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TABLE OF CONTENTS
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One) | ||
ý | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
For the quarterly period ended | ||
OR | ||
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
For the transition period from to |
Commission File No. 000-53908
(An Electric Membership Corporation)
(Exact name of registrant as specified in its charter)
Georgia (State or other jurisdiction of incorporation or organization) | 58-1211925 (I.R.S. employer identification no.) | |
2100 East Exchange Place Tucker, Georgia (Address of principal executive offices) | 30084-5336 (Zip Code) | |
Registrant's telephone number, including area code | (770) 270-7600 |
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ýo No oý
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company or an emerging growth company. See definitions of "large accelerated filer," "accelerated filer," and "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated Filer o Accelerated Filer o Non-Accelerated Filer ý (Do not check if a smaller reporting company) Smaller Reporting Company oEmerging Growth Company o
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý
Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.The registrant is a membership corporation and has no authorized or outstanding equity securities.
(This page has been left blank intentionally)
OGLETHORPE POWER CORPORATION
INDEX TO QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30, 2016MARCH 31, 2017
| | Page No. | ||
---|---|---|---|---|
PART I—FINANCIAL INFORMATION | ||||
Item 1. | Financial Statements | 1 | ||
Unaudited Consolidated Balance Sheets as of | 1 | |||
Unaudited Consolidated Statements of Revenues and Expenses For the Three | 3 | |||
Unaudited Consolidated Statements of Comprehensive Margin For the Three | 4 | |||
Unaudited Consolidated Statements of Patronage Capital and Membership Fees and Accumulated Other Comprehensive (Deficit) Margin For the | 5 | |||
Unaudited Consolidated Statements of Cash Flows For the | 6 | |||
Notes to Unaudited Consolidated Financial Statements | 7 | |||
Item 2. | Management's Discussion and Analysis of Financial Condition and Results of Operations | |||
Item 3. | Quantitative and Qualitative Disclosures About Market Risk | |||
Item 4. | Controls and Procedures | |||
PART II—OTHER INFORMATION | ||||
Item 1. | Legal Proceedings | |||
Item 1A. | Risk Factors | |||
Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds | 35 | ||
Item 3. | Defaults Upon Senior Securities | 35 | ||
Item 4. | Mine Safety Disclosures | 35 | ||
Item 5. | Other Information | 35 | ||
Item 6. | Exhibits | 35 | ||
SIGNATURES |
i
CAUTIONARY STATEMENT REGARDING
FORWARD-LOOKING STATEMENTS
This quarterly report on Form 10-Q contains "forward-looking statements." All statements, other than statements of historical facts, that address activities, events or developments that we expect or anticipate to occur in the future, including matters such as the timing of various regulatory and other actions, future capital expenditures, business strategy and development, construction or operation of facilities (often, but not always, identified through the use of words or phrases such as "will likely result," "are expected to," "will continue," "is anticipated," "estimated," "projection," "target" and "outlook") are forward-looking statements.
Although we believe that in making these forward-looking statements our expectations are based on reasonable assumptions, any forward-looking statement involves uncertainties and there are important factors that could cause actual results to differ materially from those expressed or implied by these forward-looking statements. Some of the risks, uncertainties and assumptions that may cause actual results to differ from these forward-looking statements are described under "Item 1A—RISK FACTORS" and in other sections of our annual report on Form 10-K for the fiscal year ended December 31, 20152016 and in this quarterly report on Form 10-Q. In light of these risks, uncertainties and assumptions, the forward-looking events and circumstances discussed in this quarterly report may not occur.
Any forward-looking statement speaks only as of the date of this quarterly report, and, except as required by law, we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for us to predict all of them; nor can we assess the impact of each factor or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. Factors that could cause actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:
ii
ii
iii
Oglethorpe Power Corporation |
(dollars in thousands) | (dollars in thousands) | |||||||||||||
2016 | 2015 | 2017 | 2016 | |||||||||||
Assets | ||||||||||||||
Electric plant: | ||||||||||||||
In service | $ | 8,752,591 | $ | 8,596,148 | $ | 8,805,272 | $ | 8,786,839 | ||||||
Less: Accumulated provision for depreciation | (4,069,257 | ) | (3,925,838 | ) | (4,164,233 | ) | (4,115,339 | ) | ||||||
| | | | | | | | | | | | | | |
4,683,334 | 4,670,310 | 4,641,039 | 4,671,500 | |||||||||||
Nuclear fuel, at amortized cost | 366,698 | 373,145 | 377,593 | 377,653 | ||||||||||
Construction work in progress | 3,126,508 | 2,868,669 | 3,401,701 | 3,228,214 | ||||||||||
| | | | | | | | | | | | | | |
8,176,540 | 7,912,124 | |||||||||||||
Total electric plant | 8,420,333 | 8,277,367 | ||||||||||||
| | | | | | | | | | | | | | |
Investments and funds: | ||||||||||||||
Nuclear decommissioning trust fund | 386,205 | 363,829 | 400,022 | 386,029 | ||||||||||
Investment in associated companies | 72,163 | 72,010 | 73,503 | 72,783 | ||||||||||
Long-term investments | 99,701 | 86,771 | 106,444 | 99,874 | ||||||||||
Restricted cash and investments | 201,511 | 134,690 | ||||||||||||
Restricted investments | 184,132 | 221,122 | ||||||||||||
Other | 20,002 | 19,097 | 21,045 | 20,730 | ||||||||||
| | | | | | | | | | | | | | |
779,582 | 676,397 | |||||||||||||
Total investments and funds | 785,146 | 800,538 | ||||||||||||
| | | | | | | | | | | | | | |
Current assets: | ||||||||||||||
Cash and cash equivalents | 362,708 | 213,038 | 278,551 | 366,290 | ||||||||||
Restricted short-term investments | 249,685 | 253,204 | 247,009 | 247,006 | ||||||||||
Receivables | 173,782 | 130,464 | 149,359 | 155,042 | ||||||||||
Inventories, at average cost | 253,526 | 299,252 | 271,859 | 259,831 | ||||||||||
Prepayments and other current assets | 18,852 | 16,913 | 24,181 | 32,919 | ||||||||||
| | | | | | | | | | | | | | |
1,058,553 | 912,871 | |||||||||||||
Total current assets | 970,959 | 1,061,088 | ||||||||||||
| | | | | | | | | | | | | | |
Deferred charges: | ||||||||||||||
Regulatory assets | 542,057 | 530,254 | 564,314 | 545,387 | ||||||||||
Other | 25,031 | 28,137 | 15,476 | 16,733 | ||||||||||
| | | | | | | | | | | | | | |
567,088 | 558,391 | |||||||||||||
Total deferred charges | 579,790 | 562,120 | ||||||||||||
| | | | | | | | | | | | | | |
$ | 10,581,763 | $ | 10,059,783 | |||||||||||
Total assets | $ | 10,756,228 | $ | 10,701,113 | ||||||||||
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements.
Oglethorpe Power Corporation |
(dollars in thousands) | (dollars in thousands) | |||||||||||||
2016 | 2015 | 2017 | 2016 | |||||||||||
Equity and Liabilities | ||||||||||||||
Capitalization: | ||||||||||||||
Patronage capital and membership fees | $ | 871,970 | $ | 809,465 | $ | 881,264 | $ | 859,810 | ||||||
Accumulated other comprehensive margin | 416 | 58 | (409 | ) | (370 | ) | ||||||||
| | | | | | | | | | | | | | |
872,386 | 809,523 | 880,855 | 859,440 | |||||||||||
Long-term debt | 7,885,428 | 7,291,154 | 7,876,337 | 7,892,836 | ||||||||||
Obligation under capital lease | 94,358 | 96,501 | 92,096 | 92,096 | ||||||||||
Other | 18,459 | 17,561 | 19,081 | 18,765 | ||||||||||
| | | | | | | | | | | | | | |
8,870,631 | 8,214,739 | |||||||||||||
Total capitalization | 8,868,369 | 8,863,137 | ||||||||||||
| | | | | | | | | | | | | | |
Current liabilities: | ||||||||||||||
Long-term debt and capital lease due within one year | 153,274 | 189,840 | 153,305 | 316,861 | ||||||||||
Short-term borrowings | 156,253 | 261,478 | 328,890 | 102,168 | ||||||||||
Accounts payable | 69,613 | 157,432 | 93,300 | 73,801 | ||||||||||
Accrued interest | 57,864 | 58,830 | 58,342 | 93,634 | ||||||||||
Member power bill prepayments, current | 168,705 | 174,743 | 173,705 | 176,988 | ||||||||||
Other current liabilities | 58,613 | 86,746 | 42,713 | 59,979 | ||||||||||
| | | | | | | | | | | | | | |
664,322 | 929,069 | |||||||||||||
Total current liabilities | 850,255 | 823,431 | ||||||||||||
| | | | | | | | | | | | | | |
Deferred credits and other liabilities: | ||||||||||||||
Asset retirement obligations | 698,240 | 602,230 | 706,913 | 698,051 | ||||||||||
Member power bill prepayments, non-current | 83,052 | 44,205 | 53,115 | 48,115 | ||||||||||
Contract retainage | 39,551 | 66,515 | 40,374 | 40,008 | ||||||||||
Regulatory liabilities | 193,156 | 166,967 | 205,603 | 197,748 | ||||||||||
Other | 32,811 | 36,058 | 31,599 | 30,623 | ||||||||||
| | | | | | | | | | | | | | |
1,046,810 | 915,975 | |||||||||||||
Total deferred credits and other liabilities | 1,037,604 | 1,014,545 | ||||||||||||
| | | | | | | | | | | | | | |
$ | 10,581,763 | $ | 10,059,783 | |||||||||||
Total equity and liabilities | $ | 10,756,228 | $ | 10,701,113 | ||||||||||
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements.
Oglethorpe Power Corporation |
(dollars in thousands) | (dollars in thousands) | |||||||||||||||||||
Three Months | Nine Months | Three Months | ||||||||||||||||||
2016 | 2015 | 2016 | 2015 | 2017 | 2016 | |||||||||||||||
Operating revenues: | ||||||||||||||||||||
Sales to Members | $ | 430,883 | $ | 318,123 | $ | 1,158,134 | $ | 938,047 | $ | 354,144 | $ | 348,097 | ||||||||
Sales to non-Members | 130 | 50,541 | 383 | 114,136 | 26 | 64 | ||||||||||||||
| | | | | | | | | | | | | | | | | | | | |
Total operating revenues | 431,013 | 368,664 | 1,158,517 | 1,052,183 | 354,170 | 348,161 | ||||||||||||||
| | | | | | | | | | | | | | | | | | | | |
Operating expenses: | ||||||||||||||||||||
Fuel | 178,516 | 142,142 | 404,056 | 365,762 | 103,915 | 98,952 | ||||||||||||||
Production | 105,681 | 94,504 | 312,332 | 337,632 | 101,088 | 103,471 | ||||||||||||||
Depreciation and amortization | 54,719 | 42,484 | 162,606 | 128,088 | 55,863 | 53,486 | ||||||||||||||
Purchased power | 13,109 | 13,737 | 39,254 | 41,980 | 14,976 | 13,143 | ||||||||||||||
Accretion | 8,059 | 6,676 | 24,099 | 19,535 | 8,998 | 8,016 | ||||||||||||||
Deferral of Hawk Road and Smith Energy Facilities effect on net margin | — | (166 | ) | — | (41,855 | ) | ||||||||||||||
| | | | | | | | | | | | | | | | | | | | |
Total operating expenses | 360,084 | 299,377 | 942,347 | 851,142 | 284,840 | 277,068 | ||||||||||||||
| | | | | | | | | | | | | | | | | | | | |
Operating margin | 70,929 | 69,287 | 216,170 | 201,041 | 69,330 | 71,093 | ||||||||||||||
| | | | | | | | | | | | | | | | | | | | |
Other income: | ||||||||||||||||||||
Investment income | 12,578 | 9,816 | 37,628 | 29,850 | 14,819 | 12,323 | ||||||||||||||
Other | 1,531 | 2,227 | 6,259 | 7,527 | 640 | 2,301 | ||||||||||||||
| | | | | | | | | | | | | | | | | | | | |
Total other income | 14,109 | 12,043 | 43,887 | 37,377 | 15,459 | 14,624 | ||||||||||||||
| | | | | | | | | | | | | | | | | | | | |
Interest charges: | ||||||||||||||||||||
Interest expense | 93,544 | 89,322 | 273,066 | 265,161 | 93,285 | 88,517 | ||||||||||||||
Allowance for debt funds used during construction | (30,135 | ) | (27,739 | ) | (84,460 | ) | (80,691 | ) | (33,087 | ) | (26,380 | ) | ||||||||
Amortization of debt discount and expense | 2,999 | 3,839 | 8,946 | 11,819 | 3,137 | 2,982 | ||||||||||||||
| | | | | | | | | | | | | | | | | | | | |
Net interest charges | 66,408 | 65,422 | 197,552 | 196,289 | 63,335 | 65,119 | ||||||||||||||
| | | | | | | | | | | | | | | | | | | | |
Net margin | $ | 18,630 | $ | 15,908 | $ | 62,505 | $ | 42,129 | $ | 21,454 | $ | 20,598 | ||||||||
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements.
Oglethorpe Power Corporation |
(dollars in thousands) | (dollars in thousands) | |||||||||||||||||||
Three Months | Nine Months | Three Months | ||||||||||||||||||
2016 | 2015 | 2016 | 2015 | 2017 | 2016 | |||||||||||||||
Net margin | $ | 18,630 | $ | 15,908 | $ | 62,505 | $ | 42,129 | $ | 21,454 | $ | 20,598 | ||||||||
| | | | | | | | | | | | | | | | | | | | |
Other comprehensive margin: | ||||||||||||||||||||
Unrealized (loss) gain on available-for-sale securities | (19 | ) | (95 | ) | 358 | (267 | ) | (39 | ) | 284 | ||||||||||
| | | | | | | | | | | | | | | | | | | | |
Total comprehensive margin | $ | 18,611 | $ | 15,813 | $ | 62,863 | $ | 41,862 | $ | 21,415 | $ | 20,882 | ||||||||
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements.
(dollars in thousands) | (dollars in thousands) | |||||||||||||||||||
Patronage Capital and Membership Fees | Accumulated Other Comprehensive Margin | Total | Patronage Capital and Membership Fees | Accumulated Other Comprehensive (Deficit) Margin | Total | |||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Balance at December 31, 2014 | $ | 761,124 | $ | 468 | $ | 761,592 | ||||||||||||||
| | | | | | | | | | |||||||||||
Components of comprehensive margin: | ||||||||||||||||||||
Net margin | 42,129 | — | 42,129 | |||||||||||||||||
Unrealized loss on available-for-sale securities | — | (267 | ) | (267 | ) | |||||||||||||||
| | | | | | | | | | |||||||||||
Balance at September 30, 2015 | $ | 803,253 | $ | 201 | $ | 803,454 | ||||||||||||||
| | | | | | | | | | |||||||||||
| | | | | | | ||||||||||||||
| | | | | | | | | | |||||||||||
Balance at December 31, 2015 | $ | 809,465 | $ | 58 | $ | 809,523 | $ | 809,465 | $ | 58 | $ | 809,523 | ||||||||
| | | | | | | | | | | | | | | | | | | ||
Components of comprehensive margin: | ||||||||||||||||||||
Net margin | 62,505 | — | 62,505 | 20,598 | — | 20,598 | ||||||||||||||
Unrealized gain on available-for-sale securities | — | 358 | 358 | — | 284 | 284 | ||||||||||||||
| | | | | | | | | | | | | | | | | | | | |
Balance at September 30, 2016 | $ | 871,970 | $ | 416 | $ | 872,386 | ||||||||||||||
Balance at March 31, 2016 | $ | 830,063 | $ | 342 | $ | 830,405 | ||||||||||||||
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Balance at December 31, 2016 | $ | 859,810 | $ | (370 | ) | $ | 859,440 | |||||||||||||
| | | | | | | | | | | ||||||||||
Components of comprehensive margin: | ||||||||||||||||||||
Net margin | 21,454 | — | 21,454 | |||||||||||||||||
Unrealized loss on available-for-sale securities | — | (39 | ) | (39 | ) | |||||||||||||||
| | | | | | | | | | | ||||||||||
Balance at March 31, 2017 | $ | 881,264 | $ | (409 | ) | $ | 880,855 | |||||||||||||
| | | | | | | | | | | ||||||||||
| | | | | | | | |||||||||||||
| | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements.
