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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 ý Noo o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer," and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated Filer o Accelerated Filer o Non-Accelerated Filer ý (Do not check if a smaller reporting company) Smaller Reporting Company o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý
Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.The registrant is a membership corporation and has no authorized or outstanding equity securities.
(This page has been left blank intentionally)
OGLETHORPE POWER CORPORATION
INDEX TO QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED MARCH 31,JUNE 30, 2016
| | 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 and Six Months ended | 3 | |||
Unaudited Consolidated Statements of Comprehensive Margin For the Three and Six Months ended | 4 | |||
Unaudited Consolidated Statements of Patronage Capital and Membership Fees and Accumulated Other Comprehensive 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 | |||
Item 3. | Defaults Upon Senior Securities | |||
Item 4. | Mine Safety Disclosures | |||
Item 5. | Other Information | |||
Item 6. | Exhibits | |||
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, 2015.2015 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
iii
Oglethorpe Power Corporation |
(dollars in thousands) | |||||||
2016 | 2015 | ||||||
Assets | |||||||
Electric plant: | |||||||
In service | $ | 8,630,779 | $ | 8,596,148 | |||
Less: Accumulated provision for depreciation | (3,968,968 | ) | (3,925,838 | ) | |||
| | | | | | | |
4,661,811 | 4,670,310 | ||||||
Nuclear fuel, at amortized cost | 387,207 | 373,145 | |||||
Construction work in progress | 2,958,677 | 2,868,669 | |||||
| | | | | | | |
8,007,695 | 7,912,124 | ||||||
| | | | | | | |
Investments and funds: | |||||||
Nuclear decommissioning trust fund | 369,441 | 363,829 | |||||
Investment in associated companies | 73,197 | 72,010 | |||||
Long-term investments | 90,470 | 86,771 | |||||
Restricted cash and investments | 144,109 | 134,690 | |||||
Other | 19,394 | 19,097 | |||||
| | | | | | | |
696,611 | 676,397 | ||||||
| | | | | | | |
Current assets: | |||||||
Cash and cash equivalents | 111,093 | 213,038 | |||||
Restricted short-term investments | 250,541 | 253,204 | |||||
Receivables | 126,420 | 130,464 | |||||
Inventories, at average cost | 293,999 | 299,252 | |||||
Prepayments and other current assets | 16,640 | 16,913 | |||||
| | | | | | | |
798,693 | 912,871 | ||||||
| | | | | | | |
Deferred charges: | |||||||
Regulatory assets | 554,494 | 530,254 | |||||
Other | 22,910 | 28,137 | |||||
| | | | | | | |
577,404 | 558,391 | ||||||
| | | | | | | |
$ | 10,080,403 | $ | 10,059,783 | ||||
| | | | | | | |
| | | | | | | |
| | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements.
|
(dollars in thousands) | |||||||
2016 | 2015 | ||||||
Equity and Liabilities | |||||||
Capitalization: | |||||||
Patronage capital and membership fees | $ | 830,063 | $ | 809,465 | |||
Accumulated other comprehensive margin | 342 | 58 | |||||
| | | | | | | |
830,405 | 809,523 | ||||||
Long-term debt | 7,403,407 | 7,291,154 | |||||
Obligation under capital leases | 96,501 | 96,501 | |||||
Other | 17,857 | 17,561 | |||||
| | | | | | | |
8,348,170 | 8,214,739 | ||||||
| | | | | | | |
Current liabilities: | |||||||
Long-term debt and capital leases due within one year | 189,938 | 189,840 | |||||
Short-term borrowings | 303,020 | 261,478 | |||||
Accounts payable | 44,241 | 157,432 | |||||
Accrued interest | 53,302 | 58,830 | |||||
Member power bill prepayments, current | 173,004 | 174,743 | |||||
Other current liabilities | 56,566 | 86,746 | |||||
| | | | | | | |
820,071 | 929,069 | ||||||
| | | | | | | |
Deferred credits and other liabilities: | |||||||
Asset retirement obligations | 599,631 | 602,230 | |||||
Member power bill prepayments, non-current | 39,165 | 44,205 | |||||
Contract retainage | 62,552 | 66,515 | |||||
Regulatory liabilities | 177,351 | 166,967 | |||||
Other | 33,463 | 36,058 | |||||
| | | | | | | |
912,162 | 915,975 | ||||||
| | | | | | | |
$ | 10,080,403 | $ | 10,059,783 | ||||
| | | | | | | |
| | | | | | | |
| | | | | | | |
(dollars in thousands) | |||||||
2016 | 2015 | ||||||
Assets | |||||||
Electric plant: | |||||||
In service | $ | 8,741,230 | $ | 8,596,148 | |||
Less: Accumulated provision for depreciation | (4,011,683 | ) | (3,925,838 | ) | |||
| | | | | | | |
4,729,547 | 4,670,310 | ||||||
Nuclear fuel, at amortized cost | 375,723 | 373,145 | |||||
Construction work in progress | 3,008,270 | 2,868,669 | |||||
| | | | | | | |
8,113,540 | 7,912,124 | ||||||
| | | | | | | |
Investments and funds: | |||||||
Nuclear decommissioning trust fund | 375,440 | 363,829 | |||||
Investment in associated companies | 73,545 | 72,010 | |||||
Long-term investments | 95,139 | 86,771 | |||||
Restricted cash and investments | 103,116 | 134,690 | |||||
Other | 19,696 | 19,097 | |||||
| | | | | | | |
666,936 | 676,397 | ||||||
| | | | | | | |
Current assets: | |||||||
Cash and cash equivalents | 347,369 | 213,038 | |||||
Restricted short-term investments | 251,864 | 253,204 | |||||
Receivables | 170,464 | 130,464 | |||||
Inventories, at average cost | 279,390 | 299,252 | |||||
Prepayments and other current assets | 17,611 | 16,913 | |||||
| | | | | | | |
1,066,698 | 912,871 | ||||||
| | | | | | | |
Deferred charges: | |||||||
Regulatory assets | 538,290 | 530,254 | |||||
Other | 27,868 | 28,137 | |||||
| | | | | | | |
566,158 | 558,391 | ||||||
| | | | | | | |
$ | 10,413,332 | $ | 10,059,783 | ||||
| | | | | | | |
| | | | | | | |
| | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements.
Oglethorpe Power Corporation |
(dollars in thousands) | |||||||
Three Months | |||||||
2016 | 2015 | ||||||
Operating revenues: | |||||||
Sales to Members | $ | 348,097 | $ | 308,776 | |||
Sales to non-Members | 64 | 31,002 | |||||
��� | | | | | | | |
Total operating revenues | 348,161 | 339,778 | |||||
| | | | | | | |
Operating expenses: | |||||||
Fuel | 98,952 | 108,409 | |||||
Production | 103,471 | 114,759 | |||||
Depreciation and amortization | 53,486 | 42,652 | |||||
Purchased power | 13,143 | 13,631 | |||||
Accretion | 8,016 | 6,382 | |||||
Deferral of Hawk Road and Smith Energy Facilities effect on net margin | — | (14,315 | ) | ||||
| | | | | | | |
Total operating expenses | 277,068 | 271,518 | |||||
| | | | | | | |
Operating margin | 71,093 | 68,260 | |||||
| | | | | | | |
Other income: | |||||||
Investment income | 12,323 | 9,849 | |||||
Other | 2,301 | 2,859 | |||||
| | | | | | | |
Total other income | 14,624 | 12,708 | |||||
| | | | | | | |
Interest charges: | |||||||
Interest expense | 88,517 | 87,707 | |||||
Allowance for debt funds used during construction | (26,380 | ) | (26,253 | ) | |||
Amortization of debt discount and expense | 2,982 | 4,145 | |||||
| | | | | | | |
Net interest charges | 65,119 | 65,599 | |||||
| | | | | | | |
Net margin | $ | 20,598 | $ | 15,369 | |||
| | | | | | | |
| | | | | | | |
| | | | | | | |
(dollars in thousands) | |||||||
2016 | 2015 | ||||||
Equity and Liabilities | |||||||
Capitalization: | |||||||
Patronage capital and membership fees | $ | 853,340 | $ | 809,465 | |||
Accumulated other comprehensive margin | 435 | 58 | |||||
| | | | | | | |
853,775 | 809,523 | ||||||
Long-term debt | 7,865,127 | 7,291,154 | |||||
Obligation under capital leases | 94,358 | 96,501 | |||||
Other | 18,154 | 17,561 | |||||
| | | | | | | |
8,831,414 | 8,214,739 | ||||||
| | | | | | | |
Current liabilities: | |||||||
Long-term debt and capital leases due within one year | 191,623 | 189,840 | |||||
Short-term borrowings | 75,995 | 261,478 | |||||
Accounts payable | 71,846 | 157,432 | |||||
Accrued interest | 60,836 | 58,830 | |||||
Member power bill prepayments, current | 148,245 | 174,743 | |||||
Other current liabilities | 45,314 | 86,746 | |||||
| | | | | | | |
593,859 | 929,069 | ||||||
| | | | | | | |
Deferred credits and other liabilities: | |||||||
Asset retirement obligations | 688,330 | 602,230 | |||||
Member power bill prepayments, non-current | 45,827 | 44,205 | |||||
Contract retainage | 39,165 | 66,515 | |||||
Regulatory liabilities | 184,823 | 166,967 | |||||
Other | 29,914 | 36,058 | |||||
| | | | | | | |
988,059 | 915,975 | ||||||
| | | | | | | |
$ | 10,413,332 | $ | 10,059,783 | ||||
| | | | | | | |
| | | | | | | |
| | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements.
