DYNEGY INC. - FORM 8-K - EX-99.6

Attached files

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8-K - CURRENT REPORT OF MATERIAL EVENTS OR CORPORATE CHANGES - DYNEGY INC.	a14-21528_18k.htm
EX-23.1 - EX-23.1 - DYNEGY INC.	a14-21528_1ex23d1.htm
EX-23.2 - EX-23.2 - DYNEGY INC.	a14-21528_1ex23d2.htm
EX-99.1 - EX-99.1 - DYNEGY INC.	a14-21528_1ex99d1.htm
EX-99.3 - EX-99.3 - DYNEGY INC.	a14-21528_1ex99d3.htm
EX-99.4 - EX-99.4 - DYNEGY INC.	a14-21528_1ex99d4.htm
EX-99.5 - EX-99.5 - DYNEGY INC.	a14-21528_1ex99d5.htm
EX-99.2 - EX-99.2 - DYNEGY INC.	a14-21528_1ex99d2.htm

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.

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.

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.

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