Oglethorpe Power Corporation |
(dollars in thousands) | (dollars in thousands) | |||||||||||||
2016 | 2015 | 2017 | 2016 | |||||||||||
Cash flows from operating activities: | ||||||||||||||
Net margin | $ | 62,505 | $ | 42,129 | $ | 21,454 | $ | 20,598 | ||||||
| | | | | | | | | | | | | | |
Adjustments to reconcile net margin to net cash provided by operating activities: | ||||||||||||||
Depreciation and amortization, including nuclear fuel | 268,674 | 234,362 | 92,049 | 87,413 | ||||||||||
Accretion cost | 24,099 | 19,535 | 8,998 | 8,016 | ||||||||||
Amortization of deferred gains | (1,341 | ) | (1,341 | ) | (447 | ) | (447 | ) | ||||||
Allowance for equity funds used during construction | (567 | ) | (506 | ) | (193 | ) | (177 | ) | ||||||
Deferred outage costs | (29,464 | ) | (25,060 | ) | (19,385 | ) | (24,869 | ) | ||||||
Deferral of Hawk Road and Smith Energy Facilities effect on net margin | — | (41,855 | ) | |||||||||||
Gain on sale of investments | (653 | ) | (34,121 | ) | ||||||||||
(Gain) loss on sale of investments | (16,045 | ) | 849 | |||||||||||
Regulatory deferral of costs associated with nuclear decommissioning | (14,522 | ) | 24,339 | 10,602 | (5,814 | ) | ||||||||
Other | (4,424 | ) | (5,076 | ) | (3,138 | ) | (1,685 | ) | ||||||
Change in operating assets and liabilities: | ||||||||||||||
Receivables | (41,015 | ) | (4,786 | ) | 6,241 | 4,044 | ||||||||
Inventories | 30,251 | (19,942 | ) | (12,028 | ) | 5,253 | ||||||||
Prepayments and other current assets | (1,305 | ) | (4,650 | ) | 3,822 | 273 | ||||||||
Accounts payable | (87,056 | ) | (45,068 | ) | (18,028 | ) | (39,787 | ) | ||||||
Accrued interest | (966 | ) | (5,774 | ) | (35,292 | ) | (5,528 | ) | ||||||
Accrued taxes | 5,348 | 10,099 | (12,909 | ) | (13,160 | ) | ||||||||
Other current liabilities | (20,604 | ) | (9,006 | ) | (7,059 | ) | (9,777 | ) | ||||||
Member power bill prepayments | 32,809 | 27,672 | 1,717 | (6,779 | ) | |||||||||
| | | | | | | | | | | | | | |
Total adjustments | 159,264 | 118,822 | (1,095 | ) | (2,175 | ) | ||||||||
| | | | | | | | | | | | | | |
Net cash provided by operating activities | 221,769 | 160,951 | 20,359 | 18,423 | ||||||||||
| | | | | | | | | | | | | | |
Cash flows from investing activities: | ||||||||||||||
Property additions | (421,384 | ) | (335,217 | ) | (171,806 | ) | (259,447 | ) | ||||||
Activity in nuclear decommissioning trust fund—Purchases | (307,222 | ) | (463,544 | ) | (165,213 | ) | (129,886 | ) | ||||||
—Proceeds | 302,308 | 460,171 | 163,635 | 128,179 | ||||||||||
Increase in restricted cash and investments | (66,821 | ) | (23,230 | ) | ||||||||||
Decrease (increase) in restricted short-term investments | 3,519 | (5,893 | ) | |||||||||||
Decrease (increase) in restricted cash and investments | 36,990 | (9,419 | ) | |||||||||||
(Increase) decrease in restricted short-term investments | (3 | ) | 2,663 | |||||||||||
Activity in other long-term investments—Purchases | (44,457 | ) | (48,461 | ) | (18,190 | ) | (14,267 | ) | ||||||
—Proceeds | 35,278 | 49,075 | 14,093 | 11,639 | ||||||||||
Other | 2,401 | (6,239 | ) | (1,658 | ) | 3,147 | ||||||||
| | | | | | | | | | | | | | |
Net cash used in investing activities | (496,378 | ) | (373,338 | ) | (142,152 | ) | (267,391 | ) | ||||||
| | | | | | | | | | | | | | |
Cash flows from financing activities: | ||||||||||||||
Long-term debt proceeds | 634,279 | 289,910 | 4,517 | 7,998 | ||||||||||
Long-term debt payments | (113,328 | ) | (124,138 | ) | (201,398 | ) | (36,677 | ) | ||||||
(Decrease) increase in short-term borrowings, net | (105,225 | ) | 90,132 | |||||||||||
Increase in short-term borrowings, net | 226,722 | 171,280 | ||||||||||||
Other | 8,553 | 2,628 | 4,213 | 4,422 | ||||||||||
| | | | | | | | | | | | | | |
Net cash provided by financing activities | 424,279 | 258,532 | 34,054 | 147,023 | ||||||||||
| | | | | | | | | | | | | | |
Net increase in cash and cash equivalents | 149,670 | 46,145 | ||||||||||||
Net decrease in cash and cash equivalents | (87,739 | ) | (101,945 | ) | ||||||||||
Cash and cash equivalents at beginning of period | 213,038 | 237,391 | 366,290 | 213,038 | ||||||||||
| | | | | | | | | | | | | | |
Cash and cash equivalents at end of period | $ | 362,708 | $ | 283,536 | $ | 278,551 | $ | 111,093 | ||||||
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
Supplemental cash flow information: | ||||||||||||||
Cash paid for— | ||||||||||||||
Interest (net of amounts capitalized) | $ | 185,484 | $ | 186,651 | $ | 94,754 | $ | 66,950 | ||||||
Supplemental disclosure of non-cash investing and financing activities: | ||||||||||||||
Change in asset retirement obligations | $ | 72,097 | $ | 17,390 | $ | — | $ | (10,425 | ) | |||||
Change in accrued property additions | $ | (24,451 | ) | $ | 8,984 | $ | 40,259 | $ | (79,336 | ) | ||||
Interest paid-in-kind | $ | 34,587 | $ | 26,116 | $ | 13,909 | $ | 10,606 |
The accompanying notes are an integral part of these consolidated financial statements.
Oglethorpe Power Corporation
Notes to Unaudited Consolidated Financial Statements
For the nine-month period ended September 30, 2015, we made an adjustment of $26,116,000 to the Consolidated Statement of Cash Flows decreasing other adjustments to reconcile net margin to net cash provided by operating activities and decreasing cash paid for property additions. This adjustment reflects the non-cash nature of the allowance for debt funds used during construction related to interest paid-in-kind associated with loans under our Department of Energy Loan Guarantee. The change properly reflects an immaterial adjustment to cash flows provided by operations and cash used in investing activities, and is consistent with the presentation beginning with the statement of cash flows for the year ended December 31, 2015.
These consolidated financial statements should be read in conjunction with the financial statements and the notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015,2016, as filed with the SEC. The results of operations for the three-month and nine-month periodsperiod ended September 30, 2016March 31, 2017 are not necessarily indicative of results to be expected for the full year. As noted in our 20152016 Form 10-K, our revenues consist primarily of sales to our 38 electric distribution cooperative members and, thus, the receivables on the consolidated balance sheets are principally from our members. (See "Notes to Consolidated Financial Statements" in our 20152016 Form 10-K.)
The guidance establishes a three-tier fair value hierarchy which prioritizes the inputs used in measuring fair value as follows:
As required by the guidance, assets and liabilities measured at fair value are based on one or more of the following three valuation techniques:
1. Market approach. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities (including a business) and deriving fair value based on these inputs.
2. Income approach. The income approach uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts.
3. Cost approach. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (often referred to as current replacement cost). This approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset or comparable utility, adjusted for obsolescence.
The tables below detail assets and liabilities measured at fair value on a recurring basis at September 30, 2016March 31, 2017 and December 31, 2015.2016.
| | | | | | | | | | | | | | | | | | | | | | | | | ||
Fair Value Measurements at Reporting Date Using | Fair Value Measurements at Reporting Date Using | |||||||||||||||||||||||||
September 30, | Quoted Prices in | Significant Other | Significant | March 31, | Quoted Prices in | Significant Other | Significant | |||||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | ||
(dollars in thousands) | (dollars in thousands) | |||||||||||||||||||||||||
Nuclear decommissioning trust funds: | ||||||||||||||||||||||||||
Domestic equity | $ | 163,202 | $ | 163,202 | $ | — | $ | — | $ | 128,483 | $ | 128,483 | $ | — | $ | — | ||||||||||
International equity trust | 70,475 | — | 70,475 | — | 70,815 | — | 70,815 | — | ||||||||||||||||||
Corporate bonds | 48,943 | — | 48,943 | — | 67,336 | — | 67,336 | — | ||||||||||||||||||
US Treasury and government agency securities | 72,798 | 72,798 | — | — | 68,026 | 68,026 | — | — | ||||||||||||||||||
Agency mortgage and asset backed securities | 22,395 | — | 22,395 | — | 18,157 | — | 18,157 | — | ||||||||||||||||||
Mutual funds | 44,172 | 44,172 | — | — | ||||||||||||||||||||||
Municipal bonds | 404 | — | 404 | — | 313 | — | 313 | — | ||||||||||||||||||
Other | 7,988 | 7,988 | — | — | 2,720 | 2,720 | — | — | ||||||||||||||||||
Long-term investments: | ||||||||||||||||||||||||||
International equity trust | 15,573 | — | 15,573 | — | 16,895 | — | 16,895 | — | ||||||||||||||||||
Corporate bonds | 11,395 | — | 11,395 | — | 14,145 | — | 14,145 | — | ||||||||||||||||||
US Treasury and government agency securities | 13,037 | 13,037 | — | — | 11,849 | 11,849 | — | — | ||||||||||||||||||
Agency mortgage and asset backed securities | 1,825 | — | 1,825 | — | 1,386 | — | 1,386 | — | ||||||||||||||||||
Mutual funds | 57,462 | 57,462 | — | — | 62,169 | 62,169 | — | — | ||||||||||||||||||
Other | 409 | 409 | — | — | ||||||||||||||||||||||
Interest rate options | — | — | — | — | ||||||||||||||||||||||
Natural gas swaps | 2,823 | — | 2,823 | — | (4,968 | ) | — | (4,968 | ) | — | ||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | |
Fair Value Measurements at Reporting Date Using | Fair Value Measurements at Reporting Date Using | |||||||||||||||||||||||||
December 31, | Quoted Prices in | Significant Other | Significant | December 31, | Quoted Prices in | Significant Other | Significant | |||||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
(dollars in thousands) | (dollars in thousands) | |||||||||||||||||||||||||
Nuclear decommissioning trust funds: | ||||||||||||||||||||||||||
Domestic equity | $ | 151,178 | $ | 151,178 | $ | — | $ | — | $ | 170,408 | $ | 170,408 | $ | — | $ | — | ||||||||||
International equity trust | 68,753 | — | 68,753 | — | 66,861 | — | 66,861 | — | ||||||||||||||||||
Corporate bonds | 48,450 | — | 48,450 | — | 60,019 | — | 60,019 | — | ||||||||||||||||||
US Treasury and government agency securities | 75,173 | 74,698 | 475 | — | 65,725 | 65,725 | — | — | ||||||||||||||||||
Agency mortgage and asset backed securities | 15,503 | — | 15,503 | — | 17,410 | — | 17,410 | — | ||||||||||||||||||
Municipal bonds | 943 | — | 943 | |||||||||||||||||||||||
Other | 4,772 | 4,772 | — | — | 4,663 | 4,663 | — | — | ||||||||||||||||||
Long-term investments: | ||||||||||||||||||||||||||
Corporate bonds | 9,903 | — | 9,903 | — | 11,853 | — | 11,853 | — | ||||||||||||||||||
US Treasury and government agency securities | 13,772 | 13,772 | — | — | 12,187 | 12,187 | — | — | ||||||||||||||||||
Agency mortgage and asset backed securities | 1,121 | — | 1,121 | — | 1,651 | — | 1,651 | — | ||||||||||||||||||
International equity trust | 12,846 | — | 12,846 | — | 15,946 | — | 15,946 | — | ||||||||||||||||||
Mutual funds | 48,649 | 48,649 | — | — | 57,932 | 57,932 | — | — | ||||||||||||||||||
Other | 479 | 479 | — | — | 305 | 305 | — | — | ||||||||||||||||||
Interest rate options | 1,010 | — | — | 1,010 | ||||||||||||||||||||||
Natural gas swaps | 24,995 | — | 24,995 | — | (15,090 | ) | — | (15,090 | ) | — | ||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | |
The Level 2 investments above in corporate bonds and agency mortgage and asset backed securities may not be exchange traded. The fair value measurements for these investments are based on a market approach, including the use of observable inputs. Common inputs include reported trades and broker/dealer bid/ask prices. The fair value of the Level 2 investments above in international equity trust are calculated based on the net asset value per share of the fund. There are no unfunded commitments for the international equity trust and redemption may occur daily with a 3-day redemption notice period.
The following tables present the changes in Level 3 assets measured at fair value on a recurring basis during the three and nine months ended September 30, 2016 and 2015.
| | | | |
Three Months Ended September 30, 2016 | ||||
| | | | |
Interest rate options | ||||
| | | | |
(dollars in thousands) | ||||
Assets (Liabilities): | ||||
Balance at June 30, 2016 | $ | 5 | ||
Total gains or losses (realized/unrealized): | ||||
Included in earnings (or changes in net assets) | (5 | ) | ||
| | | | |
Balance at September 30, 2016 | $ | — | ||
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
Three Months Ended September 30, 2015 | ||||
| | | | |
Interest rate options | ||||
| | | | |
(dollars in thousands) | ||||
Assets (Liabilities): | ||||
Balance at June 30, 2015 | $ | 4,715 | ||
Total gains or losses (realized/unrealized): | ||||
Included in earnings (or changes in net assets) | (3,213 | ) | ||
| | | | |
Balance at September 30, 2015 | $ | 1,502 | ||
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
Nine Months Ended September 30, 2016 | ||||
| | | | |
Interest rate options | ||||
| | | | |
(dollars in thousands) | ||||
Assets (Liabilities): | ||||
Balance at December 31, 2015 | $ | 1,010 | ||
Total gains or losses (realized/unrealized): | ||||
Included in earnings (or changes in net assets) | (1,010 | ) | ||
| | | | |
Balance at September 30, 2016 | $ | — | ||
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
Nine Months Ended September 30, 2015 | ||||
| | | | |
Interest rate options | ||||
| | | | |
(dollars in thousands) | ||||
Assets (Liabilities): | ||||
Balance at December 31, 2014 | $ | 4,371 | ||
Total gains or losses (realized/unrealized): | ||||
Included in earnings (or changes in net assets) | (2,869 | ) | ||
| | | | |
Balance at September 30, 2015 | $ | 1,502 | ||
| | | | |
| | | | |
| | | | |
| | | | |
We estimate the value of the interest rate options as the sum of time value and any intrinsic value minus a counterparty credit adjustment. Intrinsic value is the value of the underlying swap, which we are able to calculate based on the forward LIBOR swap rates, the fixed rate on the underlying swap, the time to expiration, the term of the underlying swap and discount rates, all of which we are able to effectively observe. Time value is the additional value of the swaption due to the fact that it is an option. We estimate the time value using an option pricing model which, in addition to the factors used to calculate intrinsic value, also takes into account option volatility, which we estimate based on option valuations we obtain from various sources. We estimate the counterparty credit adjustment by observing credit attributes, including the credit default swap spread of entities similar to the counterparty and the amount of credit support that is available for each swaption. Since the primary component of the LIBOR swaptions' value is time value, which is based on estimated option volatility derived from valuations of comparable instruments that are generally not publicly available, we have categorized these LIBOR swaptions as Level 3. We believe the estimated fair values for the LIBOR swaptions we hold are based on the most accurate
information available for these types of derivative contracts. For additional information regarding our interest rate options, see Note C.