Oglethorpe Power Corporation |
(dollars in thousands) | (dollars in thousands) | |||||||||||||||||||
Three Months | Three Months | Six Months | ||||||||||||||||||
2016 | 2015 | 2016 | 2015 | 2016 | 2015 | |||||||||||||||
Operating revenues: | ||||||||||||||||||||
Sales to Members | $ | 379,154 | $ | 311,148 | $ | 727,251 | $ | 619,924 | ||||||||||||
Sales to non-Members | 189 | 32,593 | 253 | 63,595 | ||||||||||||||||
| | | | | | | | | | | | | | |||||||
Total operating revenues | 379,343 | 343,741 | 727,504 | 683,519 | ||||||||||||||||
| | | | | | | | | | | | | | |||||||
Operating expenses: | ||||||||||||||||||||
Fuel | 126,588 | 115,211 | 225,540 | 223,620 | ||||||||||||||||
Production | 103,180 | 128,369 | 206,651 | 243,128 | ||||||||||||||||
Depreciation and amortization | 54,401 | 42,952 | 107,887 | 85,604 | ||||||||||||||||
Purchased power | 13,002 | 14,612 | 26,145 | 28,243 | ||||||||||||||||
Accretion | 8,024 | 6,477 | 16,040 | 12,859 | ||||||||||||||||
Deferral of Hawk Road and Smith Energy Facilities effect on net margin | — | (27,374 | ) | — | (41,689 | ) | ||||||||||||||
| | | | | | | | | | | | | | |||||||
Total operating expenses | 305,195 | 280,247 | 582,263 | 551,765 | ||||||||||||||||
| | | | | | | | | | | | | | |||||||
Operating margin | 74,148 | 63,494 | 145,241 | 131,754 | ||||||||||||||||
| | | | | | | | | | | | | | |||||||
Other income: | ||||||||||||||||||||
Investment income | 12,727 | 10,185 | 25,050 | 20,034 | ||||||||||||||||
Other | 2,427 | 2,441 | 4,728 | 5,300 | ||||||||||||||||
| | | | | | | | | | | | | | |||||||
Total other income | 15,154 | 12,626 | 29,778 | 25,334 | ||||||||||||||||
| | | | | | | | | | | | | | |||||||
Interest charges: | ||||||||||||||||||||
Interest expense | 91,005 | 88,132 | 179,522 | 175,839 | ||||||||||||||||
Allowance for debt funds used during construction | (27,945 | ) | (26,699 | ) | (54,325 | ) | (52,952 | ) | ||||||||||||
Amortization of debt discount and expense | 2,965 | 3,835 | 5,947 | 7,980 | ||||||||||||||||
| | | | | | | | | | | | | | |||||||
Net interest charges | 66,025 | 65,268 | 131,144 | 130,867 | ||||||||||||||||
| | | | | | | | | | | | | | |||||||
Net margin | $ | 20,598 | $ | 15,369 | $ | 23,277 | $ | 10,852 | $ | 43,875 | $ | 26,221 | ||||||||
| | | | | | | ||||||||||||||
Other comprehensive margin: | ||||||||||||||||||||
Unrealized gain (loss) on available-for-sale securities | 284 | (47 | ) | |||||||||||||||||
| | | | | | | ||||||||||||||
Total comprehensive margin | $ | 20,882 | $ | 15,322 | ||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
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 | Three Months | Six Months | |||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Balance at December 31, 2014 | $ | 761,124 | $ | 468 | $ | 761,592 | |||||||||||||||||
2016 | 2015 | 2016 | 2015 | ||||||||||||||||||||
Net margin | $ | 23,277 | $ | 10,852 | $ | 43,875 | $ | 26,221 | |||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | |
Components of comprehensive margin: | |||||||||||||||||||||||
Net margin | 15,369 | — | 15,369 | ||||||||||||||||||||
Unrealized loss on available-for-sale securities | — | (47 | ) | (47 | ) | ||||||||||||||||||
Other comprehensive margin: | |||||||||||||||||||||||
Unrealized gain (loss) on available-for-sale securities | 93 | (314 | ) | 377 | (361 | ) | |||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | |
Balance at March 31, 2015 | $ | 776,493 | $ | 421 | $ | 776,914 | |||||||||||||||||
Total comprehensive margin | $ | 23,370 | $ | 10,538 | $ | 44,252 | $ | 25,860 | |||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | |
Balance at December 31, 2015 | $ | 809,465 | $ | 58 | $ | 809,523 | |||||||||||||||||
| | | | | | | | | | | | | | | | | | | | ||||
Components of comprehensive margin: | |||||||||||||||||||||||
Net margin | 20,598 | — | 20,598 | ||||||||||||||||||||
Unrealized gain on available-for-sale securities | — | 284 | 284 | ||||||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | |
Balance at March 31, 2016 | $ | 830,063 | $ | 342 | $ | 830,405 | |||||||||||||||||
| | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements.
Oglethorpe Power Corporation |
(dollars in thousands) | ||||||||||
Patronage Capital and Membership Fees | Accumulated Other Comprehensive Margin | Total | ||||||||
---|---|---|---|---|---|---|---|---|---|---|
Balance at December 31, 2014 | $ | 761,124 | $ | 468 | $ | 761,592 | ||||
| | | | | | | | | | |
Components of comprehensive margin: | ||||||||||
Net margin | 26,221 | — | 26,221 | |||||||
Unrealized loss on available-for-sale securities | — | (361 | ) | (361 | ) | |||||
| | | | | | | | | | |
Balance at June 30, 2015 | $ | 787,345 | $ | 107 | $ | 787,452 | ||||
| | | | | | | | | | |
Balance at December 31, 2015 | $ | 809,465 | $ | 58 | $ | 809,523 | ||||
| | | | | | | | | | |
Components of comprehensive margin: | ||||||||||
Net margin | 43,875 | — | 43,875 | |||||||
Unrealized gain on available-for-sale securities | — | 377 | 377 | |||||||
| | | | | | | | | | |
Balance at June 30, 2016 | $ | 853,340 | $ | 435 | $ | 853,775 | ||||
| | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements.
Oglethorpe Power Corporation |
(dollars in thousands) | (dollars in thousands) | |||||||||||||
2016 | 2015 | 2016 | 2015 | |||||||||||
Cash flows from operating activities: | ||||||||||||||
Net margin | $ | 20,598 | $ | 15,369 | $ | 43,875 | $ | 26,221 | ||||||
| | | | | | | | | | | | | | |
Adjustments to reconcile net margin to net cash provided by operating activities: | ||||||||||||||
Depreciation and amortization, including nuclear fuel | 87,413 | 76,642 | 177,367 | 156,416 | ||||||||||
Accretion cost | 8,016 | 6,382 | 16,040 | 12,859 | ||||||||||
Amortization of deferred gains | (447 | ) | (447 | ) | (894 | ) | (894 | ) | ||||||
Allowance for equity funds used during construction | (177 | ) | (173 | ) | (352 | ) | (342 | ) | ||||||
Deferred outage costs | (24,869 | ) | (17,169 | ) | (26,090 | ) | (18,274 | ) | ||||||
Deferral of Hawk Road and Smith Energy Facilities effect on net margin | — | (14,315 | ) | — | (41,689 | ) | ||||||||
Gain on sale of investments | 849 | (4,687 | ) | |||||||||||
Loss (gain) on sale of investments | 633 | (32,470 | ) | |||||||||||
Regulatory deferral of costs associated with nuclear decommissioning | (5,814 | ) | 1,222 | (10,677 | ) | 25,781 | ||||||||
Other | (1,685 | ) | (1,617 | ) | (3,429 | ) | (3,312 | ) | ||||||
Change in operating assets and liabilities: | ||||||||||||||
Receivables | 4,044 | 10,471 | (37,697 | ) | (11,171 | ) | ||||||||
Inventories | 5,253 | 18,031 | 4,386 | 2,857 | ||||||||||
Prepayments and other current assets | 273 | (30,174 | ) | (698 | ) | (10,664 | ) | |||||||
Accounts payable | (39,787 | ) | (39,364 | ) | (73,698 | ) | (45,059 | ) | ||||||
Accrued interest | (5,528 | ) | (5,703 | ) | 2,006 | (49 | ) | |||||||
Accrued taxes | (13,160 | ) | (8,914 | ) | (3,597 | ) | 820 | |||||||
Other current liabilities | (9,777 | ) | (10,545 | ) | (23,977 | ) | (8,681 | ) | ||||||
Member power bill prepayments | (6,779 | ) | 23,732 | (24,876 | ) | (11,033 | ) | |||||||
| | | | | | | | | | | | | | |
Total adjustments | (2,175 | ) | 3,372 | (5,553 | ) | 15,095 | ||||||||
| | | | | | | | | | | | | | |
Net cash provided by operating activities | 18,423 | 18,741 | 38,322 | 41,316 | ||||||||||
| | | | | | | | | | | | | | |
Cash flows from investing activities: | ||||||||||||||
Property additions | (259,447 | ) | (157,332 | ) | (301,545 | ) | (239,510 | ) | ||||||
Activity in nuclear decommissioning trust fund—Purchases | (129,886 | ) | (111,750 | ) | (216,217 | ) | (281,938 | ) | ||||||
—Proceeds | 128,179 | 110,666 | 212,949 | 279,751 | ||||||||||
Increase in restricted cash and investments | (9,419 | ) | (586 | ) | ||||||||||
Decrease in restricted cash and investments | 31,574 | 41,855 | ||||||||||||
Decrease (increase) in restricted short-term investments | 2,663 | (4,668 | ) | 1,340 | (5,524 | ) | ||||||||
Activity in other long-term investments—Purchases | (14,267 | ) | (12,045 | ) | (31,114 | ) | (23,746 | ) | ||||||
—Proceeds | 11,639 | 11,214 | 24,820 | 24,973 | ||||||||||
Other | 3,147 | (5,278 | ) | 2,494 | (8,450 | ) | ||||||||
| | | | | | | | | | | | | | |
Net cash used in investing activities | (267,391 | ) | (169,779 | ) | (275,699 | ) | (212,589 | ) | ||||||
| | | | | | | | | | | | | | |
Cash flows from financing activities: | ||||||||||||||
Long-term debt proceeds | 7,998 | 113,718 | 628,358 | 271,892 | ||||||||||
Long-term debt payments | (36,677 | ) | (37,319 | ) | (75,537 | ) | (76,418 | ) | ||||||
Increase in short-term borrowings, net | 171,280 | 109,360 | ||||||||||||
(Decrease) increase in short-term borrowings, net | (185,483 | ) | 27,375 | |||||||||||
Other | 4,422 | (408 | ) | 4,370 | (2,190 | ) | ||||||||
| | | | | | | | | | | | | | |
Net cash provided by financing activities | 147,023 | 185,351 | 371,708 | 220,659 | ||||||||||
| | | | | | | | | | | | | | |
Net (decrease) increase in cash and cash equivalents | (101,945 | ) | 34,313 | |||||||||||
Net increase in cash and cash equivalents | 134,331 | 49,386 | ||||||||||||
Cash and cash equivalents at beginning of period | 213,038 | 237,391 | 213,038 | 237,391 | ||||||||||
| | | | | | | | | | | | | | |
Cash and cash equivalents at end of period | $ | 111,093 | $ | 271,704 | $ | 347,369 | $ | 286,777 | ||||||
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
Supplemental cash flow information: | ||||||||||||||
Cash paid for— | ||||||||||||||
Interest (net of amounts capitalized) | $ | 66,950 | $ | 69,258 | $ | 121,760 | $ | 127,026 | ||||||
Supplemental disclosure of non-cash investing and financing activities: | ||||||||||||||
Change in asset retirement obligations | $ | (10,425 | ) | $ | — | $ | 70,780 | $ | 20,711 | |||||
Change in accrued property additions | $ | (79,336 | ) | $ | (22,510 | ) | $ | (38,209 | ) | $ | (8,454 | ) | ||
Interest paid-in-kind | $ | 10,606 | $ | 8,065 | $ | 21,765 | $ | 16,528 |
The accompanying notes are an integral part of these consolidated financial statements.
