Exhibit 99.6
EQUIPOWER RESOURCES CORP. AND SUBSIDIARIES
AND BRAYTON POINT HOLDINGS, LLC AND SUBSIDAIRY
MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion of Equipower Resources Corp. and Subsidiaries and Brayton Point Holdings, LLC and Subsidiary’s financial condition and results of operations should be read in conjunction with their audited historical combined financial statements and the notes thereto as of December 31, 2011, 2012 and 2013, and for the years ended December 31, 2011, 2012 and 2013 (the “Audited Financial Statements”) and unaudited historical combined financial statements and the notes thereto as of June 30, 2014 and December 31, 2013 and for the six-months ended June 30, 2013 and 2014 (the “Unaudited Financial Statements”), each of which is attached as an exhibit to the Form 8-K to which this discussion is an exhibit. Unless the context requires otherwise, references in this discussion to “we,” “our,” or “us” refer collectively to Equipower Resources Corp. and Brayton Point Holdings, LLC and their respective subsidiaries.
The discussion below also includes a non-GAAP financial measure referencing our energy margin for the years ended December 31, 2011, 2012 and 2013 and for the six months ended June 30, 2013 and 2014. We use this non-GAAP financial measure to evaluate the performance of the facilities and to provide details of margin for the portfolio excluding net hedge settlements, mark-to-market for economic hedging activities, capacity revenue and ancillary and other revenue. Due to the nature and significance of these items, we believe that the non-GAAP presentation is useful in describing our financial performance as it provides additional and useful information to readers in analyzing our historical and future performance. This non-GAAP financial measure should not be considered as an alternative to total margin determined in accordance with GAAP, or as an indicator of operating performance.
Factors Affecting Comparability of Our Combined Financial Statements
Date | | Actions | | Notes |
| | | | |
January 20, 2011 | | Acquired Milford | | For more information, see note 3 of our Audited Financial Statements |
| | | | |
January 28, 2011 | | Entered into a Credit and Guaranty Agreement which consisted of $425 million term loan facility and a $100 million working capital facility | | For more information, see note 15 of our Audited Financial Statements |
| | | | |
October 7, 2011 | | Acquired Liberty Electric Generation Holdings | | For more information, see note 3 of our Audited Financial Statements |
| | | | |
June 21, 2012 | | Entered into our First Lien Credit Facilities, which consisted of a $685 million Term B Loan Facility and a $100 million working capital facility (collectively, the “Refinancing”) | | In connection with the Refinancing, we restructured certain commodity hedges relating to our Lake Road and Milford facilities in order to eliminate gas basis risk associated with those transactions. For more information, see note 15 of our Audited Financial Statements. |
| | | | |
October 31, 2012 | | Entered into the First Amendment to our First Lien Credit Facilities | | For more information, see note 15 of our Audited Financial Statements. |
| | | | |
August 29, 2013 | | Acquired Kincaid and a 49.5% interest in Elwood | | For more information, see note 3 of our Audited Financial Statements. |
| | | | |
August 29, 2013 | | Acquired Brayton Point from Dominion Energy Inc. | | For more information, see note 3 of our Audited Financial Statements. |
| | | | |
August 29, 2013 | | In connection with the acquisitions of Kincaid, Elwood and Brayton Point, we entered into the Third Amendment to our First Lien Credit Facilities. | | For more information, see note 15 of our Audited Financial Statements. |
| | | | |
December 18, 2013 | | Acquired Richland and Stryker | | For more information, see note 3 of our Audited Financial Statements. |
| | | | |
December 18, 2013 | | In connection with the acquisition of Richland and Stryker, we entered into the Fifth Amendment to our First Lien Credit Facilities | | For more information, see note 15 of our Audited Financial Statements. |
Combined Results of Operations of Our Business
The following is a discussion of the combined results of operations of our business:
| | Years Ended December 31, | | Six Months Ended June 30, | |
(in thousands) | | 2013 | | 2012 | | Change $ | | Change % | | 2014 | | 2013 | | Change $ | | Change % | |
OPERATING REVENUES | | | | | | | | | | | | | | | | | |
Energy revenues | | $ | 865,570 | | $ | 497,664 | | $ | 367,906 | | 73.93 | % | $ | 843,822 | | $ | 360,838 | | $ | 482,984 | | 133.85 | % |
Net hedge settlements(a) | | (38,393 | ) | (14,833 | ) | (23,560 | ) | -158.84 | % | (105,118 | ) | (18,460 | ) | (86,658 | ) | -469.44 | % |
Capacity revenues | | 115,957 | | 82,269 | | 33,688 | | 40.95 | % | 90,553 | | 41,328 | | 49,225 | | 119.11 | % |
Mark-to-market for commodity hedging activities | | (84,135 | ) | (13,908 | ) | (70,227 | ) | -504.94 | % | 29,604 | | (5,882 | ) | 35,486 | | 603.30 | % |
Ancillaries and other revenues | | 10,652 | | 6,633 | | 4,019 | | 60.59 | % | 16,923 | | 3,483 | | 13,440 | | 385.87 | % |
Total operating revenues | | $ | 869,651 | | $ | 557,825 | | $ | 311,826 | | 55.90 | % | $ | 875,784 | | $ | 381,307 | | $ | 494,477 | | 129.68 | % |
OPERATING EXPENSES | | | | | | | | | | | | | | | | | |
Energy and fuel costs | | 666,792 | | 370,818 | | 295,974 | | 79.82 | % | 522,113 | | 297,138 | | 224,975 | | 75.71 | % |
Operations and maintenance | | | | | | | | | | | | | | | | | |
Operation and maintenance | | 75,266 | | 51,333 | | 23,933 | | 46.62 | % | 84,929 | | 15,872 | | 69,057 | | 435.09 | % |
General and administrative costs | | 18,066 | | 13,140 | | 4,926 | | 37.49 | % | 12,182 | | 6,824 | | 5,358 | | 78.52 | % |
Debt refinancing costs | | 7,355 | | 3,556 | | 3,799 | | 106.83 | % | — | | — | | — | | 0.00 | % |
Total operations and maintenance | | $ | 100,687 | | $ | 68,029 | | $ | 32,658 | | 48.01 | % | $ | 97,111 | | $ | 22,696 | | $ | 74,415 | | 327.88 | % |
Depreciation and amortization | | 64,592 | | 51,793 | | 12,799 | | 24.71 | % | 46,183 | | 27,937 | | 18,246 | | 65.31 | % |
Taxes other than income taxes | | 24,826 | | 31,157 | | (6,331 | ) | -20.32 | % | 11,561 | | 15,739 | | (4,178 | ) | -26.55 | % |
Total operating expenses | | $ | 856,897 | | $ | 521,797 | | $ | 335,100 | | 64.22 | % | $ | 676,968 | | $ | 363,510 | | $ | 313,458 | | 86.23 | % |
OPERATING INCOME | | 12,754 | | 36,028 | | (23,274 | ) | -64.60 | % | 198,816 | | 17,797 | | 181,019 | | 1017.13 | % |
Interest and fees on debt | | 86,865 | | 88,811 | | (1,946 | ) | -2.19 | % | 42,795 | | 35,923 | | 6,872 | | 19.13 | % |
Equity loss (income) in affiliates | | 1,243 | | — | | 1,243 | | 100.00 | % | (1,692 | ) | — | | (1,692 | ) | -100.00 | % |
Other income | | (34 | ) | (4,314 | ) | 4,280 | | 99.21 | % | (49 | ) | (13 | ) | (36 | ) | -276.92 | % |
(Gain) loss on mark-to-market on interest rate derivative contracts | | (4,183 | ) | 4,654 | | (8,837 | ) | -189.88 | % | 7,162 | | (7,727 | ) | 14,889 | | 192.69 | % |
(Gain) loss on bargain purchase of business | | (3,119 | ) | — | | (3,119 | ) | -100.00 | % | — | | — | | — | | 0.00 | % |
(LOSS) INCOME BEFORE INCOME TAXES | | $ | (68,018 | ) | $ | (53,123 | ) | $ | (14,895 | ) | -28.04 | % | $ | 150,600 | | $ | (10,386 | ) | $ | 160,986 | | 1550.03 | % |
Income tax (benefit) expense | | (26,876 | ) | (13,286 | ) | (13,590 | ) | -102.29 | % | 58,588 | | (3,756 | ) | 62,344 | | 1659.85 | % |
NET (LOSS) INCOME | | $ | (41,142 | ) | $ | (39,837 | ) | $ | (1,305 | ) | -3.28 | % | $ | 92,012 | | $ | (6,630 | ) | $ | 98,642 | | 1487.81 | % |
(a) Includes realized gains and losses from financially settled transactions.