The estimated fair values of our long-term debt, including current maturities at September 30, 2016March 31, 2017 and December 31, 20152016 were as follows (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | ||
2016 | 2015 | 2017 | 2016 | |||||||||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Carrying Value | Fair Value | Carrying Value | Fair Value | Carrying Value | Fair Value | Carrying Value | Fair Value | |||||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Long-term debt | $ | 8,136,564 | $ | 9,752,299 | $ | 7,575,027 | $ | 8,445,630 | $ | 8,123,581 | $ | 8,858,128 | $ | 8,304,523 | $ | 9,043,029 | ||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
The estimated fair value of long-term debt is classified as Level 2 and is estimated based on observed or quoted market prices for the same or similar issues or on current rates offered to us for debt of similar maturities. The primary sources of our long-term debt consist of first mortgage bonds, pollution control revenue bonds and long-term debt issued by the Federal Financing Bank that is guaranteed by the Rural Utilities Service or the U.S. Department of Energy. We also have small amounts of long-term debt provided by National Rural Utilities Cooperative Finance Corporation (CFC) and by CoBank, ACB. The valuations for the first mortgage bonds and the pollution control revenue bonds were obtained from 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 September 30, 2016March 31, 2017 plus an applicable spread, which reflects our borrowing rate for new loans of this type from the Federal Financing Bank. The rates on the CFC debt are fixed and the valuation is based on rate quotes provided by CFC. We
use an interest rate quote sheet provided by CoBank for valuation of the CoBank debt, which reflects current rates for similar loans.
For cash and cash equivalents, restricted cash 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. The carrying amount approximates fair value because of the liquid nature of the deposits with the U.S. Treasury.
We are exposed to credit risk as a result of entering into these hedging arrangements. Credit risk is the potential loss resulting from a counterparty's nonperformance under an agreement. We have established policies and procedures to manage credit risk through counterparty analysis, exposure calculation and monitoring, exposure limits, collateralization and certain other contractual provisions.
It is possible that volatility in commodity prices and/or interest rates could cause us to have credit risk exposures with one or more counterparties. We currently have credit risk exposure to our interest rate options counterparties. If such counterparties fail to perform their obligations, we could suffer a financial loss. However, as of September 30, 2016,March 31, 2017 all of the counterparties with transaction amounts outstanding under our hedging programs are rated investment grade by the major rating agencies or have provided a guaranty from one of their affiliates that is rated investment grade.
We have entered into International Swaps and Derivatives Association agreements with our natural gas hedge and interest rate option counterparties that mitigate credit exposure by creating contractual rights relating to creditworthiness, collateral, termination and netting (which, in certain cases, allows us to use the net value of affected transactions with the same counterparty in the event of default by the counterparty or early termination of the agreement).
Additionally, we have implemented procedures to monitor the creditworthiness of our counterparties and to evaluate nonperformance in valuing counterparty positions. We have contracted with a third party to assist in monitoring certain of our counterparties' credit standing and condition. Net liability positions are generally not adjusted as we use derivative transactions as hedges and have the ability and intent to perform under each of our contracts. In the instance of net asset positions, we consider general market conditions and the observable financial health and outlook of specific counterparties, forward looking data such as credit default swaps, when available, and historical default probabilities from credit rating agencies in evaluating the potential impact of nonperformance risk to derivative positions.
The contractual agreements contain provisions that could require us or the counterparty to post collateral or credit support. The amount of collateral or credit support that could be required is calculated as the difference between the aggregate fair value of the hedges and pre-established credit thresholds. The credit thresholds are contingent upon each party's credit ratings from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty.
Gas hedges. Under the natural gas swap arrangements, we pay the counterparty a fixed price for specified natural gas quantities and receive a payment for such quantities based on a market price index. These payment obligations are netted, such that if the market price index is lower than the
fixed price, we will make a net payment, and if the market price index is higher than the fixed price, we will receive a net payment.
At September 30, 2016March 31, 2017 and December 31, 2015,2016, the estimated fair value of our natural gas contracts was a net liabilityasset of approximately $2,823,000$4,968,000 and $22,848,000,$15,090,000, respectively.
As of September 30, 2016March 31, 2017 and December 31, 2015,2016, 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 September 30, 2016March 31, 2017 due to our credit rating being downgraded below investment grade, we would have been required to post collateral or letters of credit of $3,204,000$1,837,000 with our counterparties.
The following table reflects the volume activity of our natural gas derivatives as of September 30, 2016March 31, 2017 that is expected to settle or mature each year:
| | | | | | | | |
Year | Natural Gas Swaps | Natural Gas Swaps | ||||||
| | | | | | | | |
2016 | 3.8 | |||||||
2017 | 20.2 | 20.38 | ||||||
2018 | 16.6 | 20.91 | ||||||
2019 | 11.4 | 14.31 | ||||||
2020 | 9.0 | 10.99 | ||||||
2021 | 2.5 | 4.69 | ||||||
2022 | .02 | |||||||
| | | | | | | | |
Total | 63.5 | 71.30 | ||||||
| | | | | | | | |
Interest rate options. We are exposed to the risk of rising interest rates due to the significant amount of new long-term debt we expect to incur in connection with anticipated capital expenditures, particularly the construction of Vogtle Units No. 3 and No. 4. In fourth quarter of 2011, we purchased seventeen LIBOR swaptions at a cost of $100,000,000 with a total notional amount of approximately $2,200,000,000 to hedge the interest rates on a portion of the debt that we are incurring to finance the two additional nuclear units at Plant Vogtle. Since inception, fifteen swaptionsThe last of these options, having a notional amount of approximately $2,019,368,000 have expired and, as of September 30, 2016, the notional amount of our remaining two outstanding swaptions was approximately $159,835,000.
The LIBOR swaptions are designed to cap our effective interest rate at a specified fixed interest rate on a specified option expiration date. This is accomplished by means of a payment of the cash settlement value our counterparties are obligated to make to us if prevailing fixed LIBOR swap rates exceed the specified fixed rate on the option expiration date. This payment would partially offset our interest costs, thereby reducing our effective interest rate. The cash settlement value is calculated based on the value of an underlying swap which we have the right, but not the obligation, to enter into, which would begin on the option expiration date and extend until 2042 and under which we would pay the specified fixed rate and receive a floating LIBOR rate. The cash settlement value would be zero if the swaption is out-of-the-money (that is, if the specified fixed rate is at or above then-current swap rates) on the expiration date. One of our two swaptions expires on December 30, 2016, and has a fixed rate of 3.845%, and the second swaption expires on March 31, 2017, and has a fixed rate of 3.8775%. The swaptions are both significantly out-of-the-money with fixed rates of 219 and 223 basis points, respectively, above the corresponding LIBOR swap rates that were in effect as of September 30, 2016. Swaptions having notional amounts totaling $230,867,000$80,169,000, expired without value during the nine months ended September 30, 2016.at March 31, 2017.
We paid allare deferring the premiums paid to purchase these LIBOR swaptions, at the time we entered into these transactions. At September 30, 2016 and December 31, 2015, the fair value of these swaptions was approximately $500 and $1,010,000, respectively. To manage our credit exposure to our counterparties, we negotiated credit support provisions that require each counterparty to provide us collateral in the form of cash or securities to the extent that the value of the swaptions outstanding for that counterparty exceeds a certain threshold. The collateral thresholds can range from $0 to $10,000,000 depending on each counterparty's credit rating. As of September 30, 2016 and December 31, 2015, there were no collateral postings required of the counterparties.
We are deferring realized and unrealized gains or losses from the change in fair value of each LIBOR swaption as well as related carrying and other incidental costs in accordance with our rate-making treatment. The deferral will continue until February 2020, at which time the deferredand costs and deferred gains, if any, from the settlement of the interest rate options will be amortized and collected in rates over the life of the $2,200,000,000 ofassociated debt that we hedged with the swaptions.
| | | | | | | | | |
Balance Sheet | Fair Value | ||||||||
| | | | | | | | | |
2017 | 2016 | ||||||||
| (dollars in thousands) | ||||||||
Not designated as hedge: | |||||||||
Assets: | |||||||||
Natural gas swaps | Other current assets | $ | 8,917 | $ | 13,833 | ||||
Natural gas swaps | Other deferred charges | $ | 144 | $ | 3,289 | ||||
Liabilities: |
| ||||||||
Natural gas swaps | Other current liabilities | $ | 271 | $ | 54 | ||||
Natural gas swaps | Other deferred credits | $ | 3,822 | $ | 1,977 | ||||
| | | | | | | | | |
The following table reflects the remaining notional amount of forecasted debt issuances we have hedged in each year with LIBOR swaptions as of September 30, 2016.
| | | | |
Year | LIBOR Swaption | |||
| | | | |
2016 | $ | 79,666 | ||
2017 | 80,169 | |||
| | | | |
Total | $ | 159,835 | ||
| | | | |
The table below reflects the fair value of derivative instruments and their effect on our unaudited consolidated balance sheets at September 30, 2016 and December 31, 2015.
| | | | | | | | | |
Balance Sheet | Fair Value | ||||||||
| | | | | | | | | |
2016 | 2015 | ||||||||
| (dollars in thousands) | ||||||||
Not designated as hedge: | |||||||||
Assets: | |||||||||
Interest rate options | Other deferred charges | $ | — | $ | 1,010 | ||||
Natural gas swaps | Other current assets | $ | 633 | $ | — | ||||
Natural gas swaps | Other deferred charges | $ | 1,142 | $ | — | ||||
Liabilities: |
| ||||||||
Natural gas swaps | Other current liabilities | $ | 909 | $ | 22,848 | ||||
Natural gas swaps | Other deferred credits | $ | 3,689 | $ | — | ||||
| | | | | | | | | |
The following table presents the gross realized gains and (losses) on derivative instruments recognized in margin for the three and nine months ended September 30, 2016March 31, 2017 and 2015.2016.
| | | | | | | | | | | | | | | | | | | | | | | | |
Statement of | Three months | Nine months | Statement of | Three months | ||||||||||||||||||||
Location | 2016 | 2015 | 2016 | 2015 | Location | 2017 | 2016 | |||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | |
(dollars in thousands) | (dollars in thousands) | |||||||||||||||||||||||
Not Designated as hedges: | ||||||||||||||||||||||||
Natural Gas Swaps | Fuel | $ | 2,039 | $ | 24 | $ | 2,057 | $ | 205 | Fuel | $ | 840 | $ | 11 | ||||||||||
Natural Gas Swaps | Fuel | (5,923 | ) | (5,970 | ) | (18,262 | ) | (14,744 | ) | Fuel | (744 | ) | (4,228 | ) | ||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | |
$ | (3,884 | ) | $ | (5,946 | ) | $ | (16,205 | ) | $ | (14,539 | ) | $ | 96 | $ | (4,217 | ) | ||||||||
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | ||
| | | | | | | | | | | | | | | | | | | | | | | | |
The following table presents the unrealized gains and (losses) on derivative instruments deferred on the balance sheet at September 30, 2016March 31, 2017 and December 31, 2015.2016.
| | | | | | | | | | | | | | | | | | |
Balance Sheet | 2016 | 2015 | Balance Sheet | 2017 | 2016 | |||||||||||||
| | | | | | | | | | | | | | | | | | |
(dollars in thousands) | (dollars in thousands) | |||||||||||||||||
Not designated as hedge: | ||||||||||||||||||
Not designated as hedges: | ||||||||||||||||||
Natural gas swaps | Regulatory liability | $ | 381 | $ | — | Regulatory asset | $ | (1,837 | ) | $ | (62 | ) | ||||||
Natural gas swaps | Regulatory asset | (3,204 | ) | (22,848 | ) | Regulatory liability | 6,805 | 15,152 | ||||||||||
Interest rate options | Regulatory asset | (11,433 | ) | (25,915 | ) | Regulatory asset | — | (5,788 | ) | |||||||||
| | | | | | | | | | | | | | | | | | |
Total not designated as hedge | $ | (14,256 | ) | $ | (48,763 | ) | ||||||||||||
Total not designated as hedges | $ | 4,968 | $ | 9,302 | ||||||||||||||
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
The following table presents the gross amounts of derivatives and their related offset amounts as permitted by their respective master netting agreements. There were no obligations to return cash collateral as of September 30, 2016March 31, 2017 or December 31, 2015.2016.
| | | | | | | | | | | | | | | | | | | | |
Gross Amounts of Recognized Assets (Liabilities) | Gross Amounts offset on the Balance Sheet | Net Amounts of Assets Presented on the Balance Sheet | Gross Amounts | Gross | Net Amounts of | |||||||||||||||
| | | | | | | | | | | | | | | | | | | | |
(dollars in thousands) | (dollars in thousands) | |||||||||||||||||||
September 30, 2016 | ||||||||||||||||||||
Assets: | ||||||||||||||||||||
March 31, 2017 | ||||||||||||||||||||
Natural gas swaps | $ | (2,823 | ) | $ | — | $ | (2,823 | ) | $ | 4,968 | $ | — | $ | 4,968 | ||||||
Interest rate options | $ | 11,433 | $ | (11,433 | ) | $ | — | |||||||||||||
December 31, 2015 | ||||||||||||||||||||
Assets: | ||||||||||||||||||||
December 31, 2016 | ||||||||||||||||||||
Natural gas swaps | $ | (22,848 | ) | $ | — | $ | (22,848 | ) | $ | 15,090 | $ | — | $ | 15,090 | ||||||
Interest rate options | $ | 26,925 | $ | (25,915 | ) | $ | 1,010 | $ | 5,788 | $ | (5,788 | ) | $ | — | ||||||
| | | | | | | | | | | | | | | | | | | |
The following tables summarize the activities for available-for-sale securities as of September 30, 2016March 31, 2017 and December 31, 2015.2016.
| | | | | | | | | | | | | | | | | | | | | | | | | ||
Gross Unrealized | Gross Unrealized | |||||||||||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
(dollars in thousands) | (dollars in thousands) | |||||||||||||||||||||||||
September 30, 2016 | Cost | Gains | Losses | Fair Value | ||||||||||||||||||||||
March 31, 2017 | Cost | Gains | Losses | Fair Value | ||||||||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Equity | $ | 235,579 | $ | 48,658 | $ | (6,159 | ) | $ | 278,078 | $ | 248,135 | $ | 47,893 | $ | (3,936 | ) | $ | 292,092 | ||||||||
Debt | 195,849 | 4,529 | (947 | ) | 199,431 | 213,015 | 1,456 | (2,815 | ) | 211,656 | ||||||||||||||||
Other | 8,398 | — | (1 | ) | 8,397 | 2,718 | — | — | 2,718 | |||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Total | $ | 439,826 | $ | 53,187 | $ | (7,107 | ) | $ | 485,906 | $ | 463,868 | $ | 49,349 | $ | (6,751 | ) | $ | 506,466 | ||||||||
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | ||
Gross Unrealized | Gross Unrealized | |||||||||||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | ||
(dollars in thousands) | (dollars in thousands) | |||||||||||||||||||||||||
December 31, 2015 | Cost | Gains | Losses | Fair Value | ||||||||||||||||||||||
December 31, 2016 | Cost | Gains | Losses | Fair Value | ||||||||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | ||
Equity | $ | 230,123 | $ | 37,494 | $ | (9,635 | ) | $ | 257,982 | $ | 237,317 | $ | 51,054 | $ | (5,041 | ) | $ | 283,330 | ||||||||
Debt | 189,700 | 1,158 | (3,491 | ) | 187,367 | 201,492 | 1,167 | (3,423 | ) | 199,236 | ||||||||||||||||
Other | 5,255 | — | (4 | ) | 5,251 | 3,339 | — | (2 | ) | 3,337 | ||||||||||||||||
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Total | $ | 425,078 | $ | 38,652 | $ | (13,130 | ) | $ | 450,600 | $ | 442,148 | $ | 52,221 | $ | (8,466 | ) | $ | 485,903 | ||||||||
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In August 2015, the FASB issued an update to Topic 606 deferring the effective date by one year. The standard is effective for annual reporting periods beginning after December 15, 2017 and interim periods therein. The standard also permits early adoption of the standard, but not before the original effective date of December 15, 2016.
