HOUSTON--(BUSINESS WIRE)--Dynegy Inc. (NYSE: DYN) reported first quarter 2014 consolidated Adjusted EBITDA of $152 million, compared to $43 million for the first quarter 2013. The $109 million increase in Adjusted EBITDA was primarily due to improved spark spreads in the Gas segment, improved energy prices for the Coal segment and the addition of the IPH segment. The Company’s operating income was $1 million for the first quarter 2014 compared to an operating loss of $115 million for the same period in 2013. The net loss attributable to Dynegy Inc. for the first quarter 2014 was $41 million, compared to a net loss of $142 million for the first quarter 2013.
“Strong operational performance and commercial execution throughout the first quarter allowed us to capitalize on the favorable market conditions which existed during the period,” said Dynegy President and Chief Executive Officer Robert C. Flexon. “In addition, the continuing trend of generation capacity retirements combined with dramatically lower natural gas inventory is driving forward capacity and energy prices higher in several of our key markets. We are seeing a sustained improvement in 2015 and 2016 forward energy prices and we continue to be successful in executing bilateral capacity transactions in MISO at average prices in excess of $2.00 per kw-month. Dynegy is well-positioned to benefit from improving market dynamics.”
First Quarter Comparative Results
| Quarter Ended March 31, 2014 | ||||||||||||||||||||||||
| (in millions) | ||||||||||||||||||||||||
| Coal | IPH | Gas | Other | Total | ||||||||||||||||||||
| Operating income (loss) | $ | 9 | $ | (16 | ) | $ | 34 | $ | (26 | ) | $ | 1 | ||||||||||||
| Plus / (Less): | ||||||||||||||||||||||||
| Depreciation expense | 14 | 8 | 44 | 1 | 67 | |||||||||||||||||||
| Amortization of intangible assets and liabilities, net | (1 | ) | (1 | ) | 18 | - | 16 | |||||||||||||||||
| Other items, net | - | - | - | (6 | ) | (6 | ) | |||||||||||||||||
| EBITDA (1) | 22 | (9 | ) | 96 | (31 | ) | 78 | |||||||||||||||||
| Plus / (Less): | ||||||||||||||||||||||||
| Acquisition and integration costs | - | 6 | - | - | 6 | |||||||||||||||||||
| Mark-to-market loss, net | 19 | 34 | 8 | - | 61 | |||||||||||||||||||
| Change in fair value of common stock warrants | - | - | - | 6 | 6 | |||||||||||||||||||
| Income attributable to noncontrolling interest | - | (4 | ) | - | - | (4 | ) | |||||||||||||||||
| Other | 1 | 3 | - | 1 | 5 | |||||||||||||||||||
| Adjusted EBITDA (1) | $ | 42 | $ | 30 | $ | 104 | $ | (24 | ) | $ | 152 | |||||||||||||
| Quarter Ended March 31, 2013 | ||||||||||||||||||||
| (in millions) | ||||||||||||||||||||
| Coal | Gas | Other | Total | |||||||||||||||||
| Operating loss | $ | (80 | ) | $ | (8 | ) | $ | (27 | ) | $ | (115 | ) | ||||||||
| Plus / (Less): | ||||||||||||||||||||
| Depreciation expense | 13 | 40 | 1 | 54 | ||||||||||||||||
| Amortization of intangible assets and liabilities, net | 31 | 32 | - | 63 | ||||||||||||||||
| Other items, net | - | 1 | - | 1 | ||||||||||||||||
| EBITDA (1) | (36 | ) | 65 | (26 | ) | 3 | ||||||||||||||
| Plus / (Less): | ||||||||||||||||||||
| Acquisition and integration costs | - | - | 3 | 3 | ||||||||||||||||
| Mark-to-market (income) loss, net | 40 | (4 | ) | - | 36 | |||||||||||||||
| Other | - | - | 1 | 1 | ||||||||||||||||
| Adjusted EBITDA (1) | $ | 4 | $ | 61 | $ | (22 | ) | $ | 43 | |||||||||||
| (1) |
EBITDA and Adjusted EBITDA are non-GAAP financial measures and are used by management to evaluate Dynegy’s business on an ongoing basis. Please refer to Item 2.02 of Dynegy’s Form 8-K which is available on the Company’s website: www.dynegy.com and filed on May 7, 2014, for definitions, purposes and uses of such non-GAAP financial measures. A reconciliation of EBITDA to Operating income (loss) is presented above. General and administrative expenses are not allocated to each segment and are included in the Other segment. Management does not allocate interest expense and income taxes on a segment level and therefore uses Operating income (loss) as the most directly comparable GAAP measure. |
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Segment Review of Results Quarter-over-Quarter
Coal – The first quarter 2014 operating income was $9 million, compared to an operating loss of $80 million for the same period in 2013. Adjusted EBITDA totaled $42 million during the first quarter 2014 compared to $4 million during the same period in 2013 primarily due to higher realized prices during first quarter 2014 compared to first quarter 2013.