| | For the Year Ended December 31, | |
(in thousands) | | 2012 | | 2011 | | Change $ | | Change % | |
OPERATING REVENUES | | | | | | | | | |
Energy revenues | | 497,664 | | 536,450 | | (38,786 | ) | -7.23 | % |
Net hedge settlements (a) | | (14,833 | ) | (31,154 | ) | 16,321 | | 52.39 | % |
Capacity revenues | | 82,269 | | 70,405 | | 11,864 | | 16.85 | % |
Mark-to-market for economic hedging activities | | (13,908 | ) | (18,746 | ) | 4,838 | | 25.81 | % |
Ancillaries and other revenues | | 6,633 | | 4,701 | | 1,932 | | 41.10 | % |
Total operating revenues | | 557,825 | | 561,656 | | (3,831 | ) | -0.68 | % |
OPERATING EXPENSES | | | | | | | | | |
Energy and fuel costs | | 370,818 | | 461,996 | | (91,178 | ) | -19.74 | % |
Operations and maintenance | | | | | | | | | |
Operation and maintenance | | 51,333 | | 36,368 | | 14,965 | | 41.15 | % |
General and administrative costs | | 13,140 | | 10,304 | | 2,836 | | 27.52 | % |
Debt refinancing costs | | 3,556 | | — | | 3,556 | | 0.00 | % |
Total operations and maintenance | | 68,029 | | 46,672 | | 21,357 | | 45.76 | % |
Depreciation and amortization | | 51,793 | | 31,053 | | 20,740 | | 66.79 | % |
Taxes other than income taxes | | 31,157 | | 21,734 | | 9,423 | | 43.36 | % |
Total operating expenses | | 521,797 | | 561,455 | | (39,658 | ) | -7.06 | % |
OPERATING INCOME | | 36,028 | | 201 | | 35,827 | | 17824.38 | % |
Interest and fees on long-term debt | | 88,811 | | 36,420 | | 52,391 | | 143.85 | % |
Net losses (gains) of affiliates | | — | | — | | — | | 0.00 | % |
Other income | | (4,314 | ) | (28 | ) | (4,286 | ) | -15307.14 | % |
(Gain)/Loss on mark-to-market on interest rate derivative contracts | | 4,654 | | 7,715 | | (3,061 | ) | -39.68 | % |
(Gain)/Loss on bargain purchase of business | | — | | — | | — | | 0.00 | % |
LOSS BEFORE INCOME TAX BENEFIT | | (53,123 | ) | (43,906 | ) | (9,217 | ) | -20.99 | % |
Income tax expense (benefit) | | (13,286 | ) | (15,899 | ) | 2,613 | | 16.43 | % |
NET LOSS BEFORE PREFERRED DIVIDENDS | | (39,837 | ) | (28,007 | ) | (11,830 | ) | -42.24 | % |
Preferred dividends | | — | | 1,395 | | (1,395 | ) | -100.00 | % |
NET LOSS | | (39,837 | ) | (29,402 | ) | (10,435 | ) | -35.49 | % |
(a) Includes realized gains and losses from financially settled transactions.
Six Months Ended June 30, 2014 and 2013
The following is a discussion of selected historical statement of operations and operating data by region.
| | Six Months Ended June 30, | |
| | 2014 | | 2013 | |
| | ISO-NE | | PJM | | ISO-NE | | PJM | |
Total Fleet | | | | | | | | | |
Generation volume (GWh) | | 6,085 | | 4,602 | | 4,734 | | 1,536 | |
Commercial availability (CA) | | 81.2 | % | 80.5 | % | 91.0 | % | 77.6 | % |
Equivalent availability factor (EAF) | | 82.1 | % | 87.3 | % | 88.2 | % | 75.4 | % |
Equivalent forced outage factor (EFOF) | | 6.9 | % | 3.0 | % | 5.3 | % | 0.6 | % |
Natural Gas Fleet | | | | | | | | | |
Starts reliability factor(a) | | 97.0 | % | 89.0 | % | 98.0 | % | 100.0 | % |
Net capacity factor (CCGTs) | | 51.3 | % | 64.2 | % | 51.8 | % | 65.4 | % |
Coal Fleet | | | | | | | | | |
Net capacity factor | | 43.3 | % | 62.2 | % | n/a | | n/a | |
(a) Contains peakers and gas facilities, excludes coal plants.
Operating statistics are affected by seasonality, economics and major planned maintenance outage schedules as well as unplanned outages and derates. On a quarterly basis, these factors may have significant impacts on operating statistics but over the course of a full year, the statistics more accurately reflect the operations of the plants.
ISO-NE differences in EAF, EFOF, CA and coal Net Capacity Factor were impacted by the acquisition of Brayton Point on August 29, 2013, and more planned outages for the gas fleet in the spring of 2014 compared to the six month ended June 30, 2013.