While we expect that the majority of our revenues will be included in the scope of Topic 606, we have not fully completed our evaluation of the new revenue standard. Our evaluation process includes, but is not limited to, identifying contracts within the scope of Topic 606, reviewing and documenting our accounting for these contracts and assessing the applicability of the variable consideration guidance. A large majority of our revenues is derived from substantially identical wholesale power contracts that we have with each of our 38 members. We are currently evaluatingexpect the futurepattern of revenue recognition pursuant to our wholesale power contracts will remain unchanged on an annual basis under the new revenue standard. However, we continue to evaluate the effects, if any, of Topic 606 on our interim period revenues as it relates to budget adjustments, which may be made during the year that affect our annual revenue requirement. We also continue to evaluate other revenue streams and the related contracts, as well as monitor issues specific to the power and utilities industry. As the ultimate impact of thisthe new revenue standard onhas not yet been determined, we have not elected our consolidated financial statements.transition method.
In July 2015, the FASB issued "Inventory (Topic 330): Simplifying the Measurement of Inventory." Under the new inventory standard, inventories are required to be measured at the lower of cost and net realizable value, the latter representing the estimated selling price in the ordinary course of business, reduced by costs of completion, disposal, and transportation. Under current guidance, inventories are required to be measured at the lower of cost or market, but depending upon specific circumstances, market could be replacement cost, net realizable value, or net realizable value reduced by a normal profit margin. The amendments do not apply to inventory measured using the last-in, first-out or the retail inventory method. The amendments apply to all other inventory, which includes inventory that is measured using first-in, first out or average cost, the method used to measure all of our inventories. The new standard is effective for us prospectively for annual reporting periods beginning after December 15, 2016, and interim periods therein. Early adoption is permitted as of the beginning of an interim or annual reporting period. As permitted, on April 1, 2016, we early adopted these amendments and applied their provisions prospectively. The adoption of this amendment did not have a material impact on our consolidated financial statements.
In November 2015, the FASB issued "Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes." The amendments in this standard simplifies the presentation of deferred income taxes by eliminating the separate classification of deferred income tax assets and liabilities into current and noncurrent amounts in the statement of financial position. The amendments in the update require that all deferred tax assets and liabilities be classified as noncurrent in the consolidated balance sheet. The new standard is effective for us prospectively for annual reporting periods beginning after December 15, 2016, and interim periods therein. Early adoption is permitted as of the beginning of an interim or annual reporting period. We are currently evaluating the future impact of this standard but do not expect adoption of the standard to have a material impact on our consolidated financial 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-effectcumulative effect adjustment to the balance sheet of the fiscal year of adoption and certain provisions should be applied prospectively. We are currently evaluating the future impact of this standard on our consolidated financial statements.
In February 2016, the FASB issued "Leases (Topic 842)." The new leases standard requires a dual approach for lessee accounting under which a lessee would account for leases as finance leases or operating leases. Both finance leases and operating leases will result in the lessee recognizing a right-of-use (ROU) asset and a corresponding lease liability. For finance leases the lessee would recognize interest expense and amortization of the ROU asset and for operating leases the lessee would recognize a straight-line total lease expense. The new lease standard does not substantially change lessor accounting. The new leases standard is effective for us on a modified retrospectivelyretrospective approach for annual reporting periods beginning after December 15, 2018, and interim periods therein. Early adoption is permitted. We are currently evaluating the future impact of this standard on our consolidated financial statements.
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. We are currently evaluating the future impact of this standard on our consolidated financial statements.
In August 2016, the FASB issued "Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments." The amendments in this standard provide specific guidance on eight cash flow classification issues relating to how certain cash receipts and cash payments are presented and classified in the statement of cash flows, thereby reducing the current and potential future diversity in practice. The new standard is effective for us for annual reporting periods beginning after December 15, 2017, and interim periods therein. Early adoption is permitted, including adoption in an interim period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the amendments in the same period. The amendments should be applied using a retrospective transition method to each period presented. If it is impracticable to apply the amendments retrospectively for some of the issues, the amendments for those issues would be applied prospectively as of the earliest date practicable. We are currently evaluating the future impact of this standard on our consolidated financial statements.
In November 2016, the FASB issued "Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force)." The amendments in this standard require the statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents are to be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period amounts shown on the statement of cash flows. The new standard is effective for us on a retrospective basis for annual reporting periods beginning after December 15, 2017, and
interim periods therein. Early adoption is permitted, including adoption in an interim period. Our restricted cash balances are nominal and accordingly we do not expect the adoption of this standard to have a material impact on our consolidated financial statements.
Our effective tax rate is zero; therefore, all amounts below are presented net of tax.
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Accumulated Other Comprehensive Margin | Accumulated Other Comprehensive (Deficit) Margin | |||||||
Three Months Ended | Three Months Ended | |||||||
| | | | | | | | |
(dollars in thousands) | (dollars in thousands) | |||||||
Available-for-sale | Available-for-sale | |||||||
| | | | | | | | |
Balance at June 30, 2015 | $ | 107 | ||||||
Balance at December 31, 2015 | $ | 58 | ||||||
Unrealized gain | 125 | 294 | ||||||
(Gain) reclassified to net margin | (31 | ) | (10 | ) | ||||
| | | | | | | | |
Balance at September 30, 2015 | $ | 201 | ||||||
Balance at March 31, 2016 | $ | 342 | ||||||
| | | | | | | | |
Three Months Ended September 30, 2016 | Three Months Ended March 31, 2017 | |||||||
| | | | | | | | |
(dollars in thousands) | (dollars in thousands) | |||||||
Available-for-sale | Available-for-sale | |||||||
| | | | | | | | |
Balance at June 30, 2016 | $ | 435 | ||||||
Unrealized gain | 50 | |||||||
(Gain) reclassified to net margin | (69 | ) | ||||||
Balance at December 31, 2016 | $ | (370 | ) | |||||
Unrealized loss | (76 | ) | ||||||
Loss reclassified to net margin | 37 | |||||||
| | | | | | | | |
Balance at September 30, 2016 | $ | 416 | ||||||
Balance at March 31, 2017 | $ | (409 | ) | |||||
| | | | | | | | |
| | | | | | | | |
Nine Months Ended September 30, 2015 | ||||
| | | | |
(dollars in thousands) | ||||
Available-for-sale | ||||
| | | | |
Balance at December 31, 2014 | $ | 468 | ||
Unrealized loss | (83 | ) | ||
(Gain) reclassified to net margin | (184 | ) | ||
| | | | |
Balance at September 30, 2015 | $ | 201 | ||
| | | | |
Nine Months Ended September 30, 2016 | ||||
| | | | |
(dollars in thousands) | ||||
Available-for-sale | ||||
| | | | |
Balance at December 31, 2015 | $ | 58 | ||
Unrealized gain | 486 | |||
(Gain) reclassified to net margin | (128 | ) | ||
| | | | |
Balance at September 30, 2016 | $ | 416 | ||
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We do not anticipate that the liabilities, if any, for any current proceedings against us will have a material effect on our financial condition or results of operations. However, at this time, the ultimate outcome of any pending or potential litigation cannot be determined.
a. Vogtle Units No. 3 and No. 4 Construction Litigation
In 2008, Georgia Power, acting for itself and as agent for us, the Municipal Electric Authority of Georgia and the City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, doing business as Dalton Utilities (collectively, the Co-owners) and Westinghouse Electric Company LLC and Stone & Webster, Inc. (collectively, the Contractor) entered into an Engineering, Procurement and Construction Agreement (the EPC Agreement). Pursuant to the EPC Agreement, the Contractor will design, engineer, procure, construct and test two 1,100 megawatt nuclear units using the Westinghouse AP1000 technology and related facilities at Plant Vogtle, Units No. 3 and No. 4. Our ownership interest and proportionate share of the cost to construct these units is 30%, representing 660 megawatts of total capacity.
On December 31, 2015, Westinghouse and the Co-owners entered into a settlement agreement to resolve certain disputes between the Co-owners and the Contractor under the EPC Agreement which were dismissed with prejudice on January 5, 2016. Future claims by the Contractor or Georgia Power, on behalf of the Co-owners, could arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the EPC Agreement and, under the resolution procedures, may be resolved through litigation after the completion of nuclear fuel load for both units.
For additional information about the Vogtle construction project, see "Item 8—FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA—Notes to Consolidated Financial Statements" in our 2015 Form 10-K and "Management's Discussion and Analysis of Financial Condition and Results of Operations—Financial Condition—Capital Requirements and Liquidity and Sources of Capital—Vogtle Units No. 3 and No. 4."
b. Patronage Capital Litigation
There have been no material changes to this litigation from the disclosure included underin Note G12 "Contingencies and Regulatory Matters" of Notes to Unaudited Consolidated Financial Statements in our 2016 Form 10-Q for the quarterly period ended June 30, 2016. For additional information regarding this litigation, see Note G10-K.
Table of Notes to Unaudited Consolidated Financial Statements in our Form 10-Q for the quarterly period ended March 31, 2016.Contents
c.b. Environmental Matters
As is typical for electric utilities, we are subject to various federal, state and local environmental laws which represent significant future risks and uncertainties. Air emissions, water discharges and water usage are extensively controlled, closely monitored and periodically reported. Handling and disposal requirements govern the manner of transportation, storage and disposal of various types of waste. We are also subject to climate change regulations that impose restrictions on emissions of greenhouse gases, including carbon dioxide, for certain new and modified facilities.
In general, these and other types of environmental requirements are becominghave become increasingly stringent. Such requirements may substantially increase the cost of electric service, by requiring modifications in the design or operation of existing facilities or the purchase of emission allowances. Failure to comply with these requirements could result in civil and criminal penalties and could include the complete shutdown of individual generating units not in compliance. Certain
of our debt instruments require us to comply in all material respects with laws, rules, regulations and orders imposed by applicable governmental authorities, which include current and future environmental laws or regulations. Should we fail to be in compliance with these requirements, it would constitute a default under those debt instruments. We believe that we are in compliance with those environmental regulations currently applicable to our business and operations. Although it is our intent to comply with current and future regulations, we cannot provide assurance that we will always be in compliance.
At this time, the ultimate impact of any new and more stringent environmental regulations described above is uncertain and could have an effect on our financial condition, results of operations and cash flows as a result of future additional capital expenditures and increased operations and maintenance costs.
Additionally, litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has increased generally throughout the United States. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief, personal injury and property damage allegedly caused by coal combustion residue, greenhouse gas and other emissions have become more frequent.
The following regulatory assets and liabilities are reflected on the unaudited consolidated balance sheets as of September 30, 2016March 31, 2017 and December 31, 2015.2016.
| | | | | | | | | | | | | | |
2016 | 2015 | 2017 | 2016 | |||||||||||
(dollars in thousands) | (dollars in thousands) | |||||||||||||
| | | | | | | | | | | | | | |
Regulatory Assets: | ||||||||||||||
Premium and loss on reacquired debt(a) | $ | 56,772 | $ | 61,916 | $ | 55,014 | $ | 55,084 | ||||||
Amortization on capital leases(b) | 31,769 | 30,253 | 32,668 | 32,274 | ||||||||||
Outage costs(c) | 39,589 | 42,027 | 48,611 | 39,986 | ||||||||||
Interest rate swap termination fees(d) | 4,017 | 5,355 | 3,124 | 3,570 | ||||||||||
Asset retirement obligations—Ashpond and other(l) | 42,357 | 33,747 | ||||||||||||
Depreciation expense(e) | 44,447 | 45,514 | 43,735 | 44,091 | ||||||||||
Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(f) | 41,871 | 37,646 | 44,797 | 43,444 | ||||||||||
Interest rate options cost(g) | 106,220 | 102,554 | 108,562 | 107,394 | ||||||||||
Deferral of effects on net margin—Smith Energy Facility(h) | 173,885 | 178,343 | 170,913 | 172,399 | ||||||||||
Other regulatory assets(m) | 43,487 | 26,646 | 14,533 | 13,398 | ||||||||||
| | | | | | | | | | | | | | |
Total Regulatory Assets | $ | 542,057 | $ | 530,254 | $ | 564,314 | $ | 545,387 | ||||||
Regulatory Liabilities: | ||||||||||||||
Accumulated retirement costs for other obligations(i) | $ | 12,925 | $ | 8,910 | $ | 11,769 | $ | 9,829 | ||||||
Deferral of effects on net margin—Hawk Road Energy Facility(h) | 20,316 | 20,775 | 20,011 | 20,163 | ||||||||||
Major maintenance reserve(j) | 29,450 | 22,422 | 31,737 | 28,379 | ||||||||||
Amortization on capital leases(b) | 23,939 | 26,502 | 22,230 | 23,084 | ||||||||||
Deferred debt service adder(k) | 83,644 | 76,334 | 88,496 | 86,082 | ||||||||||
Asset retirement obligations(l) | 19,106 | 8,316 | 21,367 | 11,766 | ||||||||||
Other regulatory liabilities(m) | 3,776 | 3,708 | 9,993 | 18,445 | ||||||||||
| | | | | | | | | | | | | | |
Total Regulatory Liabilities | $ | 193,156 | $ | 166,967 | $ | 205,603 | $ | 197,748 | ||||||
| | | | | | | | | | | | | | |
Net Regulatory Assets | $ | 348,901 | $ | 363,287 | $ | 358,711 | $ | 347,639 | ||||||
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Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005 (the "Title XVII Loan Guarantee Program"), we and the U.S. Department of Energy, acting by and through the Secretary of Energy, entered into a Loan Guarantee Agreement on February 20, 2014 pursuant to which the Department of Energy agreed to guarantee our obligations under the Note Purchase Agreement dated as of February 20, 2014 (the "Note Purchase Agreement"), among us, the Federal Financing BankFFB and the Department of Energy and two future advance promissory notes, each dated February 20, 2014, made by us to the Federal Financing BankFFB (the "Federal Financing Bank"FFB Notes" and together with the Note Purchase Agreement, the "FFB Credit Facility Documents"). The FFB Credit Facility Documents provide for a multi-advance term loan facility (the "Facility"), under which we may make termlong-term loan borrowings through the Federal Financing Bank.FFB.
Proceeds of advances made under the Facility will be used to reimburse us for a portion of certain costs of construction relating to Vogtle Units No. 3 and No. 4 that are eligible for financing under the Title XVII Loan Guarantee Program ("Eligible Project Costs").Program. Aggregate borrowings under the Facility may not exceed $3,057,069,461, of which $335,471,604 is designated for capitalized interest.
Under the Loan Guarantee Agreement, we are obligated to reimburse the Department of Energy in the event the Department of Energy is required to make any payments to the FFB under the guarantee. Our payment obligations to FFB 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 notes and 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 will begin on February 20, 2020. Under both FFB Notes, the interest rates during the applicable interest rate periods will equal the current average yield on U.S. Treasuries of comparable maturity at the beginning of the interest rate period, plus a spread equal to 0.375%.
At March 31, 2017, aggregate DOE-guaranteed borrowings totaled $1,692,350,000, including capitalized interest. Advances may be requested under the Facility on a quarterly basis through December 31, 20202020. Future advances are subject to satisfaction of customary conditions, including certification of compliance with the requirements of the Title XVII Loan Guarantee Program, accuracy of project-related representations and warranties, delivery of updated project-related information, our continued ownership of our interest in Vogtle Units No. 3 and No. 4 free and clear of any liens except those permitted under the Loan Guarantee Agreement, evidence of compliance with the prevailing wage requirements of the Davis-Bacon Act, as amended, and certification from the Department of Energy's consulting engineer that proceeds of the advance are securedused to reimburse eligible project costs. The failure by the Contractor to perform its obligations under the EPC Agreement could affect our first mortgage indenture. On June 8, 2016,ability to satisfy the conditions required to receive future advances.
