.14 |