The increase in PJM EAF and CA is attributed to the acquisitions of Kincaid and Richland and Stryker on August 29, 2013 and December 18, 2013, respectively. The increase in EFOF is primarily due to Richland and Stryker fuel gas curtailment forced outages in 2014. During the severely cold winter of 2013-2014, pipeline and local distribution company (“LDC”) restrictions (including requirements to burn ratably over a 24-hour period) coupled with the peaking nature of Richland and Stryker created a situation that made it necessary to declare the unit unavailable to PJM so that the PJM operators could have the necessary information for reliable dispatch of the system. Richland and Stryker, as peaking facilities, would not be expected to be economically dispatched for a 24-hour period, but the LDC and pipeline constraints would have required us to burn an equal amount of gas in each of the 24-hours each day. While the operating statistics are negatively impacted by those hours declared unavailable due to the LDC and pipeline restrictions, the commercial availability impact is small.
The decrease in start reliability, mainly related to Richland and Stryker, was primarily driven by extreme cold weather conditions in the winter 2014 and the lack of legacy winter operational preparation prior to our ownership. Corrective measures have since been addressed in preparation for the next winter season.
Discussion of Combined Results of Operations for Six Months Ended June 30, 2014 and 2013
| | For the Six Months Ended June 30, 2014 | | For the Six Months Ended June 30, 2013 | |
| | ISO-NE | | PJM | | Total | | ISO-NE | | PJM | | Total | |
| | (in thousands) | |
Energy revenue | | 587,617 | | 256,205 | | 843,822 | | 300,524 | | 60,314 | | 360,838 | |
Energy and fuel costs | | 363,096 | | 159,017 | | 522,113 | | 248,730 | | 48,408 | | 297,138 | |
Energy margin | | $ | 224,521 | | $ | 97,188 | | $ | 321,709 | | $ | 51,794 | | $ | 11,906 | | $ | 63,700 | |
Net hedge settlements | | (70,931 | ) | (34,187 | ) | (105,118 | ) | (20,184 | ) | 1,724 | | (18,460 | ) |
Capacity revenues | | 56,985 | | 33,568 | | 90,553 | | 26,248 | | 15,080 | | 41,328 | |
Ancillaries and other revenue | | 12,175 | | 4,748 | | 16,923 | | 1,374 | | 2,109 | | 3,483 | |
Total gross margin(a) | | $ | 222,750 | | $ | 101,317 | | $ | 324,067 | | $ | 59,232 | | $ | 30,819 | | $ | 90,051 | |
| | Change | |
| | Change $
(ISO-NE) | | Change %
(ISO-NE) | | Change $
(PJM) | | Change %
(PJM) | | Change $
(Total) | | Change %
(Total) | |
| | (in thousands) | |
Energy revenue | | 287,093 | | 95.53 | % | 195,891 | | 324.79 | % | 482,984 | | 133.85 | % |
Energy and fuel costs | | 114,366 | | 45.98 | % | 110,609 | | 228.49 | % | 224,975 | | 75.71 | % |
Energy margin | | $ | 172,727 | | 333.49 | % | $ | 85,282 | | 716.29 | % | $ | 258,009 | | 405.04 | % |
Net hedge settlements | | (50,747 | ) | (251.42 | )% | (35,911 | ) | (2,083.00 | )% | (86,658 | ) | (469.44 | )% |
Capacity revenues | | 30,737 | | 117.10 | % | 18,488 | | 122.60 | % | 49,225 | | 119.11 | % |
Ancillaries and other revenue | | 10,801 | | 786.10 | % | 2,639 | | 125.13 | % | 13,440 | | 385.87 | % |
Total gross margin(a) | | $ | 163,518 | | 276.06 | % | $ | 70,498 | | 228.75 | % | $ | 234,016 | | 259.87 | % |
(a) Total gross margin excludes mark-to-market for economic hedging activities of $43.8 million and ($14.2) million for the six months ended June 30, 2014 for ISO-NE and PJM, respectively. For the six months ended June 30, 2013, mark-to-market for economic hedging activities was ($5.1) million and ($0.7) million for ISO-NE and PJM, respectively. The mark-to market for economic hedging activities is a non-cash event to record change in fair value associated with open commodity hedge transactions.
Energy margin
The ISO-NE region energy margin revenue increased by $172.7 million for the six months ended June 30, 2014 compared to the six months ended June 30, 2013, primarily resulting from a $155.2 million increase due to our acquisition of Brayton Point on August 29, 2013 and $31.8 million increase due to higher spark spreads which benefitted our ISO-NE fleet of assets. These increases were partially offset by a decrease of $11.1 million attributable to lower generation of 652,607 MWh and a decrease of $2.2 million due to higher plant heat rates.
The PJM region energy margin revenue increased by $85.3 million for the six months ended June 30, 2014 compared to the six months ended June 30, 2013, primarily resulting from a $74.5 million increase due to our acquisition of Kincaid on August 29, 2013 and our acquisition of Richland and Stryker on December 18, 2013, as well as an $11.1 million increase due to higher spark spreads benefitting our Liberty facility partially offset by a decrease of $0.4 million attributable to lower generation of 26,275 MWh
Net hedge settlements
The ISO-NE region net hedge settlements decreased by $50.7 million for the six months ended June 30, 2014 compared to the six months ended June 30, 2013. This decrease primarily relates to negative net hedge settlements at Brayton Point of $63.9 million partially offset by $14.8 million associated with the Dighton facility’s heat rate call option hedge which expired on December 31, 2013.
The PJM region net hedge settlements decreased by $35.9 million for the six months ended June 30, 2014 compared to the six months ended June 30, 2013. This decrease primarily relates to negative hedge settlements at Kincaid of $25.9 million as well as $8.0 million lower realized spark spread hedge settlements.
Capacity
The ISO-NE region capacity revenue increased by $30.7 million for the six months ended June 30, 2014 compared to the six months ended June 30, 2013, primarily resulting from a $31.1 million increase due to our acquisition of Brayton Point on August 29, 2013.
The PJM region capacity revenue increased by $18.5 million for the six months ended June 30, 2014 compared to the six months ended June 30, 2013, primarily resulting from an $8.4 million increase due to our acquisition of Kincaid on August 29, 2013, a $3.0 million increase due to our acquisition of Richland and Stryker on December 18, 2013, and a $7.1 million increase attributable to increased capacity revenue at Liberty as a result of increased capacity prices in 2014.
Ancillaries and other revenue
The ISO-NE region ancillaries and other revenue increased by $10.8 million for the six months ended June 30, 2014 compared to the six months ended June 30, 2013, primarily resulting from a $9.8 million increase due to our acquisition of Brayton Point on August 29, 2013, and a $0.9 million increase due to higher regulation revenue.