Under the Loan Guarantee Agreement, we receivedare 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, the Department of Energy may, at its option, (i) elect to suspend or terminate the FFB's commitment to make further advances under the Facility, and may later revoke any such suspension or (ii) trigger a $300,000,000 advanceLoan Guarantee Agreement covenant under which we have agreed 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) cessation of the construction of Vogtle Units No. 3 and No. 4 for twelve consecutive months, (ii) termination of the EPC Agreement under certain circumstances, (iii) loss of or failure to receive necessary regulatory approvals under certain circumstances, (iv) loss of access to intellectual property rights necessary to construct or operate Vogtle Units No. 3 and No. 4 under certain circumstances, (v) our failure to fund our share of operation and maintenance expenses for Vogtle Units No. 3 and No. 4 for twelve consecutive months, (vi) change of control of Oglethorpe and (vii) 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. At September 30, 2016, aggregateWe may also voluntarily prepay outstanding borrowings totaled $1,515,215,000,under the Facility. Under the FFB Credit Facility Documents, any prepayment will be subject to a make-whole premium or discount, as applicable.
Upon notice to the Department of Energy from the Co-owners of their intent to terminate the EPC Agreement for convenience, the Department of Energy may elect to continue construction of Vogtle Units No. 3 and No. 4. In such an event, unless we elect to join the Department of Energy in continuing construction, the Department of Energy will have the right, subject to certain conditions including capitalized interest.obtaining necessary NRC approvals, to assume our rights and obligations under the principal agreements relating to Vogtle Units No. 3 and No. 4 and to acquire all or a portion of our ownership interest in Vogtle Units No. 3 and No. 4.
For the nine-monththree-month period ended September 30, 2016,March 31, 2017 we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling $88,354,000$4,517,000 for general and environmental improvements at existing plants.
On October 27, 2016, we received an additional $6,105,000 in advances on Rural Utilities Service-guaranteed Federal Financing Bank loans for general and environmental improvements at existing plants.
These advances are secured under our first mortgage indenture.
On April 21, 2016,In January 2017, we issued $250,000,000temporarily refinanced $122,600,000 of 4.25% first mortgagevariable rate pollution control revenue bonds Series 2016A primarilywith original maturity dates ranging from 2020 through 2040, through the issuance of commercial paper. The bonds were classified as current debt at December 31, 2016.
In 2008, Georgia Power, acting for itself and as agent for the purposeCo-owners, entered into an Engineering, Procurement and Construction Agreement (the EPC Agreement) with Westinghouse Electric Company LLC and Stone & Webster, Inc. (collectively, the Contractor). Stone & Webster was subsequently acquired by Westinghouse and changed its name to WECTEC Global Project Services Inc. (WECTEC). Pursuant to the EPC Agreement, the Contractor 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.
Under the EPC Agreement, the Co-owners agreed to pay a purchase price that is subject to certain price escalations and adjustments, including fixed escalation amounts and certain index-based adjustments, as well as adjustments for change orders and performance bonuses. The EPC Agreement also provides for liquidated damages upon the Contractor's failure to fulfill the schedule and certain performance guarantees, each subject to an aggregate cap of providing long-term financing10% of the contract price, or approximately $920,000,000. In addition, the EPC Agreement provides for expenditures relatedlimited cost sharing by the Co-owners for increases to Contractor costs under certain conditions. The maximum amount of additional capital costs under this provision attributable to us is $75,000,000. Each Co-owner is severally, and not jointly, liable to the Contractor for its proportionate share, based on its ownership interest, of all amounts owed under the EPC Agreement. In the event of a credit rating downgrade below investment grade of any Co-owner, that Co-owner will be required to provide a letter of credit or other credit enhancement.
Under the terms of the EPC Agreement, the Contractor does not have a right to terminate the EPC Agreement for convenience. The Contractor may terminate the EPC Agreement under certain circumstances, including certain Co-owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the EPC Agreement by the Co-owners, Co-owner insolvency, and certain other events. In the event of an abandonment of work by the Contractor, the maximum liability of the Contractor under the EPC Agreement is increased to 40% of the contract price (approximately $1,100,000,000 based on our ownership interest). The EPC Agreement permits Georgia Power, acting for itself and as agent for the Co-owners, to terminate the EPC Agreement at any time for convenience; provided that the Co-owners will be required to pay certain termination costs. In addition, Georgia Power, acting for itself and as agent for the Co-owners, may terminate the EPC Agreement for certain Contractor breaches, including abandonment of work by the Contractor.
Under the Toshiba Guarantee, Toshiba has guaranteed certain payment obligations of the Contractor, including any liability of the Contractor for abandonment of work. However, due to Toshiba's financial situation described below, substantial risk regarding the Co-owners' ability to fully collect under the Toshiba Guarantee exists. In January 2016, Westinghouse delivered to the Co-owners $920,000,000 of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the Contractor's potential obligations under the EPC Agreement. The Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020, and require 60 days' written notice to Georgia Power, as agent of the Co-owners, in the event the Westinghouse Letters of Credit will not be renewed. In the event of such notice, Georgia Power, as agent of the Co-owners, would be able to draw on the entire balance of the Westinghouse Letters of Credit. The Westinghouse Letters of Credit remain in place in accordance with the terms of the EPC Agreement.
On March 29, 2017, Westinghouse and WECTEC each filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. Georgia Power, acting for itself and as agent for the other Co-owners, entered into an Interim Assessment Agreement with the Contractor and WECTEC Staffing Services LLC (WECTEC Staffing), dated as of March 29, 2017 (the Interim Assessment Agreement), to provide for a continuation of work with respect to Vogtle Units No. 3 and No. 4 and4. The provisions in the Smith Energy Facility. In conjunction with the issuance of the bonds, we repaid $129,737,500 of outstanding commercial paper, which was classified as long-term debt at March 31, 2016. The bonds are secured under our first mortgage indenture.Interim Assessment Agreement became effective upon approval
of the Interim Assessment Agreement by the bankruptcy court on March 30, 2017. The term of the Interim Assessment Agreement was originally scheduled to expire on April 28, 2017. On October 6, 2016, we extendedApril 28, 2017, Georgia Power, acting for itself and as agent for the other Co-owners, entered into an amendment to the Interim Assessment Agreement with the Contractor and WECTEC Staffing solely to extend the term of the Interim Assessment Agreement through the earlier of (i) May 12, 2017 and (ii) termination of the Interim Assessment Agreement by any party upon five business days' notice (the Interim Assessment Period).
The Interim Assessment Agreement provides, among other items, that (i) Georgia Power will be obligated to pay, on behalf of the Co-owners, all costs accrued by the Contractor for subcontractors and vendors for services performed or goods provided during the Interim Assessment Period, with these amounts to be paid to the Contractor, except for amounts accrued for Fluor Corporation (Fluor), which will be paid directly to Fluor, (ii) during the Interim Assessment Period, the Contractor shall provide certain engineering, procurement and management services for Vogtle Units No. 3 and No. 4, to the same extent as contemplated by the EPC Agreement, and Georgia Power, on behalf of the Co-owners, will make payments of $5,400,000 per week for these services, (iii) Georgia Power will have the right to make payments, on behalf of the Co-owners, directly to subcontractors and vendors who have accounts past due with the Contractor, (iv) during the Interim Assessment Period, the Contractor will use its commercially reasonable efforts to provide information reasonably requested by Georgia Power as is necessary to continue construction and investigate the completion status of Vogtle Units No. 3 and No. 4, (v) the Contractor will reject or accept the EPC Agreement by the termination of the Interim Assessment Agreement, and (vi) during the Interim Assessment Period, Georgia Power, on behalf of the Co-owners, will not exercise any remedies against Toshiba under Toshiba's guarantee of certain obligations of Westinghouse under the EPC Agreement (the Toshiba Guarantee). Under the Interim Assessment Agreement, all parties expressly reserve all rights and remedies under the EPC Agreement, all related security and collateral, under applicable law.
A number of subcontractors to the Contractor, including Fluor Enterprises, Inc., have alleged non-payment by the Contractor for amounts owed for work performed on Vogtle Units No. 3 and No. 4. Georgia Power, acting for itself and as agent for the Co-owners, has taken, and continues to take, action to remove liens filed by these subcontractors through the posting of surety bonds.
Georgia Power estimates the aggregate liability for the Co-owners under the Interim Assessment Agreement and the removal of subcontractor liens to be approximately $470,000,000, of which our $150,000,000 unsecured JPMorgan Chase Lineproportionate share would total approximately $141,000,000. As of March 31, 2017, $245,000,000 of this aggregate liability had been paid or accrued. Georgia Power is evaluating remedies available to the Co-owners for these payments, including draws under the Westinghouse Letters of Credit through October 2018. At September 30, 2016, there was approximately $34,000,000and enforcement of the Toshiba Guarantee. Georgia Power, as agent for the Co-owners, has begun the process to access a portion of the funds available for borrowings under the arrangement,Westinghouse Letters of Credit.
In February 2017, the Contractor provided Georgia Power, as lettersagent for the Co-owners, with revised forecasted in-service dates of credit of approximately $114,000,000December 2019 and $2,000,000 had been issued to support certain variable rate demand bondsSeptember 2020 for Vogtle Units No. 3 and to post collateral to third parties,No. 4, respectively. In connectionHowever, we and Georgia Power do not believe the revised in-service dates are achievable. Georgia Power, along with this extension, $37,352,000 of the variable rate demand bonds supported by this facility, which was previously classifiedother Co-owners, is undertaking a comprehensive schedule and cost-to-complete assessment, as well as a current obligation, has been classified as long-term debt as of September 30, 2016cancellation cost assessment. It is reasonably possible these assessments result in accordance withestimated incremental costs to complete, including Co-owners' costs, that materially exceed the applicable accounting guidance.
Nuclear, in the period in whichevent Southern Nuclear assumes control over construction management of Vogtle Units No. 3 and No. 4. In addition, Georgia Power, on behalf of itself and the liability is incurred. The liabilities we have recognized primarily relateother Co-owners, intends to take all actions available to it to enforce its rights related to the decommissioningEPC Agreement, including enforcing the Toshiba Guarantee, subject to the Interim Assessment Agreement, and accessing the Westinghouse Letters of Credit.
On April 11, 2017, Toshiba filed its unaudited financial statements as of and for the nine months ended December 31, 2016, which reflected a negative shareholders' equity balance of $1,900,000,000, with Japanese regulators. Toshiba also announced that further substantial charges may be required in the quarter ended March 31, 2017 in connection with the bankruptcy filing of Westinghouse and WECTEC and that there are material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern.
The Contractor's bankruptcy filing is expected to have a material impact on the construction cost and schedule of Vogtle Units No. 3 and No. 4 and could have a material impact on our nuclear facilities.financial condition and results of operations. In addition, wean inability or other failure by Toshiba to perform its obligations under the Toshiba Guarantee could have retirement obligationsa material impact on the cost to the Co-owners of Vogtle Units No. 3 and No. 4, and, therefore, on our financial condition and results of operations.
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 as construction proceeds. 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 to ash ponds, gypsum, landfill sitesapprovals by the Nuclear Regulatory Commission, may arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be further delays in the project schedule that could result in increased costs.
As construction continues, the risk remains that challenges with labor productivity, fabrication, delivery, assembly, and asbestos removal. Underinstallation of plant systems, structures, and components, or other issues could arise and may further impact project schedule and cost. Our previously estimated owner's and financing costs of approximately $20,000,000 per month in the accounting provisionnear term for regulated operations, we record a regulatory asset or liability to reflect the difference in timing of recognitionVogtle Units No. 3 and No. 4 are being evaluated as part of the costs related to nuclearcomprehensive schedule and coal ash related decommissioning for financial statement purposes and for ratemaking purposes.
On April 17, 2015 the Environmental Protection Agency (EPA) 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. Based on additional assessments of the impact of the final CCR rule and refinement of cost estimates in 2016, we revised the forecasted cash flows for our existing coal ash related asset retirement obligations, andcost-to-complete analysis being performed as a result increased the obligations and corresponding assets in electric plant in service by approximately $70,000,000. The liabilities are estimates based on various assumptions including, but not limited to, closure and post-closure cost estimates, timing of expenditures, escalation factors, discount rates and methods for complying with the CCR rule. The increase is primarily related to closure cost estimates which are based on advanced engineering methods to close the ash ponds in place. Additional adjustments to the asset retirement obligations are expected periodically as we continue to assess the impact of the rule on our estimates and assumptions. For information regarding the impactContractor's bankruptcy.
The ultimate outcome of the final CCR rule on asset retirement obligations, see "Item 8—FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA—Notes to Consolidated Financial Statements" in our 2015 Form 10-K.these matters cannot be determined at this time.
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
General
We are a Georgia electric membership corporation (an EMC) incorporated in 1974 and headquartered in metropolitan Atlanta. We are owned by our 38 retail electric distribution cooperative members. Our members are consumer-owned distribution cooperatives providing retail electric service in Georgia on a not-for-profit basis. Our principal business is providing wholesale electric power to our members, which we provide primarily from our generation assets and, to a lesser extent, from power purchased from other suppliers. As with cooperatives generally, we operate on a not-for-profit basis.
Results of Operations
For the |
Net Margin
Our net margins for the three-month and nine-month periodsperiod ended September 30, 2016March 31, 2017 were $18.6 million and $62.5$21.5 million compared to $15.9 million and $42.1$20.6 million for the same periodsperiod of 2015.2016. Through September 30, 2016,March 31, 2017, we collected approximately 124%41% of our targeted net margin of $50.5$51.8 million for the year ending December 31, 2016.2017. These collections are typical as our capacity revenues are generally recorded evenly throughout the year and our management generally budgets conservatively. We anticipate our board of directors will approve a budget adjustment by the end of the year so margins will achieve, but not exceed, the targeted margins for interest ratio. For additional information regarding our net margin requirements and policy, see "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Summary of Cooperative Operations—Margins" in our 20152016 Form 10-K.
Operating Revenues
Our operating revenues fluctuate from period to period based on several factors, including fuel costs, weather and other seasonal factors, load requirements in our members' service territories, operating costs, availability of electric generation resources, our decisions of whether to dispatch our owned, purchased or member-owned resources over which we have dispatch rights, and our members' decisions of whether to purchase a portion of their hourly energy requirements from our resources or from other suppliers.
Sales to Members. We generate revenues principally from the sale of electric capacity and energy to our members. Capacity revenues are the revenues we receive for electric service whether or not our generation and purchased power resources are dispatched to produce electricity, and are designed to recover the fixed costs associated with our business, including fixed production expenses, depreciation and amortization expenses and interest charges, plus a targeted margin. Energy revenues are earned by selling electricity to our members, which involves generating or purchasing electricity for our members. Energy revenues recover the variable costs of our business, including fuel, purchased energy and variable operation and maintenance expense.
The components of member revenues for the three-month and nine-month periods ended September 30,March 31, 2017 and 2016 and 2015 were as follows:
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Three Months Ended September 30, | 2016 vs. 2015 % Change | Nine Months Ended September 30, | 2016 vs. 2015 % Change | Three Months Ended March 31, | 2017 vs. 2016 % Change | ||||||||||||||||||||||||
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(dollars in thousands) | (dollars in thousands) | (dollars in thousands) | |||||||||||||||||||||||||||
2016 | 2015 | 2016 | 2015 | 2017 | 2016 | ||||||||||||||||||||||||
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Capacity revenues | $ | 228,011 | $ | 187,259 | 21.8% | $ | 681,384 | $ | 577,411 | 18.0% | $ | 225,228 | $ | 224,924 | 0.1% | ||||||||||||||
Energy revenues | 202,872 | 130,864 | 55.0% | 476,750 | 360,636 | 32.2% | 128,916 | 123,173 | 4.7% | ||||||||||||||||||||
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Total | $ | 430,883 | $ | 318,123 | 35.4% | $ | 1,158,134 | $ | 938,047 | 23.5% | $ | 354,144 | $ | 348,097 | 1.7% | ||||||||||||||
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MWh Sales to members | 7,956,412 | 5,168,226 | 53.9% | 19,886,944 | 14,488,210 | 37.3% | 5,324,823 | 5,380,861 | (1.0%) | ||||||||||||||||||||
Cents/kWh | 5.42 | 6.16 | (12.0%) | 5.82 | 6.47 | (10.1%) | 6.65 | 6.47 | 2.8% | ||||||||||||||||||||
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The increase in member capacity sales was primarily a result of the recovery of fixed costs at the Smith and Hawk Road Energy Facilities which began in 2016. Prior to 2016, our members generally did not require the energy generation from Smith and Hawk Road and the effects of the costs and revenues of these plants on net margin were deferred.