Oglethorpe Power Corporation
Notes to Unaudited Consolidated Financial Statements
For the three monthsix-month period ended March 31,June 30, 2015, we made an adjustment of $8,065,000$16,528,000 in the Consolidated Statement of Cash Flows to decrease other adjustments to reconcile net margin to net cash provided by operating activities and decrease cash paid for property additions. This adjustment reflects the non-cash nature of the allowance for debt funds used during construction related to interest paid-in-kind associated with loans under our Department of Energy Loan Guarantee. The change properly reflects an immaterial adjustment to cash flows provided by operations and cash used in investing activities, and is consistent with the 2016 presentation.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, as filed with the SEC. The results of operations for the three-month periodand six-month periods ended March 31,June 30, 2016 are not necessarily indicative of results to be expected for the full year. As noted in our 2015 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"Notes to Consolidated Financial Statements"Statements" in our 2015 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 March 31,June 30, 2016 and December 31, 2015.
| | | | | | | | | | | | | | | | | | | | | | | | | ||
Fair Value Measurements at Reporting Date Using | Fair Value Measurements at Reporting Date Using | |||||||||||||||||||||||||
March 31, | Quoted Prices in | Significant Other | Significant | June 30, | Quoted Prices in | Significant Other | Significant | |||||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | ||
(dollars in thousands) | (dollars in thousands) | |||||||||||||||||||||||||
Nuclear decommissioning trust funds: | ||||||||||||||||||||||||||
Domestic equity | $ | 152,412 | $ | 152,412 | $ | — | $ | — | $ | 156,154 | $ | 156,154 | $ | — | $ | — | ||||||||||
International equity trust | 69,040 | — | 69,040 | — | 68,115 | — | 68,115 | — | ||||||||||||||||||
Corporate bonds | 46,223 | — | 46,223 | — | 51,058 | — | 51,058 | — | ||||||||||||||||||
US Treasury and government agency securities | 80,644 | 80,644 | — | — | 75,784 | 75,784 | — | — | ||||||||||||||||||
Agency mortgage and asset backed securities | 16,463 | — | 16,463 | — | 16,810 | — | 16,810 | — | ||||||||||||||||||
Municipal bonds | 380 | — | 380 | — | 400 | — | 400 | — | ||||||||||||||||||
Other | 4,279 | 4,279 | — | — | 7,119 | 7,119 | — | — | ||||||||||||||||||
Long-term investments: | ||||||||||||||||||||||||||
International equity trust | 12,904 | — | 12,904 | — | 13,892 | — | 13,892 | — | ||||||||||||||||||
Corporate bonds | 9,516 | — | 9,516 | — | 11,625 | — | 11,625 | — | ||||||||||||||||||
US Treasury and government agency securities | 14,692 | 14,692 | — | — | 13,367 | 13,367 | — | — | ||||||||||||||||||
Agency mortgage and asset backed securities | 1,482 | — | 1,482 | — | 1,181 | — | 1,181 | — | ||||||||||||||||||
Mutual funds | 51,721 | 51,721 | — | — | 54,798 | 54,798 | — | — | ||||||||||||||||||
Other | 155 | 155 | — | — | 276 | 276 | — | — | ||||||||||||||||||
Interest rate options | 95 | — | — | 95 | 5 | — | — | 5 | ||||||||||||||||||
Natural gas swaps | 25,919 | — | 25,919 | — | (2,645 | ) | — | (2,645 | ) | — | ||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | |
Fair Value Measurements at Reporting Date Using | |||||||||||||
December 31, | Quoted Prices in | Significant Other | Significant | ||||||||||
| | | | | | | | | | | | | |
(dollars in thousands) | |||||||||||||
Nuclear decommissioning trust funds: | |||||||||||||
Domestic equity | $ | 151,178 | $ | 151,178 | $ | — | $ | — | |||||
International equity trust | 68,753 | — | 68,753 | — | |||||||||
Corporate bonds | 48,450 | — | 48,450 | — | |||||||||
US Treasury and government agency securities | 75,173 | 74,698 | 475 | — | |||||||||
Agency mortgage and asset backed securities | 15,503 | — | 15,503 | — | |||||||||
Other | 4,772 | 4,772 | — | — | |||||||||
Long-term investments: | |||||||||||||
Corporate bonds | 9,903 | — | 9,903 | — | |||||||||
US Treasury and government agency securities | 13,772 | 13,772 | — | — | |||||||||
Agency mortgage and asset backed securities | 1,121 | — | 1,121 | — | |||||||||
International equity trust | 12,846 | — | 12,846 | — | |||||||||
Mutual funds | 48,649 | 48,649 | — | — | |||||||||
Other | 479 | 479 | — | — | |||||||||
Interest rate options | 1,010 | — | — | 1,010 | |||||||||
Natural gas swaps | 24,995 | — | 24,995 | — | |||||||||
| | | | | | | | | | | | | |
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 six months ended March 31,June 30, 2016 and 2015.
| | | | | | | | |
Three Months Ended March 31, 2016 | Three Months Ended June 30, 2016 | |||||||
| | | | | | | | |
Interest rate options | Interest rate options | |||||||
| | | | | | | | |
(dollars in thousands) | (dollars in thousands) | |||||||
Assets (Liabilities): | ||||||||
Balance at December 31, 2015 | $ | 1,010 | ||||||
Balance at March 31, 2016 | $ | 95 | ||||||
Total gains or losses (realized/unrealized): | ||||||||
Included in earnings (or changes in net assets) | (915 | ) | (90 | ) | ||||
| | | | | | | | |
Balance at March 31, 2016 | $ | 95 | ||||||
Balance at June 30, 2016 | $ | 5 | ||||||
| | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Three Months Ended March 31, 2015 | Three Months Ended June 30, 2015 | |||||||
| | | | | | | | |
Interest rate options | Interest rate options | |||||||
| | | | | | | | |
(dollars in thousands) | (dollars in thousands) | |||||||
Assets (Liabilities): | ||||||||
Balance at December 31, 2014 | $ | 4,371 | ||||||
Balance at March 31, 2015 | $ | 2,702 | ||||||
Total gains or losses (realized/unrealized): | ||||||||
Included in earnings (or changes in net assets) | (1,669 | ) | 2,013 | |||||
| | | | | | | | |
Balance at March 31, 2015 | $ | 2,702 | ||||||
Balance at June 30, 2015 | $ | 4,715 | ||||||
| | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | |
Six Months Ended June 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) | (1,005 | ) | ||
| | | | |
Balance at June 30, 2016 | $ | 5 | ||
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
Six Months Ended June 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) | 344 | |||
| | | | |
Balance at June 30, 2015 | $ | 4,715 | ||
| | | | |
| | | | |
| | | | |
| | | | |
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 March 31,June 30, 2016 and December 31, 2015 were as follows (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | ||
2016 | 2015 | 2016 | 2015 | |||||||||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Carrying Value | Fair Value | Carrying Value | Fair Value | Carrying Value | Fair Value | Carrying Value | Fair Value | |||||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Long-term debt | $ | 7,686,691 | $ | 8,991,014 | $ | 7,575,027 | $ | 8,445,630 | $ | 8,155,612 | $ | 9,900,207 | $ | 7,575,027 | $ | 8,445,630 | ||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
The estimated fair value of long-term debt is classified as Level 2 and is estimated based on observed or quoted market prices for the same or similar issues or on current rates offered to us for debt of similar maturities. The primary sources of our long-term debt consist of first mortgage bonds, pollution control revenue bonds and long-term debt issued by the Federal Financing Bank that is guaranteed by the Rural Utilities Service or the U.S. Department of Energy. We also have small amounts of long-term debt provided by National Rural Utilities Cooperative Finance Corporation (CFC) and by CoBank, ACB. The valuations for the first mortgage bonds and the pollution control revenue bonds were obtained from third party investment banking firms and a third party data reporting service, and are based on secondary market trading of our debt. Valuations for debt issued by the Federal Financing Bank are based on U.S. Treasury rates as of March 31,June 30, 2016 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.
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 March 31,June 30, 2016, 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 March 31,June 30, 2016 and December 31, 2015, the estimated fair value of our natural gas contracts was a net liabilityasset of approximately $25,919,000$2,645,000 and a net liability of $22,848,000, respectively.
As of March 31,June 30, 2016 and December 31, 2015, 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 March 31,June 30, 2016 due to our credit rating being downgraded below investment grade, we would have been required to post collateral or letters of credit of $25,919,000$2,887,000 with our counterparties.
The following table reflects the volume activity of our natural gas derivatives as of March 31,June 30, 2016 that is expected to settle or mature each year:
| | | | | | | | |
Year | Natural Gas Swaps | Natural Gas Swaps | ||||||
| | | | | | | | |
2016 | 21.6 | 15.1 | ||||||
2017 | 18.1 | 19.3 | ||||||
2018 | 15.4 | 16.5 | ||||||
2019 | 10.0 | 11.4 | ||||||
2020 | 2.5 | 5.5 | ||||||
| | | | | | | | |
Total | 67.6 | 67.8 | ||||||
| | | | | | | | |
Interest rate options. We are exposed to the risk of rising interest rates due to the significant amount of new long-term debt we expect to incur in connection with anticipated capital expenditures, particularly the construction of Vogtle Units No. 3 and No. 4. In fourth quarter of 2011, we purchased LIBOR swaptions at a cost of $100,000,000 with a total notional amount of
approximately $2,200,000,000 to hedge the interest rates on a portion of the debt that we are incurring to finance the two additional nuclear units at Plant Vogtle. Since inception, swaptions having a notional amount of approximately $1,864,393,000$1,941,169,000 have expired and, as of March 31,June 30, 2016, the remaining notional amount of our outstanding swaptions was approximately $314,810,000.$238,034,000.