The PJM region ancillaries and other revenue increased by $2.6 million for the six months ended June 30, 2014 compared to the six months ended June 30, 2013, primarily resulting from a $0.8 million increase due to our acquisition of Kincaid on August 29, 2013, and a $1.8 million increase due to higher reserve revenues in 2014.
Mark-to-market for economic hedging activities
Mark-to-market for economic hedging activities includes net unrealized gains/losses on derivative commodity contract positions being used to economically hedge commodity price risk associated with various commodities such as power, natural gas, fuel oil and coal. While the economic hedges are recognized at fair value within the combined financial statements, the related physical transactions these hedges are intended to mitigate are recognized on a delivered basis using accrual accounting.
Mark-to-market for economic hedging activities for the ISO-NE region increased by $48.9 million for the six months ended June 30, 2014 compared to the six months ended June 30, 2013, resulting from a $20.8 million increase primarily due to hedge positions put in place at Brayton Point to hedge power revenue during the winter period. Additionally, there was a $28.1 million increase due to net unrealized gains/losses on open positions related to other economic hedges and the reversal of net unrealized gains/losses on settled economic hedge positions.
Mark-to-market for economic hedging activities for the PJM region decreased by $13.5 million primarily due to a net decrease in the net unrealized gains/losses on open positions relating to economic hedges.
Operations and maintenance
| | Six Months Ended June 30, 2014 | | Six Months Ended June 30, 2013 | |
(in thousands) | | ISO-NE | | PJM | | Total | | ISO-NE | | PJM | | Total | |
Operations and maintenance. | | $ | 55,890 | | $ | 29,039 | | $ | 84,929 | | $ | 10,371 | | $ | 5,501 | | $ | 15,872 | |
| | | | | | | | | | | | | | | | | | | |
The ISO-NE region operations and maintenance expenses increased by $45.5 million for the six months ended June 30, 2014 compared to the year ended June 30, 2013, primarily resulting from a $43.8 million increase due to our acquisition of Brayton Point.
The PJM region operations and maintenance expenses increased by $23.5 million for the six months ended June 30, 2014 compared to the six months ended June 30, 2013, primarily resulting from a $23.9 million increase due to our acquisitions during 2013, mainly relating to Kincaid.
General and administrative costs
General and administrative costs increased by $5.4 million for the six months ended June 30, 2014 compared to the six months ended June 30, 2013, primarily resulting from a $3.9 million increase in labor costs, and other administrative costs mainly attributed to the 2013 acquisitions. In addition, general and administrative costs increased by $1.4 million associated with preparation costs for a contemplated initial public offering and asset management fees.
Depreciation and amortization
Depreciation and amortization increased by $18.3 million for the six months ended June 30, 2014 compared to the six months ended June 30, 2013, primarily from depreciation expense and asset retirement obligation accretion expense at both Kincaid and Brayton Point, which were acquired in 2013, and from higher capital expenditures and major maintenance costs placed into service in 2013. See note 8 and note 14 of our Unaudited Financial Statements for further details.
Taxes other than income taxes
Taxes other than income taxes decreased by $4.2 million for the six months ended June 30, 2014 compared to the six months ended June 30, 2013 resulting from:
· A $10.3 million decrease associated with Connecticut generator tax recognized for the six months ended June 30, 2013. The Connecticut Generator tax expired September 30, 2013.
· A $5.9 million increase in other taxes, mainly due to property taxes associated with our acquisition of Brayton Point, Kincaid and Richland and Stryker in 2013.
Interest and fees on debt
Interest and fees on debt increased by $6.9 million for the six months ended June 30, 2014 compared to the six months ended June 30, 2013, primarily resulting from an increase in long term debt, deferred amortization costs, interest rate swap settlements and other debt related credit fees associated with the 2013 acquisitions, partially offset by lower negotiated interest rates on our long-term debt. See note 15 of our Unaudited Financial Statements for further details.
Mark-to-market on interest rate derivative contracts
Mark-to-market on interest rate derivative contracts decreased by $(14.9) million for the period ending June 30, 2014 compared to the period ending June 30, 2013. Decreases in mark-to-market primarily resulted from forward interest rates decreasing in 2014 as compared to increases in 2013 as well as greater notional volumes in 2014 (resulting from additional interest rate swaps entered into during the first quarter of 2014).
Equity loss (income) in affiliates
We hold a 49.5% ownership interest in Elwood Energy, LLC, acquired on August 29, 2013. For the six months ended June 30, 2014 we recognized a loss of $1.7 million from this investment. See note 4 of our Unaudited Financial Statements for further details.
Income tax benefit
Our effective income tax rate for the six months ended June 30, 2014 was 38.9% compared to the U.S. federal statutory tax rate of 35%. Our effective tax rate was approximately 36.2% for the six months ended June 30, 2013. The increase in the effective tax rate is due to differences between the periods related to the tax effects of the domestic production activities deduction and state income taxes, net of federal benefit.
Discussion of Combined Results of Operations for the Year Ended December 31, 2013 and 2012
| | Years Ended December 31, | |
| | 2013 | | 2012 | |
| | ISO-NE | | PJM | | ISO-NE | | PJM | |
Total Fleet | | | | | | | | | |
Generation volume (GWh) | | 10,896 | | 5,842 | | 9,715 | | 3,801 | |
Commercial availability | | 94.5 | % | 89.6 | % | 90.3 | % | 89.8 | % |
Equivalent availability factor | | 89.7 | % | 87.4 | % | 85.5 | % | 86.7 | % |
Equivalent forced outage factor | | 4.8 | % | 1.1 | % | 4.9 | % | 0.3 | % |
Natural Gas Fleet | | | | | | | | | |
Starts reliability factor(a) | | 97.5 | % | 97.5 | % | 99.0 | % | 99.0 | % |
Net capacity factor (CCGTs) | | 62.3 | % | 71.1 | % | 62.6 | % | 80.0 | % |
Coal Fleet | | | | | | | | | |
Net capacity factor | | 22.8 | % | 68.1 | % | NA | | NA | |
(a) Contains peakers and gas facilities, excludes coal plants.
Operating statistics are affected by seasonality, economics and major planned maintenance outage schedules as well as unplanned outages and derates. On a quarterly basis, these affects may have significant impacts on operating statistics but over the course of a full year, the statistics more accurately reflect the operations of the plants. In comparing 2013 operating statistics to 2012, the majority of the operating statistics are consistent year over year.