The increase in energy revenues from members increased for the three-month and nine-month periods ended September 30, 2016March 31, 2017 compared to the same periodsperiod in 2015 was2016 primarily due to an increase in generation for member salesenergy costs at our natural gas-fired plants as a result of Smith and Hawk Road becoming available to the membershigher fuel costs in 2016.2017. Our members' ability to schedule these additional natural-gas fired facilities, which currently provide an economical source of energy due to low natural gas prices, significantly increased our megawatt-hour sales to our members and allowed uswere relatively unchanged for the three-month period ended March 31, 2017 compared to provide a larger percentagethe same period of our members' load requirements to date in 2016. The average energy revenue per kilowatt-hour from sales to members were relatively unchanged for the three-month period and decreased 3.7% for the nine-month period ended September 30, 2016, respectively,increased 2.8% as compared to the same periodsa result of 2015.increased energy costs. For a discussion of fuel costs, see "—Operating Expenses."
Sales to Non-members. Prior to 2016, sales to non-members primarily consisted of capacity and energy sales at Smith. Non-member sales decreased 100% for both the three-month and nine-month periods ended September 30, 2016 compared to the same periods of 2015 as Smith became available for scheduling by our members. We do not anticipate any significant non-member sales for the remainder of 2016.
Operating Expenses
The following table summarizes our fuel costs and megawatt-hour generation by generating source.
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Cost | Generation | Cents per kWh | Cost | Generation | Cents per kWh | |||||||||||||||||||||||||||||||||||||||||||||||||||
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(dollars in thousands) | (MWh) | (dollars in thousands) | (MWh) | |||||||||||||||||||||||||||||||||||||||||||||||||||||
Three Months Ended | 2016 vs. | Three Months Ended | 2016 vs. | Three Months Ended | 2016 vs. | Three Months Ended | 2017 vs. | Three Months Ended | 2017 vs. | Three Months Ended | 2017 vs. | |||||||||||||||||||||||||||||||||||||||||||||
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Fuel Source | 2016 | 2015 | 2015 % Change | 2016 | 2015 | 2015 % Change | 2016 | 2015 | 2015 % Change | 2017 | 2016 | 2016 % Change | 2017 | 2016 | 2016 % Change | 2017 | 2016 | 2016 % Change | ||||||||||||||||||||||||||||||||||||||
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Coal | $ | 49,478 | $ | 40,144 | 23.3% | 1,704,203 | 1,518,856 | 12.2% | 2.90 | 2.64 | 9.8% | $ | 19,629 | $ | 32,293 | (39.2%) | 661,135 | 1,105,030 | (40.2%) | 2.97 | 2.92 | 1.6% | ||||||||||||||||||||||||||||||||||
Nuclear | 21,950 | 21,992 | (0.2%) | 2,691,129 | 2,585,844 | 4.1% | 0.82 | 0.85 | (4.1%) | 20,542 | 18,805 | 9.2% | 2,277,498 | 2,317,510 | (1.7%) | 0.90 | 0.81 | 11.2% | ||||||||||||||||||||||||||||||||||||||
Gas: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Combined Cycle | 73,223 | 62,348 | 17.4% | 2,976,562 | 2,432,151 | 22.4% | 2.46 | 2.56 | (4.0%) | 61,747 | 41,495 | 48.8% | 2,480,997 | 1,966,483 | 26.2% | 2.49 | 2.11 | 17.9% | ||||||||||||||||||||||||||||||||||||||
Combustion Turbine | 33,865 | 17,658 | 91.8% | 846,699 | 396,581 | 113.5% | 4.00 | 4.45 | (10.2%) | 1,996 | 6,359 | (68.6%) | 42,806 | 159,478 | (73.2%) | 4.66 | 3.99 | 16.9% | ||||||||||||||||||||||||||||||||||||||
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$ | 178,516 | $ | 142,142 | 25.6% | 8,218,593 | 6,933,432 | 18.5% | 2.17 | 2.05 | 6.0% | $ | 103,914 | $ | 98,952 | 5.0% | 5,462,436 | 5,548,501 | (1.6%) | 1.90 | 1.78 | 6.7% | |||||||||||||||||||||||||||||||||||
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Cost | Generation | Cents per kWh | ||||||||||||||||||||||||||
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(dollars in thousands) | (MWh) | |||||||||||||||||||||||||||
Nine Months Ended | 2016 vs. | Nine Months Ended | 2016 vs. | Nine Months Ended | 2016 vs. | |||||||||||||||||||||||
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Fuel Source | 2016 | 2015 | 2015 % Change | 2016 | 2015 | 2015 % Change | 2016 | 2015 | 2015 % Change | |||||||||||||||||||
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Coal | $ | 114,961 | $ | 121,946 | (5.7%) | 3,945,663 | 4,327,741 | (8.8%) | 2.91 | 2.82 | 3.4% | |||||||||||||||||
Nuclear(1) | 61,786 | 57,469 | 7.5% | 7,605,266 | 7,631,162 | (0.3%) | 0.81 | 0.75 | 7.9% | |||||||||||||||||||
Gas: | ||||||||||||||||||||||||||||
Combined Cycle | 165,272 | 151,959 | 8.8% | 7,338,407 | 5,598,978 | 31.1% | 2.25 | 2.71 | (17.0%) | |||||||||||||||||||
Combustion Turbine | 62,037 | 34,388 | 80.4% | 1,644,184 | 687,372 | 139.2% | 3.77 | 5.00 | (24.6%) | |||||||||||||||||||
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$ | 404,056 | $ | 365,762 | 10.5% | 20,533,520 | 18,245,253 | 12.5% | 1.97 | 2.00 | (1.8%) | ||||||||||||||||||
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Total fuel costs increased for the three-month and nine-month periods ended September 30, 2016 as compared to the same periods of 2015was primarily due to increased generation at our natural gas-fired facilities. See "—Operating Revenues." The increase for the three-month period ended September 30, 2016 compared to the same period of 2015 was also partially due to increased generation at our relatively more expensive coal-fired facilities, which resulted in a 6.0%an increase in the average cost per kilowatt-hour of generation. An increase in nuclear fuel burn expense for the nine-month period ended September 30, 2016 compared to the same period of 2015 also contributed to the increase in total fuel costs for the period. During the first quarter of 2015, we recognized a $7.1 million reduction in fuel expense associated with the recovery of spent nuclear fuel storage costs from the U.S. Department of Energy. Somewhat offsetting the effect of increased generation on nine-month total fuel costs was a decrease in the average cost per kilowatt-hour of generation largely as a result ofnatural gas prices partially offset by a shift in the generation mix from the coal-fired unitsgeneration to the relatively more economical natural gas-fired combined cycle units.
Production costs increased 11.8% for the three-month period ended September 30, 2016 from the same period of 2015, primarily as a result of major maintenance work at certain of our natural gas-fired plants. For the nine-month period ended September 30, 2016, production costs decreased 7.5% from the same period of 2015 due to somewhat higher planned major maintenance work at Smith and Hawk Road in the first half of 2015.
Depreciation and amortization expense increased 28.8% and 26.9% for the three-month and nine-month periods ended September 30, 2016 compared to the same periods of 2015. The increase was primarily due to the January 1, 2016 adoption of revised depreciation rates for our co-owned coal-fired and nuclear facilities which average 2.55% and 1.89%, respectively. We anticipate the effect of the revised rates will increase depreciation expense for the year by approximately $24.0 million. The increases in the depreciation rates were largely due to capital additions for environmental controls and costs associated with interim retirements. The increase in depreciation and amortization expense was also due in part to the 2015 completion of the amortization of a deferred liability associated with the Hawk Road acquisition as well as an increase in depreciation associated with certain asset retirement obligations.
Financial Condition
Balance Sheet Analysis as of |
Assets
Cash used for property additions for the nine-monththree-month period ended September 30, 2016March 31, 2017 totaled $421.4$171.8 million. Of this amount, approximately $246.6$158.2 million was associated with construction expenditures for Vogtle Units No. 3 and No. 4 $46.2and $15.2 million for nuclear fuel purchases and the remaining expenditures were for normal additions and replacements to our existing generation facilities.purchases.
Restricted cash and investments consist primarily of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account. The funds, including interest earned thereon, can only be applied to debt service on Rural Utilities Service andour Rural Utilities Service-guaranteed Federal Financing Bank notes. Decisions regarding when to apply the funds are guided by the interest rate environment and our anticipated liquidity needs.
Receivables increased $43.3 million for the nine-month period ended September 30, 2016 primarily as a result of amounts billed or billable to the members due to higher energy costs during the period, which were a result of increased generation.
Inventories decreased $45.7 million for the nine-month period ended September 30, 2016 primarily due to a decline in inventory purchases at our coal-fired plants.
Equity and Liabilities
Long-term debt increased $594.3 million due to the issuance of 2016A First Mortgage Bonds, Department of Energy loan guarantee advances and Rural Utilities Service-guaranteed loan advances during the nine-month period ended September 30, 2016 for the purpose of providing long-term financing for the Vogtle construction project and other general and environmental expenditures. For additional information on these borrowings, see Note K of Notes to Unaudited Consolidated Financial Statements.
Long-term debt and capital leases due within one year decreased $37.3$163.6 million. In January 2017, we temporarily refinanced $122.6 million due to the reclassification of certain variable rate demand bond debt to long-term debt as a resultpollution control revenue bonds through the issuance of commercial paper. In addition, we made quarterly Federal Financing Bank note payments, when due, during the extension of the underlying credit facility that supports the bonds. For additional information regarding the credit facility, see Note K of Notes to Unaudited Consolidated Financial Statements.period.
Short-term borrowings, which primarily provide interim financing for Vogtle Units No. 3 and No. 4 construction costs, decreased $105.2increased $226.7 million during the nine-monththree-month period ended September 30, 2016. Total borrowings and repayments duringMarch 31, 2017. In addition to providing financing for the period were $324.5Vogtle project, $122.6 million and $429.7 million, respectively. The repayments were refinanced with long-term debt through a portion of the first mortgage bonds issued in April 2016 and underincrease was attributable to the Departmentrefinancing of Energy guaranteed-loan. See Note K of Notes to Unaudited Consolidated Financial Statements for information regarding the debt issuances.
Table of Contentsvariable rate pollution control revenue bonds.
Accounts payable decreased $87.8increased $19.5 million for the nine-monththree-month period ended September 30, 2016March 31, 2017 primarily as a result of a $93.1$45.6 million decreaseincrease in the payable to Georgia Power Company for operation and maintenance costs for our co-owned plants and capital costs associated with Vogtle Units No. 3 and No. 4. Also contributing toOffsetting the decreaseincrease was $9.2$17.2 million in credits applied to our members' bills in the first quarter of 2016,2017, for a board approved reduction in 20152016 revenue requirements as a result of margin collections in excess of our 20152016 target. Offsetting
Accrued interest decreased $35.3 million for the decrease was an increase in payables related to natural gas purchases.
Asset retirement obligations increased $96.0 million during the nine-monththree-month period ended September 30, 2016March 31, 2017 primarily as a result of amounts paid, when due, to changes in cash flow estimates associated with future coal ash pond related decommissioning costs and partially due to increases in the current year's accreted value of all of our asset retirement obligations. See Note L of Notes to Unaudited Consolidated Financial Statements for information regarding the impact of the final CCR rule on asset retirement obligations.Federal Financing Bank note payments.
Capital Requirements and Liquidity and Sources of Capital |
Vogtle Units No. 3 and No. 4.4
For additional information on Vogtle Units No. 3 and No. 4, see "Item 1—BUSINESS—OUR POWER SUPPLY RESOURCES—Future Power Resources—Vogtle Units No. 3 and No. 4" in our 2015 Form 10-K and "Item 2—Management's Discussion and Analysis of Financial Condition and Results of Operations—Financial Condition—Capital Requirements and Liquidity and Sources of Capital—Vogtle Units No. 3 and No. 4" in our June 30, 2016 Form 10-Q.
In 2008,We, Georgia Power, acting for itself and as agent for us, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, doing business as Dalton Utilities (collectively, the Co-owners) 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 binding 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. As of March 31, 2017, our total investment in the additional Vogtle units was approximately $3.4 billion.
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. (collectively, the Contractor) entered into an Engineering, Procurement. Stone & Webster was subsequently acquired by Westinghouse and Construction Agreement (the EPC Agreement)changed its name to WECTEC Global Project Services Inc. (WECTEC). Pursuant to the EPC Agreement, the Contractor willagreed to design, engineer, procure, construct and test two 1,100 megawatt nuclear units using the Westinghouse AP1000 technology and related facilities at Plant Vogtle, Units No. 3 and No. 4. Our ownership interest and proportionate share of the cost to construct these units is 30%.Vogtle.
Under the EPC Agreement, the Co-owners willagreed to pay a purchase price that is subject to certain price escalations and adjustments, including fixed escalation amounts and certain index-based adjustments, as well as adjustments for change orders and performance bonuses. The EPC Agreement also provides for liquidated damages upon the Contractor's failure to fulfill the schedule and certain performance guarantees, each subject to a cap.an aggregate cap of 10% of the contract price, or
approximately $920 million. In addition, the EPC Agreement provides for limited cost sharing by the Co-owners for increases to Contractor costs under certain conditions. The maximum amount of additional capital costs under this provision attributable to us is $75 million. Each Co-owner is severally, and not jointly, liable to the Contractor for its proportionate share, based on its ownership interest, of all amounts owed under the EPC Agreement. AsIn the event of a credit rating downgrade below investment grade of any Co-owner, that Co-owner will be required to provide a letter of credit or other credit enhancement.
Under the terms of the EPC Agreement, the Contractor does not have a right to terminate the EPC Agreement for convenience. The Contractor may terminate the EPC Agreement under certain circumstances, including certain Co-owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the EPC Agreement by the Co-owners, Co-owner insolvency, and certain other events. In the event of an abandonment of work by the Contractor, the maximum liability of the Contractor under the EPC Agreement is increased to 40% of the contract price (approximately $1.1 billion based on our ownership interest). The EPC Agreement permits Georgia Power, acting for itself and as agent for the Co-owners, to terminate the EPC Agreement at any time for convenience; provided that the Co-owners will be required to pay certain termination costs. In addition, Georgia Power, acting for itself and as agent for the Co-owners, may terminate the EPC Agreement for certain Contractor breaches, including abandonment of work by the Contractor.
Toshiba Corporation, parent company of Westinghouse, has guaranteed certain payment obligations of the Contractor under the EPC Agreement, including any liability of the Contractor for abandonment of work (the Toshiba Guarantee). However, due to Toshiba's financial situation described below, substantial risk regarding the Co-owners' ability to fully collect under the Toshiba Guarantee exists. In January 2016, Westinghouse delivered to the Co-owners $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the Contractor's potential obligations under the EPC Agreement. The Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020, and require 60 days' written notice to Georgia Power, as agent of the Co-owners, in the event the Westinghouse Letters of Credit will not be renewed. In the event of such notice, Georgia Power, as agent of the Co-owners, would be able to draw on the entire balance of the Westinghouse Letters of Credit. The Westinghouse Letters of Credit remain in place in accordance with the terms of the EPC Agreement.