The LIBOR swaptions are each designed to cap our effective interest rate at a specified fixed interest rate on a specified option expiration date. This is accomplished by means of a payment of the cash settlement value our counterparties are obligated to make to us if prevailing fixed LIBOR swap rates exceed the specified fixed rate on the option expiration date. This payment would partially offset our interest costs, thereby reducing our effective interest rate. The cash settlement value would be zero if swap rates are at or below the specified fixed rate on the expiration date. The cash settlement value is calculated based on the value of an underlying swap which we have the right, but not the obligation, to enter into, which would begin on the option expiration date and extend until 2042 and under which we would pay the specified fixed rate and receive a floating LIBOR rate. The fixed rates on the unexpired swaptions we hold average 198224 basis points above the corresponding LIBOR swap rates that were in effect as of March 31,June 30, 2016, and the weighted average fixed rate is 3.93%3.88%. Swaptions having notional amounts totaling $75,892,000$152,668,000 expired without value during the threesix months ended March 31,June 30, 2016. The remaining swaptions expire quarterly through March 31, 2017.
We paid all the premiums to purchase these LIBOR swaptions at the time we entered into these transactions. At March 31,June 30, 2016 and December 31, 2015, the fair value of these swaptions was approximately $95,000$5,000 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 March 31,June 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 deferred costs and deferred gains, if any, from the settlement of the interest rate options will be amortized and collected in rates over the life of the $2,200,000,000 of debt that we hedged with the swaptions.
The following table reflects the remaining notional amount of forecasted debt issuances we have hedged in each year with LIBOR swaptions as of March 31,June 30, 2016.
| | | | | | | | |
Year | LIBOR Swaption | LIBOR Swaption | ||||||
| | | | | | | | |
2016 | $ | 234,641 | $ | 157,865 | ||||
2017 | 80,169 | 80,169 | ||||||
| | | | | | | | |
Total | $ | 314,810 | $ | 238,034 | ||||
| | | | | | | | |
The table below reflects the fair value of derivative instruments and their effect on our consolidated balance sheets at March 31,June 30, 2016 and December 31, 2015.
| | | | | | | | | | | | | | | | | | |
Balance Sheet | Fair Value | Balance Sheet | Fair Value | |||||||||||||||
| | | | | | | | | | | | | | | | | | |
2016 | 2015 | 2016 | 2015 | |||||||||||||||
| (dollars in thousands) |
| (dollars in thousands) | |||||||||||||||
Not designated as hedge: | ||||||||||||||||||
Assets: |
| |||||||||||||||||
Interest rate options | Other deferred charges | $ | 95 | $ | 1,010 | Other deferred charges | $ | 5 | $ | 1,010 | ||||||||
Natural gas swaps | Other deferred charges | $ | 4,982 | $ | — | |||||||||||||
Liabilities: |
|
| ||||||||||||||||
Natural gas swaps | Other current liabilities | $ | 25,919 | $ | 22,848 | Other current liabilities | $ | (2,337 | ) | $ | 22,848 | |||||||
| | | | | | | | | | | | | | | | | | |
The following table presents the gross realized gains and (losses) on derivative instruments recognized in margin for the three and six months ended March 31,June 30, 2016 and 2015.
| | | | | | | | | | | | | | | | | | | | | | | | |
Statement of | Three months ended | Statement of | Three months | Six months | ||||||||||||||||||||
Location | 2016 | 2015 | Location | 2016 | 2015 | 2016 | 2015 | |||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | |
(dollars in thousands) | (dollars in thousands) | |||||||||||||||||||||||
Not Designated as hedge: | ||||||||||||||||||||||||
Natural Gas Swaps | Fuel | $ | 11 | $ | — | Fuel | $ | 7 | $ | 956 | $ | 18 | $ | 1,236 | ||||||||||
Natural Gas Swaps | Fuel | (4,228 | ) | (5,527 | ) | Fuel | (8,111 | ) | — | (12,339 | ) | — | ||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | |
$ | (4,217 | ) | $ | (5,527 | ) | $ | (8,104 | ) | $ | 956 | $ | (12,321 | ) | $ | 1,236 | |||||||||
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
The following table presents the unrealized gains and (losses) on derivative instruments deferred on the balance sheet at March 31,June 30, 2016 and December 31, 2015.
| | | | | | | | | | | | | | | | | | |
Balance Sheet | 2016 | 2015 | Balance Sheet | 2016 | 2015 | |||||||||||||
| | | | | | | | | | | | | | | | | | |
(dollars in thousands) | (dollars in thousands) | |||||||||||||||||
Not designated as hedge: | ||||||||||||||||||
Natural gas swaps | Regulatory liability | $ | 2,645 | $ | — | |||||||||||||
Natural gas swaps | Regulatory asset | $ | (25,919 | ) | $ | (22,848 | ) | Regulatory asset | — | (22,848 | ) | |||||||
Interest rate options | Regulatory asset | (21,962 | ) | (25,915 | ) | Regulatory asset | (16,901 | ) | (25,915 | ) | ||||||||
| | | | | | | | | | | | | | | | | | |
Total not designated as hedge | $ | (47,881 | ) | $ | (48,763 | ) | ||||||||||||
Total unrealized gains (losses) | $ | (14,256 | ) | $ | (48,763 | ) | ||||||||||||
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
The following table presents the gross amounts of derivatives and their related offset amounts as permitted by their respective master netting agreements and obligations to return cash collateral.
| | | | | | | | | | | | | | | | | | | | | | | | | ||
Gross Amounts of Recognized Assets (Liabilities) | Gross Amounts offset on the Balance Sheet | Cash Collateral | Net Amounts of Assets Presented on the Balance Sheet | Gross Amounts of Recognized Assets (Liabilities) | Gross Amounts offset on the Balance Sheet | Cash Collateral | Net Amounts of Assets Presented on the Balance Sheet | |||||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
(dollars in thousands) | (dollars in thousands) | |||||||||||||||||||||||||
March 31, 2016 | ||||||||||||||||||||||||||
June 30, 2016 | ||||||||||||||||||||||||||
Assets: | ||||||||||||||||||||||||||
Natural gas swaps | $ | (25,919 | ) | $ | — | $ | — | $ | (25,919 | ) | $ | 2,645 | $ | — | $ | — | $ | 2,645 | ||||||||
Interest rate options | $ | 22,057 | $ | (21,962 | ) | $ | — | $ | 95 | $ | 16,906 | $ | (16,901 | ) | $ | — | $ | 5 | ||||||||
December 31, 2015 | ||||||||||||||||||||||||||
Assets: | ||||||||||||||||||||||||||
Natural gas swaps | $ | (22,848 | ) | $ | — | $ | — | $ | (22,848 | ) | $ | (22,848 | ) | $ | — | $ | — | $ | (22,848 | ) | ||||||
Interest rate options | $ | 26,925 | $ | (25,915 | ) | $ | — | $ | 1,010 | $ | 26,925 | $ | (25,915 | ) | $ | — | $ | 1,010 | ||||||||
| | | | | | | | | | | | | | | | | | | | | | | | |
The following tables summarize the activities for available-for-sale securities as of March 31,June 30, 2016 and December 31, 2015.
| | | | | | | | | | | | | |
Gross Unrealized | |||||||||||||
| | | | | | | | | | | | | |
(dollars in thousands) | |||||||||||||
March 31, 2016 | Cost | Gains | Losses | Fair Value | |||||||||
| | | | | | | | | | | | | |
Equity | $ | 231,117 | $ | 39,324 | $ | (9,263 | ) | $ | 261,178 | ||||
Debt | 193,012 | 3,174 | (1,887 | ) | 194,299 | ||||||||
Other | 4,435 | — | (1 | ) | 4,434 | ||||||||
| | | | | | | | | | | | | |
Total | $ | 428,564 | $ | 42,498 | $ | (11,151 | ) | $ | 459,911 | ||||
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | ||
Gross Unrealized | Gross Unrealized | |||||||||||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
(dollars in thousands) | (dollars in thousands) | |||||||||||||||||||||||||
December 31, 2015 | Cost | Gains | Losses | Fair Value | ||||||||||||||||||||||
June 30, 2016 | Cost | Gains | Losses | Fair Value | ||||||||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Equity | $ | 230,123 | $ | 37,494 | $ | (9,635 | ) | $ | 257,982 | $ | 233,116 | $ | 41,280 | $ | (8,644 | ) | $ | 265,752 | ||||||||
Debt | 189,700 | 1,158 | (3,491 | ) | 187,367 | 193,497 | 5,209 | (1,273 | ) | 197,433 | ||||||||||||||||
Other | 5,255 | — | (4 | ) | 5,251 | 7,395 | — | (1 | ) | 7,394 | ||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Total | $ | 425,078 | $ | 38,652 | $ | (13,130 | ) | $ | 450,600 | $ | 434,008 | $ | 46,489 | $ | (9,918 | ) | $ | 470,579 | ||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Gross Unrealized | |||||||||||||
| | | | | | | | | | | | | |
(dollars in thousands) | |||||||||||||
December 31, 2015 | Cost | Gains | Losses | Fair Value | |||||||||
| | | | | | | | | | | | | |
Equity | $ | 230,123 | $ | 37,494 | $ | (9,635 | ) | $ | 257,982 | ||||
Debt | 189,700 | 1,158 | (3,491 | ) | 187,367 | ||||||||
Other | 5,255 | — | (4 | ) | 5,251 | ||||||||
| | | | | | | | | | | | | |
Total | $ | 425,078 | $ | 38,652 | $ | (13,130 | ) | $ | 450,600 | ||||
| | | | | | | | | | | | | |
In August 2015, the FASB issued an update to Topic 606 deferring the effective date by one year. The standard is effective for annual reporting periods beginning after December 15, 2017 and interim periods therein. The standard also permits early adoption of the standard, but not before the original effective date of December 15, 2016. We are currently evaluating the future impact of this standard on our consolidated financial statements.
In July 2015, the FASB issued "Inventory (Topic 330): Simplifying the Measurement of Inventory."Inventory". Under the new inventory standard, inventories are required to be measured at the lower of cost and net realizable value, the latter representing the estimated selling price in the ordinary course of business, reduced by costs of completion, disposal, and transportation. Under current guidance, inventories are required to be measured at the lower of cost or market, but depending upon specific circumstances, market could be replacement cost, net realizable value, or net realizable value reduced by a normal profit margin. The amendments do not apply to inventory measured using the last-in, first-out or the retail inventory method. The amendments apply to all other inventory, which includes inventory that is measured using first-in, first out or average cost, the method used to measure all of our inventories. The new standard is effective for us prospectively for annual reporting periods beginning after December 15, 2016, and interim periods therein. Early adoption is permitted as of the beginning of an interim or annual reporting period. We are currently evaluating this standard but do not expectAs permitted, on April 1, 2016, we early adopted these amendments and applied their provisions prospectively.