Gas – The first quarter 2014 operating income was $34 million, compared to an operating loss of $8 million for the same period in 2013. Adjusted EBITDA totaled $104 million during the first quarter 2014 compared to $61 million during the same period in 2013. The quarter-over-quarter increase in Adjusted EBITDA is due to higher generation and spark spreads primarily at Independence and Ontelaunee and higher ancillary services revenues across the Gas fleet, which more than offset a decline in tolling revenues at Moss Landing.
IPH – The first quarter 2014 operating loss was $16 million. Adjusted EBITDA totaled $30 million during the first quarter 2014 as the segment generated 6.7 million megawatt-hours, a meaningful portion of which was hedged through the segment’s retail business and other third parties.
Liquidity
As of March 31, 2014, Dynegy’s total available liquidity was $1,305 million as reflected in the table below.
| March 31, 2014 | ||||||||||||||
| (amounts in millions) | Dynegy Inc. | IPH (1)(2) | Total | |||||||||||
| Revolver capacity | $ | 475 | $ | - | $ | 475 | ||||||||
| Less: Outstanding letters of credit | (166 | ) | - | (166 | ) | |||||||||
| Revolver availability | 309 | - | 309 | |||||||||||
| Cash and cash equivalents | 728 | 268 | 996 | |||||||||||
| Total available liquidity | $ | 1,037 | $ | 268 | $ | 1,305 | ||||||||
| (1) | Includes Cash and cash equivalents of $191 million related to Genco. | |
| (2) | Due to the ring-fenced nature of IPH, cash at the IPH and Genco entities may not be moved out of these entities without meeting certain criteria. However, cash at these entities is available to support current operations of these entities. |
Consolidated Cash Flow
Cash flow provided by operations for the first quarter 2014 was $166 million. During the period, our power generation business provided cash of $151 million, which was partially offset by acquisition and integration costs. Corporate activities used cash of approximately $31 million, which includes interest payments to service debt related to our Credit Agreement and Senior Notes, employee-related expenses and other general and administrative expenses. This use of cash was partially offset by $46 million in positive changes in working capital, net of $38 million of increased collateral postings.
Cash flow used in investing activities totaled $17 million for the quarter entirely for capital expenditures, including $4 million in maintenance capital expenditures, $8 million in environmental capital expenditures and $5 million in capitalized interest.
Cash flow provided by financing activities during the quarter was $4 million.
PRIDE Reloaded
Over the next three years, the Company is targeting $135 million in operating improvements and $165 million in balance sheet efficiencies from its PRIDE (Producing Results through Innovation by Dynegy Employees) Reloaded program. The Company has already identified and is implementing initiatives that are expected to meet its 2014 PRIDE Reloaded EBITDA improvement target of $60 million. The overall goal of the PRIDE Reloaded program remains improving operating performance, cost structure and the balance sheet to drive incremental cash flow benefits.
Recent Developments
Exporting energy and capacity from MISO to PJM for both the Coal Segment and IPH continues to be pursued. In connection with these efforts, IPM recently secured 240 MW of firm transmission into PJM. This incremental transmission capacity, effective for the 2017/2018 planning year, requires no capital investment and brings IPH’s firm import capacity into PJM to 1,140 MW.