On March 29, 2017, Westinghouse and WECTEC each filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. Georgia Power, acting for itself and as agent for the other Co-owners, entered into an Interim Assessment Agreement with the Contractor and WECTEC Staffing Services LLC (WECTEC Staffing), dated as of March 29, 2017 (the Interim Assessment Agreement), to provide for a continuation of work with respect to Vogtle Units No. 3 and No. 4. The provisions in the Interim Assessment Agreement became effective upon approval of the Interim Assessment Agreement by the bankruptcy court on March 30, 2017. The term of the Interim Assessment Agreement was originally scheduled to expire on April 28, 2017. On April 28, 2017, Georgia Power, acting for itself and as agent for the other Co-owners, entered into an amendment to the Interim Assessment Agreement with the Contractor and WECTEC Staffing solely to extend the term of the Interim Assessment Agreement through the earlier of (i) May 12, 2017 and (ii) termination of the Interim Assessment Agreement by any party upon five business days' notice (the Interim Assessment Period).
The Interim Assessment Agreement provides, among other items, that (i) Georgia Power will be obligated to pay, on behalf of the Co-owners, all costs accrued by the Contractor for subcontractors and vendors for services performed or goods provided during the Interim Assessment Period, with these amounts to be paid to the Contractor, except for amounts accrued for Fluor Corporation (Fluor), which will be paid directly to Fluor, (ii) during the Interim Assessment Period, the Contractor shall
provide certain engineering, procurement and management services for Vogtle Units No. 3 and No. 4, to the same extent as contemplated by the EPC Agreement, and Georgia Power, on behalf of the Co-owners, will make payments of $5.4 million per week for these services, (iii) Georgia Power will have the right to make payments, on behalf of the Co-owners, directly to subcontractors and vendors who have accounts past due with the Contractor, (iv) during the Interim Assessment Period, the Contractor will use its commercially reasonable efforts to provide information reasonably requested by Georgia Power as is necessary to continue construction and investigate the completion status of Vogtle Units No. 3 and No. 4, (v) the Contractor will reject or accept the EPC Agreement by the termination of the Interim Assessment Agreement, and (vi) during the Interim Assessment Period, Georgia Power, on behalf of the Co-owners, will not exercise any remedies against Toshiba under the Toshiba Guarantee. Under the Interim Assessment Agreement, all parties expressly reserve all rights and remedies under the EPC Agreement, all related security and collateral, under applicable law.
A number of subcontractors to the Contractor, including Fluor Enterprises Inc. (Fluor Enterprises), have alleged non-payment by the Contractor for amounts owed for work performed on Vogtle Units No. 3 and No. 4. Georgia Power, acting for itself and as agent for the Co-owners, has taken, and continues to take, action to remove liens filed by these subcontractors through the posting of surety bonds.
Georgia Power estimates the aggregate liability for the Co-owners under the Interim Assessment Agreement and the removal of subcontractor liens to be approximately $470 million, of which our proportionate share would total approximately $141 million. As of March 31, 2017, $245 million of this aggregate liability had been paid or accrued. Georgia Power is evaluating remedies available to the Co-owners for these payments, including draws under the Westinghouse Letters of Credit and enforcement of the Toshiba Guarantee. Georgia Power, as agent for the Co-owners, has begun the process to access a portion of the funds available under the Westinghouse Letters of Credit.
In February 2017, the Contractor provided Georgia Power, as agent for the Co-owners, with revised forecasted in-service dates of December 2019 and September 2020 for Vogtle Units No. 3 and No. 4, respectively. However, we and Georgia Power do not believe the revised in-service dates are achievable. Georgia Power, along with the other Co-owners, is undertaking a comprehensive schedule and cost-to-complete assessment, as well as a cancellation cost assessment. It is reasonably possible these assessments result in estimated incremental costs to complete, including Co-owners' costs, that materially exceed the value of the Toshiba Guarantee. We intend to work with Georgia Power and the other Co-owners to determine future actions related to Vogtle Units No. 3 and No. 4. Georgia Power has designatedstated that it is working with the Georgia Public Service Commission in regards to this same determination. Georgia Power, for itself and as agent for the other Co-owners, is also negotiating a new service agreement which would, if necessary, engage the Contractor to provide design, engineering, and procurement services to Southern Nuclear, Operating Company asin the event Southern Nuclear assumes control over construction management of Vogtle Units No. 3 and No. 4. In addition, Georgia Power, on behalf of itself and the other Co-owners, intends to take all actions available to it to enforce its agent for contract management.rights related to the EPC Agreement, including enforcing the Toshiba Guarantee, subject to the Interim Assessment Agreement, and accessing the Westinghouse Letters of Credit.
On April 11, 2017, Toshiba filed its unaudited financial statements as of and for the nine months ended December 31, 2015, Westinghouse acquired Stone & Webster, Inc. from Chicago Bridge & Iron Co. N.V. (the Acquisition). In2016, which reflected a negative shareholders' equity balance of $1.9 billion, with Japanese regulators. Toshiba also announced that further substantial charges may be required in the quarter ended March 31, 2017 in connection with the Acquisition, Stone & Webster, Inc. changed its namebankruptcy filing of Westinghouse and WECTEC and that there are material events and conditions that raise substantial doubt about Toshiba's ability to WECTEC Global Project Services Inc. (WECTEC). In connection with the Acquisition, Westinghouse engaged Fluor Enterprises, Inc., a subsidiary of Fluor Corporation,continue as a newgoing concern.
The Contractor's bankruptcy filing is expected to have a material impact on the construction subcontractor.cost and schedule of Vogtle Units No. 3 and No. 4 and could have a material impact on our financial condition
Our project budget,and results of operations. In addition, an inability or other failure by Toshiba to perform its obligations under the Toshiba Guarantee could have a material impact on the cost to the Co-owners of Vogtle Units No. 3 and No. 4, and, therefore, on our financial condition and results of operations.
We have a $3.1 billion federal loan guarantee from the Department of Energy, under which includeswe have advanced $1.7 billion as of March 31, 2017. We have also financed an additional $1.4 billion of the capital costs allowance for funds used during construction and a contingency amount, is $5.0 billion. As of September 30, 2016, our total investment in the additional Vogtle units was $3.2 billion.through capital market debt issuances. A failure by the Contractor to perform its obligations under the EPC Agreement could, under certain circumstances, impact our ability to make further advances under the Department of Energy-guaranteed loan and give the Department of Energy discretion to require that we repay all amounts outstanding under the loan guarantee agreement over a five-year period. For additional information regarding the financing of Vogtle Units No. 3 and No. 4,
see "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION—Financial Condition—Financing"Financing Activities—Department of Energy-Guaranteed Loan"Loan" and "—Capital Requirements—Capital Expenditures"for additional information regarding applicable covenants, events of default and potential repayment over a five year period under the loan guarantee agreement with the Department of Energy, see Note 7(a)K of Notes to Unaudited Consolidated Financial Statements in our 2015 Form 10-K.Statements.
Although the Contractor's performance has improved, certain near-term milestonesThere have recently been missed, particularly in regard to Unit No. 3. Duetechnical and procedural challenges to the Contractor's inability to meet these milestones, the riskconstruction and licensing of Unit No. 3 not being operational by the current estimated in-service date of June 2019 has increased and a several month delay is likely. The Contractor's progress on Unit No. 4 indicates that the current estimated in-service date of June 2020 for Unit No. 4 remains achievable, but risks remain. We expect the Contractor to employ mitigation efforts to maintain the current project schedule, if possible, and believe the Contractor is responsible for any related costs for not achieving the schedule and performance guarantees in the EPC Agreement. Although many factors could ultimately impact our project budget, we anticipate that our current budget contains an adequate contingency to cover up to a one-year delay in the estimated in-service date for UnitVogtle Units No. 3 and a several month delayNo. 4 at the federal and state level and additional challenges may arise as construction proceeds. Processes are in place that are designed to assure compliance with the requirements specified in the estimated in-service date for Unit No. 4, if necessary.
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 construction continues,a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the risk remains that continued challenges with the Contractor's performance, including labor productivity, fabrication, delivery, assembly and installation of plant systems, structures and components, or other issues could further impact the project schedule and cost. Further, variousNuclear Regulatory Commission. Various design and other licensing-based compliance matters, including the timely resolution of inspections, tests, analysesInspections, Tests, Analyses, and acceptance criteriaAcceptance Criteria and the related approvals by the Nuclear Regulatory Commission, may arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be further delays in the project schedule that could result in increased costs tocosts.
As construction continues, the Co-owners, the Contractor,risk remains that challenges with labor productivity, fabrication, delivery, assembly, and installation of plant systems, structures, and components, or both. As discussed under "Item 1—BUSINESS—OUR POWER SUPPLY RESOURCES—Future Power Resources—Vogtle Units No. 3 and No. 4" and "Item 1A—RISK FACTORS" in our 2015 Form 10-K, other issues could arise and may further impact the project schedule and cost. Our previously estimated owner's and financing costs of approximately $20 million per month in the near term for Vogtle Units No. 3 and No. 4 are being evaluated as part of the comprehensive schedule and cost-to-complete analysis being performed as a result of the Contractor's bankruptcy.
The ultimate outcome of these matters cannot be determined at this time. See "Risk Factors" in this Form 10-Q for risks regarding the Contractor's bankruptcy and the Toshiba Guarantee and "Item 1A—Risk Factors" in our 2016 Form 10-K for a discussion of certain risks associated with the licensing, construction, financing and operation of nuclear generating units.
Environmental Regulations
Existing federalFederal and state laws and regulations regarding environmental matters continue to affect operations at our facilities. Following are some substantial developments relating to environmental regulations and litigation that have occurred since the filing of our June 30, 2016 Form 10-Q10-K.
In March 2017, the President issued an Executive Order to Promote Energy Independence and Economic Growth. As a result of this Executive Order, many existing and proposed regulations related to the energy industry will be reviewed. EPA will be reviewing a number of regulations in connection with this order and has stated that its review will include (i) Steam Electric Power Generating Effluent Guidelines, (ii) State Implementation Plans related to Startup, Shutdown and Malfunction Emissions at Industrial Facilities, and (iii) the Clean Water Rule: Definition of "Waters of the United States." EPA
may elect to evaluate other energy related regulations. It is unknown what impact the operationpotential rule changes will have on our and our members' operations. Continued uncertainty related to the status of our facilities.current and future environmental regulations may make long-term planning decisions more difficult.
In 2015, the U.S. Environmental Protection Agency (EPA) published in theFederal Register its final Clean Power Plan, which establishes guidelines for the states to follow when developing any final New Source Performance Standards (NSPS) for existing fossil fuel-fired electric generating units. Subsequently, these final rules were challenged in the U.S. Court of Appeals for the District of Columbia Circuit. On February 9, 2016, the U.S. Supreme Court granted numerous applications to stay the Clean Power Plan, pending resolution of these cases before the D.C. Circuit. The stay would continue if the case proceeds for resolution to the U.S. Supreme Court. On Sept. 27, 2016, the consolidated cases challenging the issuance of the Clean Power Plan were argued before the full D.C. Circuit. We are now awaitingThe D.C. Circuit Court has not issued a decision from this Court, which may not be issued until sometime in 2017. Regardlessdecision. The Clean Power Plan is being reviewed as part of the outcome of that decision,Executive Order to promote Energy Independence and all litigation will be held in abeyance for 60 days while the case will then likely be appealedrules are being reviewed. EPA could continue with the current rule, revise the rule or rescind the rule. Any revisions to the U.S. Supreme Court.rule could be litigated in the future. We cannot determine the outcome of: (i) these EPA rules; (ii) any rules the State of Georgia may issue in response to the Clean Power Plan; or (iii) any litigation challenging EPA'sEPA or Georgia's rules. NorGeorgia rules, nor can we predict how any of these outcomes may affect our or our members' operations. We anticipate that some of the policy approaches set forth in the Clean Power Plan could have significant negative consequences for the economy and electric system in Georgia and the nation, if the guidelines are implemented as finalized by EPA.
On September 7, 2016, EPA issued its final Cross State Air Pollution Rule (CSAPR) Update for the 2008 ozone national ambient air quality standards (NAAQS). In the final rule, EPA issued Federal Implementation Plans (FIPs) for 22 eastern states (notstates—not including Georgia),Georgia, which generally provide updated CSAPR NOx ozone season emissions budgets for the electric generating units within such states, beginning with the 2017 ozone season, May 1, 2017-September 30, 2017.season. In the rule, EPA determined that emissions from Georgia (and 13 other states) do not significantly contribute to nonattainment or interfere with maintenance of the 2008 ozone NAAQS in downwind states, so that further emission reductions from sources in these states to meet the 2008 ozone NAAQS are not required. Georgia is now the only state determined not to contribute to nonattainment with maintenance of the 2008 ozone NAAQS but which still has an ongoing requirement with respect to the 1997 ozone NAAQS, which will continuecontinues unchanged. Ultimately, the final CSAPR update proposes two trading programs for NOx ozone season: (i) a Group 1 program, to which only Georgia belongs, and (ii) a Group 2 program that contains the 22 states mentioned previously. EPA will issue distinct allowances for both trading groups. The rule allows Georgia to maintain its allowances but precludes out-of-state trading, unless existing allowances are first devalued by a factor of 3.5. The rule provides an option forState of Georgia has decided to voluntarily opt into thestay in Group 2 trading program by voluntarily adopting an updated rule emission budget.1. We continue to evaluate thesethis trading programsprogram and cannot predict the ultimate outcome of this rulemaking or any ensuing litigation that may occur.
On April 17, 2015, the final coal combustion residuals (CCR) rule was published by EPA. The rule classified CCR as non-hazardous and outlined the requirements for disposing and storing ash from electric utilities. The method of enforcement of the federal rule is through citizen suits. Each state may adopt the federal rules into its own program and may add to the federal requirements. The State of Georgia Environmental Protection Division (EPD) developed a proposed CCR rule that was approved by the Department of Natural Resources Board on October 26, 2016. The EPD rule adopts the federal rule by reference and develops a permitting process for all CCR disposal facilities. The Georgia rule also includes "inactive" facilities that are exempt in the federal rule. As a result of the rule, EPD permits will be required for the CCR disposal facilities and the co-owned plants Scherer and Wansley. Through the permitting process, the public will be allowed to comment and final permits issued by EPD can be appealed and eventually litigated. The rule is expected to be effective in late 2016 and is not expected to have a material impact on compliance with the CCR regulations.
For further discussion regarding potential effects on our business from environmental regulations, including potential capital requirements, see "Item 1—BUSINESS—REGULATION—Environmental," "Item 1A—RISK FACTORS" and "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Capital Requirements—Capital Expenditures" in our 20152016 Form 10-K.
Liquidity
At September 30, 2016,March 31, 2017, we had $1.6$1.3 billion of unrestricted available liquidity to meet our short-term cash needs and liquidity requirements. This amount included $363$279 million in cash and cash equivalents and $1.2$1.0 billion of unused and available committed credit arrangements.
At September 30, 2016,March 31, 2017, we had $1.61 billion of committed credit arrangements in place, the details of which are reflected in the table below:
| | | | | | | | | | | | | | | ||
Committed Credit Facilities | Committed Credit Facilities | Committed Credit Facilities | ||||||||||||||
| | | | | | | | | | | | | | | | |
Authorized | Available | Expiration Date | Authorized | Available | Expiration Date | |||||||||||
| | | | | | | | | | | | | | | | |
(dollars in millions) | (dollars in millions) | |||||||||||||||
Unsecured Facilities: | ||||||||||||||||
Syndicated Line of Credit led by CFC | $ | 1,210 | (1) | $ | 918 | (2) | March 2020 | $ | 1,210 | $ | 745 | (1) | March 2020 | |||
CFC Line of Credit | 110 | 110 | December 2018 | 110 | 110 | December 2018 | ||||||||||
JPMorgan Chase Line of Credit | 150 | 34 | (4) | October 2018 | 150 | 34 | (3) | October 2018 | ||||||||
Secured Facilities: |
|
| ||||||||||||||
CFC Term Loan | 250 | 250 | December 2018 | 250 | 250 | December 2018 | ||||||||||
| | | | | | | | | | | | | | | | |
In October, we renewed for another two years our $150 million line of credit with JPMorgan Chase Bank that was set to expire in November 2016.