The primary operating statistic differences between 2013 and 2012 relates to lower Net Capacity Factors in PJM in 2013. The decrease in the PJM natural gas fired fleet Net Capacity Factor is mainly due to an unplanned steam turbine maintenance outage at Liberty in 2013. The 2013 performance was adversely affected by issues associated with an October 2012 steam turbine major inspection at Liberty. The unit was improperly re-assembled in 2012 by our third-party vendor causing seal damage and instability, which needed to be repaired during an unplanned 2013 maintenance outage. It was then necessary to remove the steam turbine in February 2014, in conjunction with a planned gas turbine inspection to complete final repairs associated with the non-performance issues in October 2012. Liberty was returned to service in March 2014 after the outage with no further issues. The change in the Net Capacity Factor for the coal facilities is attributed to the acquisition of Brayton Point and Kincaid on August 29, 2013.
| | Years Ended December 31, 2013 | | Years Ended December 31, 2012 | |
(in thousands) | | ISO-NE | | PJM | | Total | | ISO-NE | | PJM | | Total | |
Energy revenues | | $ | 651,782 | | $ | 213,788 | | $ | 865,570 | | $ | 363,411 | | $ | 134,253 | | $ | 497,664 | |
Energy and fuel costs | | 505,314 | | 161,478 | | 666,792 | | 285,232 | | 85,586 | | 370,818 | |
Energy margin | | $ | 146,468 | | $ | 52,310 | | $ | 198,778 | | $ | 78,179 | | $ | 48,667 | | $ | 126,846 | |
Net hedge settlements | | (38,452 | ) | 59 | | (38,393 | ) | (15,481 | ) | 648 | | (14,833 | ) |
Capacity revenues | | 72,670 | | 43,287 | | 115,957 | | 57,611 | | 24,658 | | 82,269 | |
Ancillaries and other revenue | | 6,321 | | 4,331 | | 10,652 | | 2,439 | | 4,194 | | 6,633 | |
Total gross margin(a) | | $ | 187,007 | | $ | 99,987 | | $ | 286,994 | | $ | 122,748 | | $ | 78,167 | | $ | 200,915 | |
| | Change | |
| | Change $
(ISO-NE) | | Change %
(ISO-NE) | | Change $
(PJM) | | Change %
(PJM) | | Change $
(Total) | | Change %
(Total) | |
| | (in thousands) | |
Energy revenue | | 288,371 | | 79.35 | % | 79,535 | | 59.24 | % | 367,906 | | 73.93 | % |
Energy and fuel costs | | 220,082 | | 77.16 | % | 75,892 | | 88.67 | % | 295,974 | | 79.82 | % |
Energy margin | | $ | 68,289 | | 87.35 | % | $ | 3,643 | | 7.49 | % | $ | 71,932 | | 56.71 | % |
Net hedge settlements | | (22,971 | ) | (148.38 | )% | (589 | ) | (90.90 | )% | (23,560 | ) | (158.84 | )% |
Capacity revenues | | 15,059 | | 26.14 | % | 18,629 | | 75.55 | % | 33,688 | | 40.95 | % |
Ancillaries and other revenue | | 3,882 | | 159.16 | % | 137 | | 3.27 | % | 4,019 | | 60.59 | % |
Total gross margin(a) | | $ | 64,259 | | 52.35 | % | $ | 21,820 | | 27.91 | % | $ | 86,079 | | 42.84 | % |
(a) Total gross margin excludes mark-to-market for commodity hedging activities of ($86.4) million and $2.2 million for the year ended 2013 for ISO-NE and PJM, respectively. For the year ended December 31, 2012, mark-to-market for commodity hedging activities was ($15.1) million and $1.2 million for ISO-NE and PJM, respectively. The mark-to-market for commodity hedging activities is a non-cash event to record changes in fair value associated with open commodity hedge transactions.
Energy margin
The ISO-NE region energy margin revenue increased by $68.3 million for the year ended December 31, 2013 compared to the year ended December 31, 2012, primarily resulting from a $38.2 million increase due to our acquisition of Brayton
Point on August 29, 2013, a $35.3 million increase due to higher spark spreads, and a $1.6 million increase attributable to increased generation of 151,218 MWh. These increases were partially offset by a $6.0 million decrease due to higher emission costs, primarily due to the increased cost of RGGI credits and increased generation.
The PJM region energy margin revenue increased by $3.6 million for the year ended December 31, 2013 compared to the year ended December 31, 2012, primarily resulting from a $16.0 million increase due to our acquisition of Kincaid on August 29, 2013 partially offset by a $10.5 million decrease due to lower spark spreads and a $1.7 million decrease as a result of lower generation of 168,514 MWh. These decreases, due to lower spark spreads and generation, were mainly the result of an unplanned maintenance outage occurring in the beginning of 2013 at Liberty.
Net hedge settlements
The ISO-NE region net hedge settlements decreased by $23.0 million for the year ended December 31, 2013 compared to the year ended December 31, 2012, related to increases in spark spreads and dark spreads.
The PJM region net hedge settlements decreased by $0.6 million for the year ended December 31, 2013 compared to the year ended December 31, 2012, primarily resulting from a $0.8 million decrease relating to realized spark spread hedge positions.
Capacity revenues
The ISO-NE region capacity revenue increased by $15.1 million for the year ended December 31, 2013 compared to the year ended December 31, 2012, primarily resulting from a $21.0 million increase due to our acquisition of Brayton Point on August 29, 2013 partially offset by a $6.0 million decrease in capacity revenue as a result of decreased capacity pricing year over year.
The PJM region capacity revenue increased by $18.6 million for the year ended December 31, 2013 compared to the year ended December 31, 2012, primarily resulting from a $3.7 million increase due to our acquisition of Kincaid on August 29, 2013, a $0.1 million increase due to our acquisition of Richland and Stryker on December 18, 2013, and a $14.8 million increase attributable to increased capacity revenue at Liberty as a result of increased capacity pricing year over year.
Ancillaries and other revenue
The ISO-NE region ancillaries and other revenue increased by $3.9 million for the year ended December 31, 2013 compared to the year ended December 31, 2012, primarily resulting from a $2.7 million increase due to our acquisition of Brayton Point on August 29, 2013, and a $1.4 million increase due to higher regulation revenue.
The PJM region ancillaries and other revenue increased by $0.1 million for the year ended December 31, 2013 compared to the year ended December 31, 2012, primarily resulting from a $0.3 million increase due to our acquisition of Kincaid on August 29, 2013.
Mark-to-market for commodity hedging activities
Mark-to-market for commodity hedging activities for the ISO-NE region decreased by $71.3 million for the year ended December 31, 2013 compared to the year ended December 31, 2012, primarily resulting from a $44.3 million decrease primarily due to hedge positions put in place at Brayton Point to hedge power revenue during the winter period. Additionally, there was a $27.0 million decrease due to net unrealized gains/losses on open positions related to other commodity hedges and the reversal of net unrealized gains/losses on settled commodity hedge positions.
Mark-to-market for commodity hedging activities for the PJM region increased by $1.0 million primarily due to a net increase in the net unrealized gains/losses on open positions relating to commodity hedges.