The adoption of the standard tothis 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."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
Table evaluating the future impact of Contents
evaluating 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-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 retrospectively approach for annual reporting periods beginning after December 15, 2018, and interim periods therein. Early adoption is permitted. We are currently evaluating the future impact of this standard on our consolidated financial statements.
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.
Our effective tax rate is zero; therefore, all amounts below are presented net of tax.
| | | | | | | | |
Accumulated Other Comprehensive Margin Three Months Ended | Accumulated Other Comprehensive Margin Three Months Ended June 30, 2015 | |||||||
| | | | | | | | |
(dollars in thousands) | (dollars in thousands) | |||||||
Available-for-sale | Available-for-sale | |||||||
| | | | | | | | |
Balance at December 31, 2014 | $ | 468 | ||||||
Balance at March 31, 2015 | $ | 421 | ||||||
Unrealized gain | 107 | (161 | ) | |||||
(Gain) reclassified to net margin | (154 | ) | (153 | ) | ||||
| | | | | | | | |
Balance at March 31, 2015 | $ | 421 | ||||||
Balance at June 30, 2015 | $ | 107 | ||||||
| | | | | | | | |
Balance at December 31, 2015 | $ | 58 | ||||||
Unrealized gain | 294 | |||||||
(Gain) reclassified to net margin | (10 | ) | ||||||
| | | | |||||
Balance at March 30, 2016 | $ | 342 | ||||||
| | | | |||||
| | | | |
Three Months Ended June 30, 2016 | ||||
| | | | |
(dollars in thousands) | ||||
Available-for-sale | ||||
| | | | |
Balance at March 31, 2016 | $ | 342 | ||
Unrealized gain | 143 | |||
(Gain) reclassified to net margin | (50 | ) | ||
| | | | |
Balance at June 30, 2016 | $ | 435 | ||
| | | | |
| | | | |
Six Months Ended June 30, 2015 | ||||
| | | | |
(dollars in thousands) | ||||
Available-for-sale | ||||
| | | | |
Balance at December 31, 2014 | $ | 468 | ||
Unrealized loss | (54 | ) | ||
(Gain) reclassified to net margin | (307 | ) | ||
| | | | |
Balance at June 30, 2015 | $ | 107 | ||
| | | | |
Six Months Ended June 30, 2016 | ||||
| | | | |
(dollars in thousands) | ||||
Available-for-sale | ||||
| | | | |
Balance at December 31, 2015 | $ | 58 | ||
Unrealized gain | 437 | |||
(Gain) reclassified to net margin | (60 | ) | ||
| | | | |
Balance at June 30, 2016 | $ | 435 | ||
| | | | |
| | | | |
We do not anticipate that the liabilities, if any, for any current proceedings against us will have a material effect on our financial condition or results of operations. However, at this time, the ultimate outcome of any pending or potential litigation cannot be determined.
a. Nuclear Construction
In 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.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
On May 31, 2016, plaintiffs for both of the cases described under Note G of Notes to Unaudited Consolidated Financial Statements in our Form 10-Q for the quarterly period ended March 13, 2014, a lawsuit was filed in31, 2016 appealed the Superior Court of DeKalb County, Georgia, against us, Georgia Transmission and three of our member distribution cooperatives. Plaintiffs filed an amended complaint on July 28, 2014. The amended complaint challenges the patronage capital distribution practices of Georgia's electric cooperatives and seeks to certify a defendant class of all but one of our 38 members. It was filed by four former consumer-members of four of our members on behalf of themselves and a proposed class of all former consumer-members of our members. Plaintiffs claim that approximately 30% of all the defendants' total allocated patronage capital belongs to former consumer-members. Plaintiffs also allege that patronage capital owed to former consumer-members includes patronage capital allocated by us to our members but not yet distributed to our members. Plaintiffs claim that the patronage capital of former consumer-members held by defendants and the proposed defendant class should be retired immediately when the consumer-members end their membership by terminating service, or alternatively, according to a revolving schedule of no longer than 13 years from the date of its allocation and seek relief to effect such retirements. Plaintiffs further seek to require the defendants to adjust rates in order to establish and maintain reasonable reserves to fund patronage capital retirements on this basis. Plaintiffs also claim that defendants and the proposed defendant class should be required to adopt policies to periodically retire the patronage capital of all consumer-members on a revolving schedule of no longer than 13 years from the date of its allocation. Our first mortgage indenture restricts our ability to distribute patronage capital. Although not expected, if we were ordered by the Court to make distributions of our patronage capital, our first mortgage indenture would require us to raise our rates to a level sufficient so that we could comply with the current patronage capital distribution restrictions, and the rate increases required to meet the Plaintiffs' demands would be significant for a period of years.
On August 20, 2014, a second patronage capital lawsuit was filed in the Superior Court of DeKalb County against us, Georgia Transmission, and two of our member distribution cooperatives. The case was filed by two current consumer-members of the two member distribution cooperatives named in the lawsuit. Similar to the above described litigation, this complaint challenges the patronage capital distribution practices of Georgia's electric cooperatives; however, one notable difference is that the first case, described above, seeks to bring claims on behalf of former members while this second case seeks to bring claims on behalf of current members. The plaintiffs allege that the defendants have (i) retained patronage capital for an unreasonably long period of time; (ii) conspired with each other to deprive consumer-members of their patronage capital; and (iii) breached bylaw provisions allegedly requiring that patronage capital be retired when the financial condition of the cooperative will not be impaired. The plaintiffs seek unspecified damages and equitable relief, including an order declaring that the defendants be required to retire patronage capital "according to a regular, reasonable revolving plan." Similarly to the litigation described above, although not expected, if we were ordered by the Court to make distributions of our patronage capital, our first mortgage indenture would require us to raise our rates to a level where we could comply with current patronage capital distribution restrictions, and the rate increases required to meet the Plaintiff's demands could be significant for a period of years. The plaintiffs seek to certify three plaintiffs' classes but do not seek to certify a defendants' class.
In May 2015, the Superior Court judge appointed a special master to oversee all pre-trial issues relating to these cases, including motions to dismiss that we and the other defendants filed in connection with each lawsuit. In September, the special master issued proposed orders to the judgeCourt's decision to grant our and the other defendants' motions to dismiss both patronage capitalof those lawsuits on all counts. On May 2, 2016,counts to the SuperiorGeorgia Court judge adoptedof Appeals. For additional information about the special master's proposed orders and grantedPatronage Capital Litigation, see "Item 8—FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA—Notes to Consolidated Financial Statements" in our and the other defendants' motions to dismiss both of these lawsuits on all counts. The Court's decision remains subject to appeal.
Table of Contents2015 Form 10-K.
We intend to defend vigorously against all claims in the above-described litigation.
c. Environmental Matters
As is typical for electric utilities, we are subject to various federal, state and local environmental laws which represent significant future risks and uncertainties. Air emissions, water discharges and water usage are extensively controlled, closely monitored and periodically reported. Handling and disposal requirements govern the manner of transportation, storage and disposal of various types of waste. We are also subject to climate change regulations that impose restrictions on emissions of greenhouse gases, including carbon dioxide, for certain new and modified facilities.
In general, these and other types of environmental requirements are becoming increasingly stringent. Such requirements may substantially increase the cost of electric service, by requiring modifications in the design or operation of existing facilities or the purchase of emission
allowances. Failure to comply with these requirements could result in civil and criminal penalties and could include the complete shutdown of individual generating units not in compliance. Certain of our debt instruments require us to comply in all material respects with laws, rules, regulations and orders imposed by applicable governmental authorities, which include current and future environmental laws or regulations. Should we fail to be in compliance with these requirements, it would constitute a default under those debt instruments. We believe that we are in compliance with those environmental regulations currently applicable to our business and operations. Although it is our intent to comply with current and future regulations, we cannot provide assurance that we will always be in compliance.
At this time, the ultimate impact of any new and more stringent environmental regulations described above is uncertain and could have an effect on our financial condition, results of operations and cash flows as a result of future additional capital expenditures and increased operations and maintenance costs.
Additionally, litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has increased generally throughout the United States. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief, personal injury and property damage allegedly caused by coal combustion residue, greenhouse gas and other emissions have become more frequent.
The following regulatory assets and liabilities are reflected on the unaudited consolidated balance sheets as of March 31,June 30, 2016 and December 31, 2015.
| | | | | | | | | | | | | | |
2016 | 2015 | 2016 | 2015 | |||||||||||
(dollars in thousands) | (dollars in thousands) | |||||||||||||
| | | | | | | | | | | | | | |
Regulatory Assets: | ||||||||||||||
Premium and loss on reacquired debt(a) | $ | 60,147 | $ | 61,916 | $ | 58,459 | $ | 61,916 | ||||||
Amortization on capital leases(b) | 30,759 | 30,253 | 31,264 | 30,253 | ||||||||||
Outage costs(c) | 56,327 | 42,027 | 46,896 | 42,027 | ||||||||||
Interest rate swap termination fees(d) | 4,909 | 5,355 | 4,463 | 5,355 | ||||||||||
Depreciation expense(e) | 45,159 | 45,514 | 44,803 | 45,514 | ||||||||||
Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(f) | 38,899 | 37,646 | 40,303 | 37,646 | ||||||||||
Interest rate options cost(g) | 103,713 | 102,554 | 105,011 | 102,554 | ||||||||||
Deferral of effects on net margin—Smith Energy Facility(h) | 176,857 | 178,343 | 175,371 | 178,343 | ||||||||||
Other regulatory assets(m) | 37,724 | 26,646 | 31,720 | 26,646 | ||||||||||
| | | | | | | | | | | | | | |
Total Regulatory Assets | $ | 554,494 | $ | 530,254 | $ | 538,290 | $ | 530,254 | ||||||
Regulatory Liabilities: | ||||||||||||||
Accumulated retirement costs for other obligations(i) | $ | 10,728 | $ | 8,910 | $ | 12,553 | $ | 8,910 | ||||||
Deferral of effects on net margin—Hawk Road Energy Facility(h) | 20,622 | 20,775 | 20,469 | 20,775 | ||||||||||
Major maintenance reserve(j) | 24,872 | 22,422 | 26,354 | 22,422 | ||||||||||
Amortization on capital leases(b) | 25,647 | 26,502 | 24,793 | 26,502 | ||||||||||
Deferred debt service adder(k) | 78,767 | 76,334 | 81,206 | 76,334 | ||||||||||
Asset retirement obligations(l) | 12,917 | 8,316 | 13,303 | 8,316 | ||||||||||
Other regulatory liabilities(m) | 3,798 | 3,708 | 6,145 | 3,708 | ||||||||||
| | | | | | | | | | | | | | |
Total Regulatory Liabilities | $ | 177,351 | $ | 166,967 | $ | 184,823 | $ | 166,967 | ||||||
| | | | | | | | | | | | | | |
Net Regulatory Assets | $ | 377,143 | $ | 363,287 | $ | 353,467 | $ | 363,287 | ||||||
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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 Bank and the Department of Energy and two future advance promissory notes, each dated February 20, 2014, made by us to the Federal Financing Bank (the "Federal Financing Bank Notes" and together with the Note Purchase Agreement, the "FFB Credit Facility Documents"). The FFB Credit Facility Documents provide for a multi-advance term loan facility (the "Facility"), under which we may make term loan borrowings through the Federal Financing Bank.