Currently, we are primarily using our commercial paper program to provide interim funding for payments related to the construction of Vogtle Units No. 3 and No. 4 prior to receiving advances of long-term funding under the Department of Energy-guaranteed Federal Financing Bank loan, which can be requested no more frequently than quarterly. Between our credit arrangements and projected cash on hand, we believe we have sufficient liquidity to cover our normal operations and to provide interim financing for the Vogtle units under construction.
Under our commercial paper program, we are authorized to issue commercial paper in amounts that do not exceed the amount of our committed backup lines of credit, thereby providing 100% dedicated support for any commercial paper outstanding. Our commercial paper program is currently sized at $1.0 billion.
Under our unsecured committed lines of credit, we have the ability to issue letters of credit totaling $760 million in the aggregate, of which $509 million remained available at September 30, 2016.March 31, 2017. However, amounts related to issued letters of credit reduce the amount that would otherwise be available to draw for working capital needs. Also, due to the requirement to have 100% dedicated backup for any commercial paper outstanding, any amounts drawn under our committed credit facilities for working capital or related to issued letters of credit will reduce the amount of commercial paper that we can issue. The majority of our outstanding letters of credit are for the purpose of providing credit enhancement on variable rate demand bonds.
Two of our credit facilities contain a financial covenant that requires us to maintain minimum levels of patronage capital. At September 30, 2016,March 31, 2017, the required minimum level was $675 million and our actual patronage capital was $872$881 million. These agreements contain an additional covenant that limits our secured indebtedness and unsecured indebtedness, both as defined in the credit agreements, to $12.0 billion and $4.0 billion, respectively. At September 30, 2016,March 31, 2017, we had $8.1 billion of secured indebtedness and $156$329 million of unsecured indebtedness outstanding.
At September 30, 2016,March 31, 2017, we had $451$431 million on deposit in the Rural Utilities Service Cushion of Credit Account, all of which is classified as a restricted investment. See "—Balance Sheet Analysis as of September 30, 2016—March 31, 2017—Assets" for more information regarding this account.
Financing Activities
First Mortgage Indenture. At September 30, 2016,March 31, 2017, we had $8.1 billion of long-term debt outstanding under our first mortgage indenture secured equally and ratably by a lien on substantially all of our owned tangible and certain of our intangible property, including property we acquire in the future. See "Item 1—BUSINESS—OGLETHORPE POWER CORPORATION—First Mortgage Indenture" in our 20152016 Form 10-K for further discussion of our first mortgage indenture.
Rural Utilities Service-Guaranteed Loans. At September 30, 2016,March 31, 2017, we had two approved Rural Utilities Service-guaranteed loans being funded through the Federal Financing Bank that are in various stages of being drawn down. These two loans totaled $678 million with $506$501 million remaining to be advanced. When advanced, the debt will be secured under our first mortgage indenture. As of September 30, 2016,March 31, 2017, we had $2.6$2.5 billion of debt outstanding under various Rural Utilities Service-guaranteed loans.
Department of Energy-Guaranteed Loan. In February 2014, we closed on a loan with the Department of Energy that will fund up to $3.057$3.1 billion of eligible project costs related to the cost to construct our 30% undivided share of Vogtle Units No. 3 and No. 4. This loan is being funded by the Federal Financing Bank and is backed by a federal loan guarantee provided by the Department of Energy.
As of September 30, 2016, our total investment in Vogtle Units No. 3 and No. 4 was $3.2March 31, 2017, we had advanced $1.7 billion under this loan and we have incurred $2.9 billion of debt to provide long-term financing for this investment. This long-term debt includes $1.4 billion of taxable first mortgage bonds and $1.5 billion, including capitalized interest, under the Department of Energy loan facility. The facility may be used until no later than December 2020 to provide long-term funding for eligible project costs after they are incurred. As of September 30, 2016, we havehad the capacity to fund an additional $555$538 million under the facility based on the amount of eligible project costs we have incurred to date. We anticipate making draws on at least a semi-annual basis to meet our funding requirements as construction progresses. When advanced,already incurred. All of the debt under this loan will be secured ratably with all other debt under our first mortgage indenture. Continued access to the committed funds under this loan requires us to meet certain conditions related to our business and the Vogtle project and also requires certain third-parties related to the Vogtle project to comply with certain laws. In addition, a failure by the Contractor to perform its obligations under the EPC Agreement could, under certain circumstances, impact our ability to make further advances under this loan and give the Department of Energy discretion to require that we repay all amounts outstanding under the loan over a five-year period. For additional information regarding this loan, see Note K of Notes to Unaudited Consolidated Financial Statements.
In addition to the Department of Energy loan funding, we have issued $1.4 billion of first mortgage bonds to finance a substantial portion of the Vogtle expansion that will not be funded by the Department of Energy. As of March 31, 2017, we had $3.1 billion of long-term funding in place for the $3.4 billion invested in the Vogtle project to-date. Depending on the final Vogtle project cost, and the final amount advanced under the Department of Energy-guaranteed loan, there may be a need for additional capital market financing.
For more detailed information regarding our financing plans, see "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Financing Activities" in our 20152016 Form 10-K.
Newly Adopted or Issued Accounting Standards
For a discussion of recently issued or adopted accounting pronouncements, see Note E of Notes to Unaudited Consolidated Financial Statements.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
There have not been any material changes to market risks from those reported in "Item 7A—QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK" of our 20152016 Form 10-K.
Item 4. Controls and Procedures
As of September 30, 2016,March 31, 2017, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended. Based on this
evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures are effective.
There have been no changes in internal control over financial reporting or other factors that occurred during the quarter ended September 30, 2016March 31, 2017 that have materially affected, or are reasonably likely to affect, our internal control over financial reporting.
Other than as disclosed in "Part II—Item 1. Legal Proceedings" in our Form 10-Q for the quarterly period ended June 30, 2016 and Form 10-Q for the quarterly period ended March 31, 2016, thereThere have been no material changes to the legal proceedings disclosed in "Item 3—LEGAL PROCEEDINGS" in our 20152016 Form 10-K.
ThereExcept as discussed below, there have been no material changes from the risks disclosed in "Item 1A—RISK FACTORS" ofin our 20152016 Form 10-K.
The bankruptcy filing of Westinghouse and WECTEC is expected to have a material impact on the construction cost and schedule of Vogtle Units No. 3 and No. 4 and could have a material impact on our financial condition and results of operations, and any inability or other failure by Toshiba to perform its obligations under the Toshiba Guarantee could have a material impact on the cost to the Co-owners of Vogtle Units No. 3 and No. 4, and therefore on our financial condition and results of operations.
On March 29, 2017, Westinghouse and WECTEC each filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. Georgia Power, acting for itself and as agent for the Co-owners, entered into an Interim Assessment Agreement with the Contractor and WECTEC Staffing, dated March 29, 2017, to provide for a continuation of work with respect to Vogtle Units No. 3 and No. 4. The provisions in the Interim Assessment Agreement became effective upon approval of the Interim Assessment Agreement by the bankruptcy court on March 30, 2017. The term of the Interim Assessment Agreement was originally scheduled to expire on April 28, 2017. On April 28, 2017, Georgia Power, acting for itself and as agent for the other Co-owners, entered into an amendment to the Interim Assessment Agreement with the Contractor and WECTEC Staffing solely to extend the term of the Interim Assessment Agreement through the earlier of (i) May 12, 2017 and (ii) termination of the Interim Assessment Agreement by any party upon five business days' notice.
The Interim Assessment Agreement provides, among other items, that (i) Georgia Power will be obligated to pay, on behalf of the Co-owners, all costs accrued by the Contractor for subcontractors and vendors for services performed or goods provided during the Interim Assessment Period, with these amounts to be paid to the Contractor, except for amounts accrued for Fluor, which will be paid directly to Fluor; (ii) during the Interim Assessment Period, the Contractor shall provide certain engineering, procurement and management services for Vogtle Units No. 3 and No. 4, to the same extent as contemplated by the EPC Agreement, and Georgia Power, on behalf of the Co-owners, will make payments of $5.4 million per week for these services; (iii) Georgia Power will have the right to make payments, on behalf of the Co-owners, directly to subcontractors and vendors who have accounts past due with the Contractor; (iv) during the Interim Assessment Period, the Contractor will use its commercially reasonable efforts to provide information reasonably requested by Georgia Power as is necessary to continue construction and investigate the completion status of Vogtle Units No. 3 and No. 4; (v) the Contractor will reject or accept the EPC Agreement by the termination of the Interim Assessment Agreement; and (vi) during the Interim Assessment Period, Georgia Power, on behalf of the Co-owners, will not exercise any remedies against Toshiba under the Toshiba Guarantee. Under the Interim Assessment Agreement, all parties expressly reserve all rights and remedies under the EPC Agreement, all related security and collateral, under applicable law.
A number of subcontractors to the Contractor, including Fluor Enterprises, have alleged non-payment by the Contractor for amounts owed for work performed on Vogtle Units No. 3 and No. 4. Georgia Power, acting for itself and as agent for the Co-owners, has taken, and continues to take, action to remove liens filed by these subcontractors through the posting of surety bonds.
Georgia Power estimates the aggregate liability for the Co-owners under the Interim Assessment Agreement and the removal of subcontractor liens to be approximately $470 million, of which our proportionate share would total approximately $141 million. As of March 31, 2017, $245 million of this
aggregate liability had been paid or accrued. Georgia Power is evaluating remedies available to the Co-owners for these payments, including draws under the $920 million of Westinghouse Letters of Credit and enforcement of the Toshiba Guarantee. Georgia Power, as agent for the Co-owners, has begun the process to access a portion of the funds available under the Westinghouse Letters of Credit.
The EPC Agreement also provides for liquidated damages upon the Contractor's failure to fulfill the schedule and certain performance guarantees, each subject to an aggregate cap of 10% of the contract price, or approximately $920 million. In the event of an abandonment of work by the Contractor, the maximum liability of the Contractor under the EPC Agreement is increased to 40% of the contract price (approximately $1.1 billion based on our ownership interest). The Co-owners may terminate the EPC Agreement at any time for convenience, provided that the Co-owners will be required to pay certain termination costs. In addition, the Co-owners may terminate the EPC Agreement for certain Contractor breaches, including abandonment of work by the Contractor.
Under the Toshiba Guarantee, Toshiba has guaranteed certain payment obligations of the Contractor, including any liability of the Contractor for abandonment of work. However, due to Toshiba's financial situation described below, substantial risk regarding the Co-owners' ability to fully collect under the Toshiba Guarantee exists. In January 2016, Westinghouse delivered to the Co-owners the Westinghouse Letters of Credit from financial institutions in an amount of $920 million to secure a portion of the Contractor's potential obligations under the EPC Agreement. The Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020, and require 60 days' written notice to Georgia Power, as agent of the Co-owners, in the event the Westinghouse Letters of Credit will not be renewed. In the event of such notice, Georgia Power, as agent of the Co-owners, would be able to draw on the entire balance of the Westinghouse Letters of Credit. The Westinghouse Letters of Credit remain in place in accordance with the terms of the EPC Agreement.
On April 11, 2017, Toshiba filed its unaudited financial statements as of and for the nine months ended December 31, 2016, which reflected a negative shareholders' equity balance of $1.9 billion, with Japanese regulators. Toshiba also announced that further substantial charges may be required in the quarter ended March 31, 2017 in connection with the bankruptcy filing of Westinghouse and WECTEC and that there are material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern.
In February 2017, the Contractor provided Georgia Power, as agent for the Co-owners, with revised forecasted in-service dates of December 2019 and September 2020 for Vogtle Units No. 3 and No. 4, respectively. However, we and Georgia Power do not believe the revised in-service dates are achievable. Georgia Power, along with the other Co-owners, is undertaking a comprehensive schedule and cost-to-complete assessment, as well as a cancellation cost assessment. It is reasonably possible these assessments result in estimated incremental costs to complete, including Co-owners' costs, that materially exceed the value of the Toshiba Guarantee. We intend to work with Georgia Power and the other Co-owners to determine future actions related to Vogtle Units No. 3 and No. 4. Georgia Power has stated that it is working with the Georgia Public Service Commission in regards to this same determination. Georgia Power, for itself and as agent for the other Co-owners, is also negotiating a new service agreement which would, if necessary, engage the Contractor to provide design, engineering, and procurement services to Southern Nuclear, in the event Southern Nuclear assumes control over construction management of Vogtle Units No. 3 and No. 4. In addition, Georgia Power, on behalf of itself and the other Co-owners, intends to take all actions available to it to enforce its rights related to the EPC Agreement, including enforcing the Toshiba Guarantee, subject to the Interim Assessment Agreement, and accessing the Westinghouse Letters of Credit.
The Contractor's bankruptcy filing is expected to have a material impact on the construction cost and schedule of Vogtle Units No. 3 and No. 4 and could have a material impact on our financial condition and results of operations. In addition, an inability or other failure by Toshiba to perform its obligations
under the Toshiba Guarantee could have a material impact on the cost to the Co-owners of the additional Vogtle units and, therefore, on our financial condition and results of operations.
The ultimate outcome of these matters cannot be determined at this time. See "Item 1A—Risk Factors" in our 2016 Form 10-K for additional risks related to Vogtle Units No. 3 and No. 4. For additional information regarding the Vogtle project, see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Financial Condition—Capital Requirements and Liquidity and Sources of Capital—Vogtle Units No. 3 and No. 4."
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Not Applicable.
Item 3. Defaults upon Senior Securities
Not Applicable.
Item 4. Mine Safety Disclosures
Not Applicable.
Not Applicable.On May 10, 2017, we withdrew a Form 8-A related to our First Mortgage Bonds, Series 2009 B previously filed with the Commission on March 17, 2010. Currently, we do not have any securities registered pursuant to Section 12(b) or Section 12(g) of the Securities and Exchange Act of 1934, as amended, and we are not currently required to file reports under Section 13 or Section 15(d) of the Exchange Act. However, at this time we intend to continue to file reports under the Exchange Act.
Number | Description | ||
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Interim Assessment Agreement dated as of March 29, 2017, by and among Georgia Power Company, for itself and as agent for Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, and the City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, and Westinghouse Electric Company LLC, WECTEC Staffing Services LLC and WECTEC Global Project Services, Inc. (Incorporated by reference to Exhibit 10(c)(3) of Georgia Power Company's Form 10-Q for the quarterly period ended March 31, 2017, filed with the SEC on May 3, 2017). | |||
10.2 | Amendment No. 1 to Interim Assessment Agreement dated as of March 29, 2017, by and among Georgia Power Company, for itself and as agent for Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, and the City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, and Westinghouse Electric Company LLC, WECTEC Staffing Services LLC and WECTEC Global Project Services, Inc. (Incorporated by reference to Exhibit 10(c)(4) of Georgia Power Company's Form 10-Q for the quarterly period ended March 31, 2017, filed with the SEC on May 3, 2017). | ||
31.1 | Rule 13a-14(a)/15d-14(a) Certification, by Michael L. Smith (Principal Executive Officer). | ||
31.2 | Rule 13a-14(a)/15d-14(a) Certification, by Elizabeth B. Higgins (Principal Financial Officer). | ||
32.1 | Certification Pursuant to 18 U.S.C. 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Michael L. Smith (Principal Executive Officer). |
Number | Description | ||
---|---|---|---|
32.2 | Certification Pursuant to 18 U.S.C. 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Elizabeth B. Higgins (Principal Financial Officer). | ||
99.1 | Member Financial and Statistical Information (for calendar years 2014-2016). | ||
101 | XBRL Interactive Data File. |
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Oglethorpe Power Corporation (An Electric Membership Corporation) | ||||
Date: | By: | /s/ Michael L. Smith | ||
Michael L. Smith President and Chief Executive Officer | ||||
Date: | /s/ Elizabeth B. Higgins | |||
Elizabeth B. Higgins Executive Vice President and Chief Financial Officer (Principal Financial Officer) |