The first phase of uprates at Kendall was partially completed during April. This uprate will increase the plant’s capacity by 40 MW and an additional 40 MW of uprates are scheduled for 2016. All 80 MW of this capacity is eligible to participate in the 2017/2018 PJM capacity auction.
Dynegy continues to enter into bilateral capacity transactions in MISO for future planning years at prices averaging more than $2.00 per kw-month.
2014 Guidance
As previously disclosed, Dynegy’s 2014 consolidated Adjusted EBITDA guidance range is $300 million to $350 million, and its consolidated 2014 Free Cash Flow guidance range is $10 million to $60 million. Both guidance ranges are being maintained as the Company heads into the summer season and continues to work with the recently acquired IPH portfolio. Further guidance updates will be made during Dynegy’s second quarter 2014 earnings call.
Investor Conference Call/Webcast
Dynegy’s earnings presentation and management comments on the earnings presentation will be available on the “Investor Relations” section of www.dynegy.com later today. Dynegy will answer questions about its first quarter 2014 financial results during an investor conference call and webcast tomorrow, May 8, 2014 at 9 a.m. ET/8 a.m. CT. Participants may access the webcast from the Company’s website.
ABOUT DYNEGY
Dynegy's subsidiaries produce and sell electric energy, capacity and ancillary services in key U.S. markets. The Dynegy Power, LLC power generation portfolio consists of approximately 6,121 megawatts of primarily natural gas-fired intermediate and peaking power generation facilities. The Dynegy Midwest Generation, LLC portfolio consists of approximately 2,980 megawatts of primarily coal-fired baseload power plants. The Illinois Power Holdings, LLC portfolio consists of approximately 4,062 megawatts of primarily coal-fired baseload power plants. Homefield Energy is a retail electricity provider serving businesses and residents in Illinois.
This press release contains statements reflecting assumptions, expectations, projections, intentions or beliefs about future events that are intended as “forward-looking statements,” particularly those statements concerning drivers for increased capacity and energy prices and Dynegy’s position to benefit such market dynamic; sustained improvements in forward energy prices and bilateral capacity transactions in MISO; execution of its PRIDE reloaded target in balance sheet and operating improvements; anticipated earnings and cash flows and 2014 Adjusted EBITDA and Free Cash Flow guidance. Historically, Dynegy’s performance has deviated, in some cases materially, from its cash flow and earnings guidance. Discussion of risks and uncertainties that could cause actual results to differ materially from current projections, forecasts, estimates and expectations of Dynegy is contained in Dynegy’s filings with the Securities and Exchange Commission (the “SEC”). Specifically, Dynegy makes reference to, and incorporates herein by reference, the section entitled “Risk Factors” in its 2013 Form 10-K and subsequent Form 10-Qs. In addition to the risks and uncertainties set forth in Dynegy’s SEC filings, the forward-looking statements described in this press release could be affected by, among other things, (i) expectations regarding environmental matters, including costs of compliance, availability and adequacy of emission credits and the impact of ongoing proceedings and potential regulations or changes to current regulations, including those relating to climate change, air emissions, cooling water intake structures, coal combustion byproducts and other laws and regulations to which we are, or could become, subject; (ii) beliefs, assumptions and projections regarding the demand for power, generation volumes and commodity pricing, including natural gas prices and the timing of a recovery in natural gas prices, if any; (iii) sufficiency of, access to and costs associated with coal, fuel oil and natural gas inventories and transportation thereof; (iv) beliefs and assumptions about market competition, generation capacity