Proceeds of advances made under the Facility will be used to reimburse us for a portion of certain costs of construction relating to Vogtle Units No. 3 and No. 4 that are eligible for financing under the Title XVII Loan Guarantee Program ("Eligible Project Costs"). Aggregate borrowings under the Facility may not exceed $3,057,069,461 of which $335,471,604 is designated for capitalized interest.
Advances may be requested under the Facility on a quarterly basis through December 31, 2020.2020 and are secured under our first mortgage indenture. On June 8, 2016, we received a $300,000,000 advance under the Facility. At March 31,June 30, 2016, aggregate borrowings totaled $1,191,234,000,$1,502,393,000, including capitalized interest.
For the three monthsix-month period ended March 31,June 30, 2016 we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling $7,998,000$82,432,000 for general and environmental improvements at existing plants.
On AprilJuly 28, 2016, we received an additional $74,435,000$4,581,000 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, we issued $250,000,000 of 4.25% first mortgage bonds, Series 2016A primarily for the purpose of providing long-term financing for expenditures related to Vogtle Units No. 3 and No. 4 and 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.
for an asset's future retirement and are recorded in the period in which the liability is incurred. The liabilities we have recognized primarily relate to the decommissioning of our nuclear facilities. In addition, we have retirement obligations related to ash ponds, gypsum, landfill sites and asbestos removal. Under the accounting provision for regulated operations, we record a regulatory asset or liability to reflect the difference in timing of recognition of the costs related to nuclear and coal ash related decommissioning for financial statement purposes and for ratemaking purposes.
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, and 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 impact 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.
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 margin for the three-month periodand six-month periods ended March 31,June 30, 2016 was $20.6were $23.3 million and $43.9 million compared to $15.4$10.8 million and $26.2 million for the same periodperiods of 2015. Through March 31,June 30, 2016, we collected approximately 40%87% of our targeted net margin of $51.0$50.6 million for the year ending December 31, 2016. This isThese collections are typical as our capacity revenues are 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" ofin our 2015 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 six-month periods ended March 31,June 30, 2016 and 2015 were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Three Months Ended March 31, | 2016 vs. 2015 % Change | Three Months Ended June 30, | 2016 vs. 2015 % Change | Six Months Ended June 30, | 2016 vs. 2015 % Change | ||||||||||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(dollars in thousands) | (dollars in thousands) | �� | (dollars in thousands) | ||||||||||||||||||||||||||
2016 | 2015 | 2016 | 2015 | 2016 | 2015 | ||||||||||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | | |||
Capacity revenues | $ | 224,924 | $ | 195,328 | 15.2% | $ | 228,449 | $ | 194,824 | 17.3% | $ | 453,373 | $ | 390,152 | 16.2% | ||||||||||||||
Energy revenues | 123,173 | 113,448 | 8.6% | 150,705 | 116,324 | 29.6% | 273,878 | 229,772 | 19.2% | ||||||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | | |||
Total | $ | 348,097 | $ | 308,776 | 12.7% | $ | 379,154 | $ | 311,148 | 21.9% | $ | 727,251 | $ | 619,924 | 17.3% | ||||||||||||||
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MWh Sales to members | 5,380,861 | 4,567,689 | 17.8% | 6,549,671 | 4,752,295 | 37.8% | 11,930,532 | 9,319,984 | 28.0% | ||||||||||||||||||||
Cents/kWh | 6.47 | 6.76 | (4.3%) | 5.79 | 6.55 | (11.6%) | 6.10 | 6.65 | (8.4%) | ||||||||||||||||||||
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
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 on net margin of the costs and revenues of these plants on net margin were deferred.
The increase in energy revenues from members for the three-month periodand six-month periods ended March 31,June 30, 2016 compared to the same periodperiods in 2015 was primarily due to an increase in generation for member sales as a result of Smith and Hawk Road becoming available to the members in 2016. Partially offsetting the effectsOur members' ability to schedule these additional natural-gas fired facilities, which currently provide an economical source of theenergy due to low natural gas prices, significantly increased generation wasour megawatt-hour sales to our members and allowed us to provide a decreaselarger percentage of our members' load requirements to date in fuel costs. Primarily as2016. As a result, of the decrease in fuel costs, average energy revenue per kilowatt-hour from sales to members decreased 7.8%6.0% and 6.9% for the three-month periodand six-month periods ended March 31,June 30, 2016, respectively, as compared to the same periodperiods of 2015. 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 nearly 100% for both the three-month periodand six-month periods ended March 31,June 30, 2016 compared to the same periodperiods 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 | 2016 vs. | Three Months Ended | 2016 vs. | Three Months Ended | 2016 vs. | |||||||||||||||||||||||||||||||||||||||||||||
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Fuel Source | 2016 | 2015 | 2015 % Change | 2016 | 2015 | 2015 % Change | 2016 | 2015 | 2015 % Change | 2016 | 2015 | 2015 % Change | 2016 | 2015 | 2015 % Change | 2016 | 2015 | 2015 % Change | ||||||||||||||||||||||||||||||||||||||
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Coal | $ | 32,293 | $ | 42,485 | (24.0% | ) | 1,105,030 | 1,405,651 | (21.4% | ) | 2.92 | 3.02 | (3.3% | ) | $ | 33,191 | $ | 39,317 | (15.6%) | 1,136,430 | 1,403,234 | (19.0%) | 2.92 | 2.80 | 4.2% | |||||||||||||||||||||||||||||||
Nuclear(1) | 18,805 | 13,007 | 44.6% | 2,317,510 | 2,377,764 | (2.5% | ) | 0.81 | 0.55 | 48.3% | 21,031 | 22,469 | (6.4%) | 2,596,627 | 2,667,554 | (2.7%) | 0.81 | 0.84 | (3.8%) | |||||||||||||||||||||||||||||||||||||
Gas: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Combined Cycle | 41,495 | 47,315 | (12.3% | ) | 1,966,483 | 1,582,967 | 24.2% | 2.11 | 2.99 | (29.4% | ) | 50,560 | 42,300 | 19.5% | 2,395,362 | 1,583,860 | 51.2% | 2.11 | 2.67 | (21.0%) | ||||||||||||||||||||||||||||||||||||
Combustion Turbine | 6,359 | 5,602 | 13.5% | 159,478 | 46,157 | 245.5% | 3.99 | 12.14 | (67.1% | ) | 21,806 | 11,125 | 96.0% | 638,007 | 244,634 | 160.8% | 3.42 | 4.55 | (24.8%) | |||||||||||||||||||||||||||||||||||||
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$ | 98,952 | $ | 108,409 | (8.7% | ) | 5,548,501 | 5,412,539 | 2.5% | 1.78 | 2.00 | (11.0% | ) | $ | 126,588 | $ | 115,211 | 9.9% | 6,766,426 | 5,899,282 | 14.7% | 1.87 | 1.95 | (4.2%) | |||||||||||||||||||||||||||||||||
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Cost | Generation | Cents per kWh | ||||||||||||||||||||||||||
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(dollars in thousands) | (MWh) | |||||||||||||||||||||||||||
Six Months Ended | 2016 vs. | Six Months Ended | 2016 vs. | Six 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 | $ | 65,484 | $ | 81,802 | (19.9%) | 2,241,460 | 2,808,885 | (20.2%) | 2.92 | 2.91 | 0.3% | |||||||||||||||||
Nuclear(1) | 39,835 | 35,476 | 12.3% | 4,914,137 | 5,045,318 | (2.6%) | 0.81 | 0.70 | 15.3% | |||||||||||||||||||
Gas: | ||||||||||||||||||||||||||||
Combined Cycle | 92,051 | 89,617 | 2.7% | 4,361,845 | 3,166,827 | 37.7% | 2.11 | 2.83 | (25.4%) | |||||||||||||||||||
Combustion Turbine | 28,170 | 16,725 | 68.4% | 797,485 | 290,791 | 174.2% | 3.53 | 5.75 | (38.6%) | |||||||||||||||||||
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$ | 225,540 | $ | 223,620 | 0.9% | 12,314,927 | 11,311,821 | 8.9% | 1.83 | 1.98 | (7.4%) | ||||||||||||||||||
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The decrease in totalTotal fuel costs increased for the three-month and six-month periods ended June 30, 2016 as compared to the same periods of 2015 primarily due to increased generation at our natural gas-fired facilities. See "—Operating Revenues." An increase in nuclear fuel burn expense for the six-month period ended March 31,June 30, 2016 compared to the same period of 2015 was primarily due to lower natural gas prices and a shift in the generation mix from the coal-fired unitsalso contributed to the relatively more economical natural gas-fired combined cycle units. Slightly offsetting the decrease was an increase in nucleartotal fuel burn costs. 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 the three-month and six-month total fuel costs was a decrease in the average cost per kilowatt-hour of generation largely a result of a shift in the generation mix from the coal-fired units to the relatively more economical natural gas-fired units.
Production costs decreased 9.8%19.6% and 15.0% for the three-month periodand six-month periods ended March 31,June 30, 2016 as compared to the same periodperiods of 2015. Costs incurred during the first quarterhalf of 2015 were somewhat higher as a result of planned major maintenance work at Smith.Smith and Hawk Road.
Depreciation and amortization expense increased $10.8 million26.7% and 26.0% for the three-month periodand six-month periods ended March 31,June 30, 2016 compared to the same periodperiods 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.acquisition as well as in increase in depreciation associated with certain asset retirement obligations.