Operations and maintenance
| | Year Ended December 31, 2013 | | Year Ended December 31, 2012 | |
(in thousands) | | ISO-NE | | PJM | | Total | | ISO-NE | | PJM | | Total | |
Operations and maintenance | | $ | 47,264 | | $ | 28,002 | | $ | 75,266 | | $ | 40,992 | | $ | 10,341 | | $ | 51,333 | |
| | | | | | | | | | | | | | | | | | | |
The ISO-NE region operations and maintenance expenses increased by $6.3 million for the year ended December 31, 2013 compared to the year ended December 31, 2012, primarily resulting from a $23.9 million increase due to our acquisition of Brayton Point. This increase was partially offset by an $18.3 million decrease attributable to two plant forced outage events and an unplanned maintenance outage occurring in 2012. While these forced outage events were all
covered under our property and business interruption insurance program, the insurance proceeds relating to these outages were not received and recorded as a credit against operations and maintenance expenses until 2013.
The PJM region operations and maintenance expenses increased by $17.7 million for the year ended December 31, 2013 compared to the year ended December 31, 2012, primarily resulting from an $18.0 million increase due to our acquisitions during 2013, mainly due to Kincaid, and a $1.8 million increase due to an unplanned maintenance outage at Liberty occurring in 2013 described above. While this unplanned maintenance outage was covered under our property and business interruption insurance program (subject to customary deductibles), the insurance proceeds relating to the outage was not received and recorded as a credit against operations and maintenance expenses until 2014. These increases were partially offset by a $1.3 million decrease in costs associated with an energy management agreement at Liberty expiring at the beginning of 2013 and a $0.8 million decrease due to a minor outage occurring in 2012 but not in 2013.
General and administrative costs
General and administrative costs increased by $4.9 million for the year ended December 31, 2013 compared to the year ended December 31, 2012, primarily resulting from a $3.5 million increase in labor costs, due to the addition of full time employees associated with our acquisitions in 2013, and a $1.4 million increase in other administrative costs primarily related to one-time transition costs of integrating our 2013 acquisitions.
Debt refinancing costs
Debt refinancing costs increased by $3.8 million for the year ended December 31, 2013 compared to the year ended December 31, 2012. Debt refinancing costs mainly includes certain debt prepayment, debt re-pricing and other fees. See note 15 of our Audited Financial Statements for further details.
Depreciation and amortization
Depreciation and amortization increased by $12.8 million for the year ended December 31, 2013 compared to the year ended December 31, 2012, primarily resulting from higher capital expenditures and major maintenance costs placed into service in 2013 compared with 2012, as well as depreciation expense and asset retirement obligation accretion expense at both Kincaid and Brayton Point, which were acquired in 2013.
Taxes other than income taxes
Taxes other than income taxes decreased by $6.3 million for the year ended December 31, 2013 compared to the year ended December 31, 2012 resulting from:
· A $4.6 million decrease mainly associated with a full year’s worth of Connecticut generator tax of $20.5 million recognized in 2012, compared to only nine months of $15.9 million recognized in 2013. The Connecticut Generator tax was implemented in July 2011 and expired September 30, 2013.
· A $1.7 million decrease in other taxes, mainly due to a $1.9 million decrease in property taxes associated with our acquisition of Brayton Point, resulting primarily from a property tax settlement of $3.5 million received pertaining to periods prior to our ownership partially offset by Brayton Point property tax costs incurred in 2013 following our acquisition of Brayton Point on August 29, 2013.
Interest and fees on debt
Interest and fees on debt decreased by $1.9 million for the year ended December 31, 2013 compared to the year ended December 31, 2012, primarily resulting from the net effect of lower negotiated interest rates on our long-term debt, amortization of the long-term debt balance, write-off of deferred amortization costs, settlement of interest rate swaps, and other debt related transaction fees, partially offset by the increase in the long-term debt balance. Refer to the table below for detailed breakdown of the reason for the changes in interest expense. See note 15 of our Audited Financial Statements for further details.
| | Years Ended December 31, | |
(in thousands) | | 2013 | | 2012 | | Change | |
Interest on long-term debt facilities | | $ | 57,819 | | $ | 48,768 | | $ | 9,051 | |
Interest on mezzanine facility | | — | | 6,978 | | (6,978 | ) |
Interest on working capital facilities | | 4,921 | | 3,117 | | 1,804 | |
Amortization of deferred financing costs | | 18,050 | | 25,020 | | (6,970 | ) |
Interest rate swap settlements | | 5,884 | | 4,573 | | 1,311 | |
Other fees | | 191 | | 355 | | (164 | ) |
Interest and fees on debt | | $ | 86,865 | | $ | 88,811 | | $ | (1,946 | ) |
Mark-to-market on interest rate derivative contracts
Negative mark-to-market on interest rate derivative contracts favorably decreased by $8.8 million for the year ended December 31, 2013 compared to the year ended December 31, 2012, primarily resulting from an increase in interest rates year over year. See note 12 and note 15 of our Audited Financial Statements for further details.
Other income
For the year ended December 31, 2012, other income mainly represents a gain on investment which was realized when the Refinancing occurred.
Gain on bargain purchase of business
In 2013, we recognized a $ 3.1 million gain on bargain purchase attributable to the acquisition of Brayton Point. The fair value of the assets acquired net of the liabilities assumed in the Brayton Point acquisition exceeded the purchase price due to the fact that the assets were purchased for zero dollars. See note 3 of our Audited Financial Statements for further details.
Equity loss (income) in affiliates
We hold a 49.5% ownership interest in Elwood Energy, LLC, acquired on August 29, 2013. From August 29, 2013 to December 31, 2013, we recognized a loss of $1.2 million from this investment. See note 4 of our Audited Financial Statements for further details.
Income tax benefit
Our effective income tax rate for the year ended December 31, 2013 was 38.5% compared to the U.S. federal statutory tax rate of 35%. Our effective tax rate was approximately 25.0% for the year ended December 31, 2012.
| | Years Ended December 31, | |
| | 2013 | | % of Operating | | 2012 | | % of Operating | | Change | |
| | Amount | | Revenues | | Amount | | Revenues | | Amount | |
Income tax (benefit) expense | | $ | (26,876 | ) | -3 | % | $ | (13,286 | ) | -2 | % | $ | (13,590 | ) |
| | | | | | | | | | | | | | |
Income taxes provide for tax effects of transactions reported in the combined financial statements and consist of income taxes currently due plus deferred income taxes related to temporary differences between the basis of certain financial statement assets and liabilities for income tax reporting purposes. Deferred taxes are determined based on the difference between the financial statement asset or liability balance and the tax basis of assets and liabilities calculated using enacted tax rates in effect in the years in which the differences are expected to reverse. Based upon the weight of available evidence, a valuation allowance is provided if it is more likely than not that some or all of the deferred tax assets will not be realized.