and regional supply and demand characteristics of the wholesale and retail power generation market, including the anticipation of plant retirements and higher market pricing over the longer term; (v) the effects of, or changes to, MISO power procurement process; (vi) the effectiveness of our strategies to capture opportunities presented by changes in commodity prices and to manage our exposure to energy price volatility; (vii) efforts to secure retail sales and the ability to grow the retail business; (viii) efforts to identify opportunities to reduce congestion and improve busbar power prices; (ix) beliefs and assumptions about weather and general economic conditions; (x) projected operating or financial results, including anticipated cash flows from operations, revenues and profitability; (xi) expectations regarding our compliance with the Credit Agreement, including collateral demands, interest expense, any applicable financial ratios and other payments; (xii) our focus on safety and our ability to efficiently operate our assets so as to capture revenue generating opportunities and operating margins; (xiii) beliefs about the costs and scope of the ongoing demolition and site remediation efforts at the South Bay and Vermilion facilities; (xiv) beliefs regarding successful renegotiation of the IBEW Local 1245 collective bargaining agreement; (xv) beliefs regarding redevelopment efforts for the Morro Bay facility; (xvi) beliefs and assumptions regarding approval by the CPUC of the SCE 2016 transaction for Moss Landing Units 6 & 7; (xvii) ability to mitigate impacts associated with expiring RMR and/or capacity contracts; (xviii) beliefs about the outcome of legal, administrative, legislative and regulatory matters; (xix) anticipated benefits and expected synergies resulting from the AER acquisition and beliefs associated with the integration of operations; (xx) lack of comparable financial data due to the application of fresh-start accounting; (xxi) the timing and anticipated benefits to be achieved through our company-wide savings improvement programs, including our PRIDE initiative; and (xxii) expectations regarding performance standards and capital and maintenance expenditures. Any or all of Dynegy’s forward-looking statements may turn out to be wrong. They can be affected by inaccurate assumptions or by known or unknown risks, uncertainties and other factors, many of which are beyond Dynegy’s control.
| DYNEGY INC. | |||||||||||||
| REPORTED UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS | |||||||||||||
| (IN MILLIONS, EXCEPT PER SHARE DATA) | |||||||||||||
|
Three Months |
Three Months |
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| Revenues | $ | 762 | $ 318 | ||||||||||
| Cost of sales | (552 | ) | (284 | ) | |||||||||
| Gross margin | 210 | 34 | |||||||||||
| Operating and maintenance expense | (110 | ) | (71 | ) | |||||||||
| Depreciation expense | (67 | ) | (54 | ) | |||||||||
| Gain on sale of assets | - | 1 | |||||||||||
| General and administrative expense | (26 | ) | (22 | ) | |||||||||
| Acquisition and integration costs | (6 | ) | (3 | ) | |||||||||
| Operating income (loss) | 1 | (115 | ) | ||||||||||
| Interest expense | (30 | ) | (28 | ) | |||||||||
| Other income and expense, net | (6 | ) | 1 | ||||||||||
| Loss before income taxes | (35 | ) | (142 | ) | |||||||||
| Income tax expense | (2 | ) | - | ||||||||||
| Net loss | (37 | ) | (142 | ) | |||||||||
| Less: Net income attributable to the noncontrolling interests | 4 | - | |||||||||||
| Net loss attributable to Dynegy Inc. | $ | (41 | ) | $ (142 | ) | ||||||||
| Loss Per Share: | |||||||||||||
| Basic loss per share attributable to Dynegy Inc. | $ | (0.41 | ) | $ (1.42 | ) | ||||||||
| Diluted loss per share attributable to Dynegy Inc. | $ | (0.41 | ) | $ (1.42 | ) | ||||||||
| Basic shares outstanding | 100 | 100 | |||||||||||
| Diluted shares outstanding | 101 | 100 | |||||||||||
| (1) | For the three months ended March 31, 2014 and 2013, a reconciliation of basic loss per share to diluted loss per share is presented below: | ||||||||||||