Financial Condition
Balance Sheet Analysis as of |
Assets
Cash used for property additions for the three-monthsix-month period ended March 31,June 30, 2016 totaled $259.4$301.5 million. Of this amount, approximately $180.4$267.7 million was associated with construction expenditures for Vogtle Units No. 3 and No. 4 $19.3and $29.3 million for nuclear fuel purchases and the remaining expenditures were for normal additions and replacements to 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 and Rural Utilities Service-guaranteed Federal Financing Bank notes. Decisions regarding when to apply the funds are guided by the interest rate environment and our anticipated liquidity needs.
TableReceivables increased $40.0 million for the six-month period ended June 30, 2016 primarily as a result of Contentsamounts billed or billable to the members due to higher energy costs during the period, which were a result of increased generation.
Equity and Liabilities
Long-term debt increased $573.4 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 six-month period ended June 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.
Short-term borrowings, increased $41.5 million during the three-month period ended March 31, 2016 towhich provide interim financing for Vogtle Units No. 3 and No. 4 construction costs.costs, decreased $185.5 million during the six-month period ended June 30, 2016. Total borrowings atand repayments during the end of the quarterperiod were $432.8$114.8 million of which $129.7and $300.3 million, wasrespectively. The repayments were refinanced with long-term debt through a portion of the issuance of first mortgage bonds issued in April 2016 and classified as long-term debt asunder the Department of March 31, 2016.Energy guaranteed-loan. See Note K of Notes to Unaudited Consolidated Financial Statements for information regarding the debt issuance of first mortgage bonds and commercial paper repayment.issuances.
Accounts payable decreased $113.2$85.6 million for the three-monthsix-month period ended March 31,June 30, 2016 primarily as a result of a $96.3$93.1 million decrease in the payable to Georgia Power for operation and maintenance costs for our co-owned plants and capital costs associated with Vogtle Units No. 3 and No. 4. Also contributing to the decrease was $9.2 million in credits applied to our members' bills in the first quarter of 2016, for a board approved reduction in 2015 revenue requirements as a result of margin collections in excess of our 2015 target. Partially offsetting the decrease was an increase in payables related to natural gas purchases.
Other current liabilities decreased $30.2$41.4 million for the three-monthsix-month period ended March 31,June 30, 2016 primarily due to a decrease in estimates for unrecorded liabilities, a decrease in the unrealized losses associated with natural gas hedges and the payment of certain property taxes.
Asset retirement obligations increased $86.1 million during the six-month period ended June 30, 2016 primarily 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.
In connection with the Vogtle Units No. 3 and No. 4 construction project, we are accruing long-term contract retainage amounts for substantial and mechanical completion milestones. For the six-month period ended June 30, 2016 there was a $27.4 million decrease in the long-term contract retainage amounts as a result of modifications to the construction contract. For information regarding the Vogtle construction project, see Note G of Notes to Unaudited Consolidated Financial Statements.
Capital Requirements and Liquidity and Sources of Capital |
Vogtle Units No. 3 and No. 4.
We, along withFor 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.
In 2008, Georgia Power, acting for itself and as agent for us, the Municipal Electric Authority of Georgia, and the City of Dalton, are participating inGeorgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, doing business as Dalton Utilities (collectively, the construction ofCo-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 nuclear generating unitstechnology and related facilities at Plant Vogtle, each with a nominally rated generating capacity of approximately 1,100 megawatts.Units No. 3 and No. 4. Our ownership interest and proportionate share of the cost to construct these units is 30%.
Under the EPC Agreement, the Co-owners will pay a purchase price that is subject to certain price escalations and adjustments, including fixed escalation amounts and certain index-based adjustments, as well as adjustments for change orders and performance bonuses. The EPC Agreement also provides for liquidated damages upon the Contractor's failure to fulfill the schedule and performance guarantees, subject to a cap. In addition, the EPC Agreement provides for limited cost sharing by the Co-owners for increases to Contractor costs under certain conditions. The maximum amount of additional capital costs under this provision attributable to us is $75 million. Each Co-owner is severally, not jointly, liable to the Contractor for its proportionate share, based on ownership interest, of all amounts owed under the EPC Agreement. As agent for the Co-owners, Georgia Power has designated Southern Nuclear Operating Company as its agent for contract management.
On December 31, 2015, Westinghouse acquired Stone & Webster, Inc. from Chicago Bridge & Iron Co. N.V. (the Acquisition). In connection with the Acquisition, Stone & Webster, Inc. changed its name to WECTEC Global Project Services Inc. (WECTEC). In connection with the Acquisition, Westinghouse engaged Fluor Enterprises, Inc., representing 660 megawattsa subsidiary of total capacity.Fluor Corporation, as a new construction subcontractor.
The current estimated in-service dates are June 30, 2019 for Unit No. 3 and June 30, 2020 for Unit No. 4. Our project budget, which includes capital costs, allowance for funds used during construction and a contingency amount, is $5.0 billion. Included in the project budget is our share of owner-related costs, including property taxes, oversight costs, compliance costs and other operational readiness costs, as well as financing costs, totaling approximately $20 million per month, on average, through the estimated in-service dates. As of March 31,June 30, 2016, our total investment in the additional Vogtle units was $3.1 billion. For information regarding the financing of Vogtle Units No. 3 and No. 4, was $3.0 billion.see "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION—Financial Condition—Financing Activities—Department of Energy-Guaranteed Loan" and "—Capital Requirements—Capital Expenditures" and Note 7(a) of Notes to Consolidated Financial Statements in our 2015 Form 10-K.
Various design and other licensing-based compliance matters, including the timely resolution of inspections, tests, analyses and acceptance criteria 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 to the Co-owners, the Contractor, or both.
ForIn connection with Georgia Power's participation in the development and construction of the additional information aboutVogtle Units and its certification of Georgia Power's costs to construct the additional Vogtle Units, the Georgia Public Service Commission engaged an independent construction monitor to evaluate and report on the progress of the Vogtle project. In June 2016, in connection with the 14th Vogtle Construction Monitoring report, the independent monitor provided testimony stating that Georgia Power had not demonstrated to the Georgia Public Service Commission Staff that the current estimated in-service dates for Vogtle Units No. 3 and No. 4 have a reasonable chance of being met. He also expressed his opinion that there exists a strong likelihood of further delayed operation dates for both Units. We have been advised by Georgia Power, as agent for the Co-owners, that it disagrees with these opinions and believes that the current estimated in-service dates for Vogtle Units No. 3 and No. 4 are challenging but remain achievable.
As construction project, seecontinues, the risk remains that challenges with the Contractor's performance, including additional challenges in labor productivity and its fabrication, assembly, delivery, and installation of the plant equipment, the shield building and structural modules, could further impact the estimated in-service dates and cost and the Contractor must improve its schedule performance in order to mitigate this risk. As discussed under "Item 1—BUSINESS—OUR POWER SUPPLY RESOURCES—Future Power Resources—Plant Vogtle Units No. 3 and No. 4" and "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Capital Requirements—Capital Expenditures"1A—RISK FACTORS" in our 2015 Form 10-K. Also see Note G10-K, other issues could arise and may further impact the project schedule and cost. The ultimate outcome of Notes to Unaudited Consolidated Financial Statements.these matters cannot be determined at this time.
Environmental Regulations
Existing federal 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 2015 10-KForm 10-Q for the quarterly period ended March 31, 2016 that may impact the operation of our facilities.
On April 25,June 30, 2016, the U.S. Environmental Protection Agency (EPA) signedEPA proposed the design details for a rule proposing revisionsClean Energy Incentive Program (CEIP), a voluntary program that states can adopt to incentivize early emission reduction projects under the Clean Power Plan (CPP). Under the CEIP, states can distribute allowances (for mass-based plans) or emission rate credits (ERCs) (for rate-based plans) to eligible clean energy projects that generate savings in 2020 and 2021. Such projects would include demand-side energy efficiency and solar projects implemented to serve low-income communities, and zero-emitting renewable energy projects using wind, solar, geothermal or hydropower generation in all communities. EPA would award matching allowances (or ERCs), from a national pool of 300 million short tons of CO2 emissions (or 375 million ERCs) to state-approved projects, which in turn could then sell or transfer the allowances (or ERCs) to electric generating units subject to CPP CO2 emission limits. The national pool would be allocated to each CEIP-participating state, based on its emissions reductions requirements from 2012 levels relative to the regional haze program, describing actions the states must take when submitting regional haze state implementation plans and progress reports for the period 2019 - 2028. The purpose of the program is to protect visibility in designated sensitive federal areas such as national parks, like the nearby Great Smokey Mountains National Park, and certain wilderness areas (including the Cohutta, Okefenokee and Wolf Island areas in Georgia). Potentially affected entities include states, Federal Land Managers and owners and/or operators of sources that emit visibility-impairing substances including fossil fuel-fired power plants. The proposed revisions would make several technical and administrative changes to the program, including a one-time adjustment to the due date for the next state implementation plans (from July 21, 2018 to July 31, 2021).other CEIP-participating states. We cannot determine the outcome of this proposal on our operations, if any, the effect of any planthe program should Georgia may develop and submitchoose to participate in
response to EPA's rule when finalized, the result of EPA review and approval of any Georgia submission it, or the outcome of any litigation that could be brought challenging the CEIP if finalized.
On April 17, 2015, EPA published a final coal combustion residuals (CCR) rule, in which it decided to regulate CCRs from electric utilities as non-hazardous material under Subtitle D of the Resource Conservation and Recovery Act. The final rule, which became effective in October 2015, contains
requirements for structural integrity assessments, groundwater monitoring, location siting, composite lining, inactive units, closure and post closure, beneficial use recycling, design and operating criteria, recordkeeping, notification, and internet posting for new and existing CCR landfills, CCR surface impoundments and lateral expansions of CCR facilities. On November 3, 2015, the EPA also published a final rule to revise the effluent limitations guidelines that apply to certain wastewater discharges from fossil fuel-fired steam electric power plants (including our co-owned Plants Wansley and Scherer). Subsequently, in May and July of 2016, and in response to EPA's CCR rulemaking, the Georgia Environmental Protection Division (EPD) proposed to add specific provisions for CCR wastes to its existing solid waste management rules. EPD's rules would contain the requirements in EPA's CCR Rule but would add further requirements for CCR wastes in Georgia. Such requirements would be administered in a state permit system, with permits to be issued and enforced by EPD. Citizen groups would retain the authority to enforce federal CCR requirements. The proposed EPD regulations are expected to be finalized in October 2016 and are not anticipated to have a material impact on our compliance obligations under the federal CCR rule.