As of December 31, 2013, we had federal net operating losses (“NOLs”) carryforwards of $214.6 million, which are set to begin expiring in 2032. We expect to utilize the entire NOL balance by the December 31, 2015 tax year.
Discussion of Combined Results of Operations for the Year Ended December 31, 2012 and 2011
| | Years Ended December 31, | |
| | 2012 | | 2011 | |
| | ISO-NE | | PJM | | ISO-NE | | PJM | |
Total Fleet | | | | | | | | | |
Generation volume (GWh) | | 9,715 | | 3,801 | | 10,993 | | 955 | |
Commercial availability | | 90.3 | % | 89.8 | % | 94.8 | % | 96.2 | % |
Equivalent availability factor | | 85.5 | % | 86.7 | % | 93.2 | % | 91.0 | % |
Equivalent forced outage factor | | 4.9 | % | 0.3 | % | 1.9 | % | 0.0 | % |
Natrual Gas Fleet | | | | | | | | | |
Start reliability factor(a) | | 99.0 | % | 99.0 | % | 96.0 | % | 100.0 | % |
Net capacity factor (CCGTs) | | 62.6 | % | 80.0 | % | 70.4 | % | 79.9 | % |
(a) Contains peakers and gas facilities, excludes coal plants.
Operating statistics are affected by seasonality, economics and major planned maintenance outage schedules as well as unplanned outages and derates. On a quarterly basis, these affects may have significant impacts on operating statistics but over the course of a full year, the statistics more accurately reflect the operations of the plants. The decrease in ISO-NE generation volume, commercial availability, equivalent availability factor and net capacity factor is due to Dighton MXL upgrade and two plant forced outage events and an unplanned maintenance outage occurring in 2012. The decrease in the PJM natural gas fired fleet Equivalent availability factor and commercial availability is mainly due to an October 2012 steam turbine major inspection at Liberty.
| | Year Ended December 31, 2012 | | Year Ended December 31, 2011 | |
(in thousands) | | ISO-NE | | PJM | | Total | | ISO-NE | | PJM | | Total | |
Energy revenues | | $ | 363,411 | | $ | 134,253 | | $ | 497,664 | | $ | 503,518 | | $ | 32,932 | | $ | 536,450 | |
Energy and fuel costs | | 285,232 | | 85,586 | | 370,818 | | 434,998 | | 26,998 | | 461,996 | |
Energy margin | | $ | 78,179 | | $ | 48,667 | | $ | 126,846 | | $ | 68,520 | | $ | 5,934 | | $ | 74,454 | |
Net hedge settlements | | (15,481 | ) | 648 | | (14,833 | ) | (32,280 | ) | 1,126 | | (31,154 | ) |
Capacity revenues | | 57,611 | | 24,658 | | 82,269 | | 65,363 | | 5,042 | | 70,405 | |
Ancillaries and other revenue | | 2,439 | | 4,194 | | 6,633 | | 3,363 | | 1,338 | | 4,701 | |
Total gross margin(a) | | $ | 122,748 | | $ | 78,167 | | $ | 200,915 | | $ | 104,966 | | $ | 13,440 | | $ | 118,406 | |
| | Change | |
(in thousands) | | Change $ (ISO-NE) | | Change % (ISO-NE) | | Change $ (PJM) | | Change % (PJM) | | Change $ (Total) | | Change % (Total) | |
Energy revenue | | (140,107 | ) | -27.83 | % | 101,321 | | 307.67 | % | (38,786 | ) | -7.23 | % |
Energy and fuel costs | | (149,766 | ) | -34.43 | % | 58,588 | | 217.01 | % | (91,178 | ) | -19.74 | % |
Energy margin | | $ | 9,659 | | 14.10 | % | $ | 42,733 | | 720.14 | % | $ | 52,392 | | 70.37 | % |
Net hedge settlements | | 16,799 | | 52.04 | % | (478 | ) | -42.45 | % | 16,321 | | 52.39 | % |
Capacity revenues | | (7,752 | ) | -11.86 | % | 19,616 | | 389.05 | % | 11,864 | | 16.85 | % |
Ancillaries and other revenue | | (924 | ) | -27.48 | % | 2,856 | | 213.45 | % | 1,932 | | 41.10 | % |
Total gross margin | | $ | 17,782 | | 16.94 | % | $ | 64,727 | | 481.60 | % | $ | 82,509 | | 69.68 | % |
(a) Total gross margin excludes mark-to-market for commodity hedging activities. For the year ended December 31, 2012, mark-to-market for commodity hedging activities was ($15.1) million and $1.2 million for ISO-NE and PJM, respectively. For the year ended December 31, 2011, mark-to-market for commodity hedging activities was ($22.1) million and $3.3 million for ISO-NE and PJM, respectively. The mark-to-market for commodity hedging activities is a non-cash event to record changes in fair value associated with open commodity hedge transactions.
Energy margin
The ISO-NE region energy margin revenue increased by $9.7 million for the year ended December 31, 2012 compared to the year ended December 31, 2011, primarily resulting from a $16.7 million increase due to higher spark spreads and a $1.5 million increase as a result of favorable heat rates experienced at the facilities. These increases were partially offset by a $8.5 million decrease attributable to lower generation of 1,087,079 MWh.
The PJM region energy margin revenue increased by $42.7 million for the year ended December 31, 2012 compared to the year ended December 31, 2011, primarily resulting from a $38.0 million increase due to higher generation of 2,964,200 MWh because we owned Liberty for the full year of 2012 but only for approximately 3 months in 2011. There was also a $4.7 million increase due to higher spark spreads in 2012.
Net hedge settlements
The ISO-NE region net hedge settlements increased by $16.8 million for the year ended December 31, 2012 compared to the year ended December 31, 2011, primarily due to heat rate option hedges in place at the Milford Plant in the winter of 2012 but no such hedges in place for the same period of 2011 as well as lower realized spark spreads in the winter and summer months for the other plants in ISO-NE.
The PJM region net hedge settlements decreased by $0.5 million for the year ended December 31, 2012 compared to the year ended December 31, 2011, primarily resulting from a $0.5 million decrease relating to realized spark spread hedge positions.
Capacity revenues
The ISO-NE region capacity revenue decreased by $7.8 million for the year ended December 31, 2012 compared to the year ended December 31, 2011, primarily resulting from a $11.6 million decrease in capacity revenue as a result of decreased capacity pricing year over year which was partially offset by a $4.7 million increase in capacity revenue as a result of negative peak energy rents during 2011 that were not experienced in 2012.
The PJM region capacity revenue increased by $19.6 million for the year ended December 31, 2012 compared to the year ended December 31, 2011, primarily because we owned Liberty for the full year of 2012 but only for approximately 3 months in 2011.
Ancillaries and other revenue
The ISO-NE region ancillaries and other revenue decreased by $0.9 million for the year ended December 31, 2012 compared to the year ended December 31, 2011, primarily resulting from a $1.1 million decrease due to lower regulation and other revenue partially offset by a $0.2 million increase in forward reserves.