In September 2015, Georgia Power announced that it is preparing a schedule to close existing ash ponds at all of its Georgia coal-fired facilities, including at our co-owned Plants Scherer and Wansley. On June 13, 2016, Georgia Power further announced that it will cease sending CCR to all of its ash ponds in Georgia within three years. It also announced that it will close the ash ponds in place using advanced engineering methods at Plants Wansley and Scherer, among other locations. Our current estimated expenditures for the settlement of related asset retirement obligations are approximately $172 million for the closure and post-closure of existing coal ash ponds. See Note L of Notes to Unaudited Consolidated Financial Statements. Preliminary estimates suggest that our capital expenditures to comply with the CCR rule and effluent limitations guidelines will be approximately $170 million for conversion to dry ash handling, landfill construction and wastewater treatment. More definitive cost estimates will be developed as the process of rule evaluation, compliance approach and design and construction implementation proceeds. The ultimate impacts associated with the federal and state CCR rules and the federal effluent limitations guidelines cannot be determined with certainty at this time.
On June 12, 2015, EPA published a rule in the Federal Register requiring certain states to revise the provisions of their State Implementation Plans (SIPs) relating to the regulation of excess emissions at industrial facilities, including fossil fuel-fired generating facilities, during periods of startup, shut-down, or malfunction (SSM). EPA is requiring revision to the SSM-related SIPs for 36 states, including Georgia, by November 22, 2016. In response to EPA's rule, in July 2016 EPD proposed to amend its state SSM rules and related SIP provisions accordingly. Litigation challenging EPA's SSM rule continues in the U.S. Court of Appeals for the District of Columbia Circuit. We cannot determine the outcome of EPD's proposed SSM rule on our operations, the outcome of any litigation on EPA's SSM rule, or any litigation that could be brought challenging EPD's SSM rule (and related SIP provisions) once finalized.
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 2015 Form 10-K.
Liquidity
At March 31,June 30, 2016, we had $1.0$1.63 billion of unrestricted available liquidity to meet our short-term cash needs and liquidity requirements. This amount included $111$347 million in cash and cash equivalents and $925 million$1.28 billion of unused and available committed credit arrangements.
At March 31,June 30, 2016, we had in excess of $1.6$1.61 billion of committed credit arrangements in place, the details of which are reflected in the table below:
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Committed Credit Facilities | Committed Credit Facilities | Committed Credit Facilities | ||||||||||||||
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Authorized | Available | Expiration Date | Authorized | Available | Expiration Date | |||||||||||
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(dollars in millions) | (dollars in millions) | |||||||||||||||
Unsecured Facilities: | ||||||||||||||||
Syndicated Line of Credit led by CFC | $ | 1,210 | (1) | $ | 641 | (2) | March 2020 | $ | 1,210 | (1) | $ | 998 | (2) | March 2020 | ||
CFC Line of Credit(3) | 110 | 110 | December 2018 | 110 | 110 | December 2018 | ||||||||||
JPMorgan Chase Line of Credit | 150 | 34 | (4) | November 2016 | 150 | 34 | (4) | November 2016 | ||||||||
Secured Facilities: |
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CFC Term Loan(3) | 250 | 250 | December 2018 | 250 | 250 | December 2018 | ||||||||||
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As of March 31, 2016, we wereWe are currently using our commercial paper program to provide interim funding for 1) payments related to the construction of Vogtle Units No. 3 and No. 4 prior to receiving advances of permanentlong-term funding under the Department of Energy-guaranteed Federal Financing Bank loan, which can be requested no more frequently than quarterly and 2) the premium payments made in connection with our interest rate hedging program.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 interim financings described above.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 March 31,June 30, 2016. 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 March 31,June 30, 2016, the required minimum level was $675 million and our actual patronage capital was $830$853 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
$12.0 billion and $4.0 billion, respectively. At March 31,June 30, 2016, we had $7.8$8.2 billion of secured indebtedness and $433$76 million of unsecured indebtedness outstanding.
We plan to renew the $150 million line of credit with JPMorgan Chase Bank, N.A. before it expires on November 15, 2016.
At March 31,June 30, 2016, we had $395$355 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 March 31,June 30, 2016—Assets" for more information regarding this account.
Financing Activities
First Mortgage Indenture. At March 31,June 30, 2016, we had $7.7$8.2 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 2015 Form 10-K for further discussion of our first mortgage indenture.
Rural Utilities Service-Guaranteed Loans. At March 31,June 30, 2016 we had threetwo approved Rural Utilities Service-guaranteed loans being funded through the Federal Financing Bank that are in various stages of being drawn down. These threetwo loans totaled $561$358 million with $178$95 million remaining to be advanced. When advanced, the debt will be secured under our first mortgage indenture. As of March 31,June 30, 2016, we had $2.6 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 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 March 31,June 30, 2016, our total investment in Vogtle Units No. 3 and No. 4 was $3.0$3.1 billion and we have incurred $2.6$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 we previously issued and $1.2$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 March 31,June 30, 2016, we have the capacity to fund an additional $758$509 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, the debt will be secured under our first mortgage indenture. For additional information regarding this loan, see Note K of Notes to Unaudited Consolidated Financial Statements.
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 2015 Form 10-K.
Bond Financing. On April 21, 2016, we issued $250 million of Series 2016A first mortgage bonds to provide long-term financing for expenditures related to the Vogtle construction project and the Smith
Energy Facility. The bonds are secured under our first mortgage indenture. See Note K of Notes to Unaudited Consolidated Financial Statements for additional information regarding thethis bond issuance.
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 2015 Form 10-K.
Item 4. Controls and Procedures
As of March 31,June 30, 2016, 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 March 31,June 30, 2016 that have materially affected, or are reasonably likely to affect, our internal control over financial reporting.
Patronage Capital Litigation
On May 31, 2016, plaintiffs for both of the cases described under "Part II—Item 1. Legal Proceedings—Patronage Capital Litigation" in our Form 10-Q for the quarterly period ended March 13, 2014, a lawsuit was filed in31, 2016 appealed the Superior Court of DeKalb County, Georgia, against us, Georgia Transmission and three of our member distribution cooperatives. Plaintiffs filed an amended complaint on July 28, 2014. The amended complaint challenges the patronage capital distribution practices of Georgia's electric cooperatives and seeks to certify a defendant class of all but one of our 38 members. It was filed by four former consumer-members of four of our members on behalf of themselves and a proposed class of all former consumer-members of our members. Plaintiffs claim that approximately 30% of all the defendants' total allocated patronage capital belongs to former consumer-members. Plaintiffs also allege that patronage capital owed to former consumer-members includes patronage capital allocated by us to our members but not yet distributed to our members. Plaintiffs claim that the patronage capital of former consumer-members held by defendants and the proposed defendant class should be retired immediately when the consumer-members end their membership by terminating service, or alternatively, according to a revolving schedule of no longer than 13 years from the date of its allocation and seek relief to effect such retirements. Plaintiffs further seek to require the defendants to adjust rates in order to establish and maintain reasonable reserves to fund patronage capital retirements on this basis. Plaintiffs also claim that defendants and the proposed defendant class should be required to adopt policies to periodically retire the patronage capital of all consumer-members on a revolving schedule of no longer than 13 years from the date of its allocation. Our first mortgage indenture restricts our ability to distribute patronage capital. See "Item 1—BUSINESS—OGLETHORPE POWER CORPORATION—First Mortgage Indenture" in our 2015 Form 10-K. Although not expected, if we were ordered by the Court to make distributions of our patronage capital, our first mortgage indenture would require us to raise our rates to a level sufficient so that we could comply with the current patronage capital distribution restrictions, and the rate increases required to meet the Plaintiffs' demands would be significant for a period of years.
On August 20, 2014, a second patronage capital lawsuit was filed in the Superior Court of DeKalb County against us, Georgia Transmission, and two of our member distribution cooperatives. The case was filed by two current consumer-members of the two member distribution cooperatives named in the lawsuit. Similar to the above described litigation, this complaint challenges the patronage capital distribution practices of Georgia's electric cooperatives; however, one notable difference is that the first case, described above, seeks to bring claims on behalf of former members while this second case seeks to bring claims on behalf of current members. The plaintiffs allege that the defendants have (i) retained patronage capital for an unreasonably long period of time; (ii) conspired with each other to deprive consumer-members of their patronage capital; and (iii) breached bylaw provisions allegedly requiring that patronage capital be retired when the financial condition of the cooperative will not be impaired. The plaintiffs seek unspecified damages and equitable relief, including an order declaring that the defendants be required to retire patronage capital "according to a regular, reasonable revolving plan." Similarly to the litigation described above, although not expected, if we were ordered by the Court to make distributions of our patronage capital, our first mortgage indenture would require us to raise our rates to a level where we could comply with current patronage capital distribution restrictions, and the rate increases required to meet the Plaintiff's demands could be significant for a period of years. The plaintiffs seek to certify three plaintiffs' classes but do not seek to certify a defendants' class.
In May 2015, the Superior Court judge appointed a special master to oversee all pre-trial issues relating to these cases, including motions to dismiss that we and the other defendants filed in connection with each lawsuit. In September, the special master issued proposed orders to the judgeCourt's decision to grant our and the other defendants' motions to dismiss both patronage capitalof those lawsuits on all counts.
Tablecounts to the Georgia Court of Contents
On May 2, 2016, the Superior Court judge adopted the special master's proposed orders and granted our and the other defendants' motions to dismiss both of these lawsuits on all counts. The Court's decision remains subject to appeal.Appeals.
We intend to defend vigorously against all claims in the above-described litigation.
There have been no material changes from the risks disclosed in "Item 1A—RISK FACTORS" of our 2015 Form 10-K.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Not Applicable.
Item 3. Defaults upon Senior Securities
Not Applicable.
Item 4. Mine Safety Disclosures
Not Applicable.
Not Applicable.
Number | Description | ||
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Amendment No. 8, dated as of April 20, 2016, to the Engineering, Procurement and Construction Agreement, dated as of April 8, 2008, between Georgia Power, for itself and as agent for Oglethorpe, Municipal Electric Authority of Georgia, and Dalton Utilities, as owners, and a consortium consisting of Westinghouse and Stone & Webster, as contractor, for Units 3 & 4 at the Vogtle Electric Generating Plant Site. (Incorporated by reference to Exhibit 10(c)(3) of Georgia Power Company's Form 10-Q for the quarterly period ended June 30, 2016, filed with the SEC on August 8, 2016) | |||
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). | ||
32.2 | Certification Pursuant to 18 U.S.C. 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Elizabeth B. Higgins (Principal Financial Officer). | ||
101 | XBRL Interactive Data File. |
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Oglethorpe Power Corporation (An Electric Membership Corporation) | ||||
Date: | By: | /s/ 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) |