The PJM region ancillaries and other revenue increased by $2.9 million for the year ended December 31, 2012 compared to the year ended December 31, 2011 because we owned Liberty for the full year of 2012 but only for approximately 3 months in 2011.
Mark-to-market for commodity hedging activities
Mark-to-market for commodity hedging activities for the ISO-NE region increased by $6.9 million for the year ended December 31, 2012 compared to the year ended December 31, 2011, primarily resulting from a $6.2 million increase due to lower net unrealized losses on open positions related to commodity hedges and the reversal of net unrealized losses on settled commodity hedge positions.
Mark-to-market for commodity hedging activities for the PJM region decreased by $2.1 million primarily due to a reversal of previously unrealized losses relating to commodity hedges during 2011 not also realized in 2012.
Operations and maintenance
| | Year Ended December 31, 2012 | | Year Ended December 31, 2011 | |
(in thousands) | | ISO-NE | | PJM | | Total | | ISO-NE | | PJM | | Total | |
Operations and maintenance | | $ | 40,992 | | $ | 10,341 | | $ | 51,333 | | $ | 29,676 | | $ | 6,692 | | $ | 36,368 | |
| | | | | | | | | | | | | | | | | | | |
The ISO-NE region operations and maintenance expenses increased by $11.3 million for the year ended December 31, 2012 compared to the year ended December 31, 2011, primarily resulting from two plant forced outage events and an unplanned maintenance outage occurring in 2012. While these forced outage events were all covered under our property and business interruption insurance program, the insurance proceeds relating to these outages were not received and recorded as a credit against operations and maintenance expenses until 2013.
The PJM region operations and maintenance expenses increased by $3.6 million for the year ended December 31, 2012 compared to the year ended December 31, 2011, primarily resulting from a full year of operations of Liberty due to the acquisition of Liberty in October 2011.
General and administrative costs
General and administrative costs increased by $2.8 million for the year ended December 31, 2012 compared to the year ended December 31, 2011, primarily resulting from increased labor costs and operating costs.
Debt refinancing costs
Debt refinancing costs increased by $3.6 million for the year ended December 31, 2012 compared to the year ended December 31, 2011. Debt refinancing costs mainly include certain debt prepayment, debt re-pricing and other fees and there were no such costs in 2011.
Depreciation and amortization
Depreciation and amortization increased by $20.7 million for the year ended December 31, 2012 compared to the year ended December 31, 2011, primarily resulting from higher capital expenditures and major maintenance costs placed into service in 2012 compared with 2011, as well as full year of Liberty’s depreciation expense due to Liberty’s acquisition in October 2011.
Taxes other than income taxes
Taxes other than income taxes increased by $9.4 million for the year ended December 31, 2012 compared to the year ended December 31, 2011 resulting from:
· An $8.7 million increase mainly associated with a full year’s worth of Connecticut generator tax of $20.5 million recognized in 2012, compared to only six months of Connecticut generator tax of $11.8 million recognized in 2011. The Connecticut generator tax was implemented in July 2011 and expired September 30, 2013.
· A $0.7 million increase in other taxes, mainly due to a $0.4 million increase in property taxes associated with Liberty’s full year cost, and $0.3 increase in franchise taxes.
Interest and fees on long-term debt
Interest and fees on long-term debt increased by $52.4 million for the year ended December 31, 2012 compared to the year ended December 31, 2011, primarily resulting from a higher long-term debt balances in 2012 compared to 2011, amortization of deferred financing costs, write-off of deferred amortization costs associated with the refinancing in 2012, settlement of interest rate swaps, and other debt related transaction fees, partially offset by lower negotiated interest rates on our long-term debt balance. Refer to the table below for detailed breakdown of the reason for the changes in interest expense.
| | For the Year Ended December 31, | |
(in thousands) | | 2012 | | 2011 | | Change | |
Interest on long-term debt facilities | | 48,768 | | 24,858 | | (23,910 | ) |
Interest on mezzanine facility | | 6,978 | | 3,273 | | (3,705 | ) |
Interest on working capital facilities | | 3,117 | | 2,160 | | (957 | ) |
Amortization of deferred financing costs | | 25,020 | | 2,289 | | (22,731 | ) |
Interest rate swap settlements | | 4,573 | | 3,684 | | (889 | ) |
Other fees | | 355 | | 156 | | (199 | ) |
| | 88,811 | | 36,420 | | (52,391 | ) |
Mark-to-market on interest rate derivative contracts
Negative mark-to-market on interest rate derivative contracts favorably decreased by $3.1 million for the year ended December 31, 2012 compared to the year ended December 31, 2011, primarily resulting from entering into additional interest rate swap transactions in June 2012 which were transacted at interest rate levels lower than those as of December 31, 2012.
Other income
For the year ended December 31, 2012, other income mainly represents a gain on investment which was realized when the Refinancing occurred.
Income tax benefit
Our effective income tax rate for the year ended December 31, 2012 was 25.0% compared to the U.S. federal statutory tax rate of 35.0%. Our effective tax rate was approximately 36.0% for the year ended December 31, 2011.
| | Years Ended December 31, | |
| | 2012 | | 2011 | | Change | |
| | Amount | | % of Operating
Revenues | | Amount | | % of Operating
Revenues | | Amount | |
Income tax expense (benefit) | | (13,286 | ) | -2 | % | (15,899 | ) | -3 | % | 2,613 | |
Income taxes provide for tax effects of transactions reported in the financial statements and consist of income taxes currently due plus deferred income taxes related to temporary differences between the basis of certain financial statement assets and liabilities for income tax reporting purposes. Deferred taxes are determined based on the difference between the financial statement asset or liability balance and the tax basis of assets and liabilities calculated using enacted tax rates in effect in the years in which the differences are expected to reverse. Based upon the weight of available evidence, a valuation allowance is provided if it is more likely than not that some or all of the deferred tax assets will not be realized.
For the years ended December 31, 2012 and 2011, the Company generated Federal Net Operating Losses (“NOLs”) of approximately $119.0 million and $23.6 million, respectively, and State NOLs of approximately $107.1 million and $25.9 million, respectively. These losses will begin to expire in 2032, however, the Company expects to fully utilize these NOLs. The Company carried back approximately $23.0 million of its 2011 NOLs back to its 2010 tax year.
Under Section 382 of the Internal Revenue Code, or the Code, substantial changes in our ownership may limit the amount of NOLs that could be utilized annually in the future to offset taxable income, if any. Specifically, this limitation may arise in the event of a cumulative change in ownership of our company of more than 50% within a three-year period as determined under the Code, which we refer to as an ownership change. Any such annual limitation may significantly reduce the utilization of these NOLs before they expire.