| Net loss attributable to Dynegy Inc. for basic and diluted loss per share | $ | (41 | ) | $ | (142 | ) | |||||||
| Basic weighted-average shares | 100 | 100 | |||||||||||
| Effect of dilutive securities (2) | 1 | - | |||||||||||
| Diluted weighted-average shares | 101 | 100 | |||||||||||
| Loss per share attributable to Dynegy Inc. | |||||||||||||
| Basic | $ | (0.41 | ) | $ | (1.42 | ) | |||||||
| Diluted (2) | $ | (0.41 | ) | $ | (1.42 | ) | |||||||
| (2) | Entities with a net loss from continuing operations are prohibited from including potential common shares in the computation of diluted per share amounts. Accordingly, we have utilized the basic shares outstanding amount to calculate both basic and diluted loss per share for all periods presented. | ||||||||||||
| DYNEGY INC. | ||||||||||||||||||||||
| REPORTED SEGMENTED RESULTS OF OPERATIONS | ||||||||||||||||||||||
| THREE MONTHS ENDED MARCH 31, 2014 | ||||||||||||||||||||||
| (UNAUDITED) (IN MILLIONS) | ||||||||||||||||||||||
| The following table provides summary financial data regarding our Adjusted EBITDA by segment for the three months ended March 31, 2014: | ||||||||||||||||||||||
| Three Months Ended March 31, 2014 | ||||||||||||||||||||||
| Coal | IPH | Gas | Other | Total | ||||||||||||||||||
| Net loss attributable to Dynegy Inc. | $ | (41 | ) | |||||||||||||||||||
| Plus / (Less): | ||||||||||||||||||||||
| Income attributable to noncontrolling interest | 4 | |||||||||||||||||||||
| Income tax expense | 2 | |||||||||||||||||||||
| Interest expense | 30 | |||||||||||||||||||||
| Depreciation expense | 67 | |||||||||||||||||||||
| Amortization of intangible assets and liabilities, net | 16 | |||||||||||||||||||||
| EBITDA (1) | $ | 22 | $ | (9 | ) | $ | 96 | $ | (31 | ) | $ | 78 | ||||||||||
| Plus / (Less): | ||||||||||||||||||||||
| Acquisition and integration costs | - | 6 | - | - | 6 | |||||||||||||||||
| Mark-to-market loss, net | 19 | 34 | 8 | - | 61 | |||||||||||||||||
| Change in fair value of common stock warrants | - | - | - | 6 | 6 | |||||||||||||||||
| Income attributable to noncontrolling interest | - | (4 | ) | - | - | (4 | ) | |||||||||||||||
| Other | 1 | 3 | - | 1 | 5 | |||||||||||||||||
| Adjusted EBITDA (1) | $ | 42 | $ | 30 | $ | 104 | $ | (24 | ) | $ | 152 | |||||||||||
| (1) | EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on May 7, 2014, for definitions, utility and uses of such non-GAAP financial measures. A reconciliation of EBITDA to Operating income (loss) is presented below. Management does not allocate interest expense and income taxes on a segment level and therefore uses Operating income (loss) as the most directly comparable GAAP measure. | |||||||||||||||||||||
| Three Months Ended March 31, 2014 | ||||||||||||||||||||||
| Coal | IPH | Gas | Other | Total | ||||||||||||||||||
| Operating income (loss) | $ | 9 | $ | (16 | ) | $ | 34 | $ | (26 | ) | $ | 1 | ||||||||||
| Depreciation expense | 14 | 8 | 44 | 1 | 67 | |||||||||||||||||
| Amortization of intangible assets and liabilities, net | (1 | ) | (1 | ) | 18 | - | 16 | |||||||||||||||
| Other items, net | - | - | - | (6 | ) | (6 | ) | |||||||||||||||
| EBITDA | $ | 22 | $ | (9 | ) | $ | 96 | $ | (31 | ) | $ | 78 | ||||||||||
| DYNEGY INC. | ||||||||||||||||||
| REPORTED SEGMENTED RESULTS OF OPERATIONS | ||||||||||||||||||
| THREE MONTHS ENDED MARCH 31, 2013 | ||||||||||||||||||
| (UNAUDITED) (IN MILLIONS) | ||||||||||||||||||
| The following table provides summary financial data regarding our Adjusted EBITDA by segment for the three months ended March 31, 2013: | ||||||||||||||||||
| Three Months Ended March 31, 2013 | ||||||||||||||||||
| Coal | Gas | Other | Total | |||||||||||||||
| Net loss | $ | (142 | ) | |||||||||||||||
| Plus / (Less): | ||||||||||||||||||
| Interest expense | 28 | |||||||||||||||||
| Depreciation expense | 54 | |||||||||||||||||
| Amortization of intangible assets and liabilities, net | 63 | |||||||||||||||||
| EBITDA (1) | $ | (36 | ) | $ | 65 | $ | (26 | ) | $ | 3 | ||||||||
| Plus / (Less): | ||||||||||||||||||
| Acquisition and integration costs | - | - | 3 | 3 | ||||||||||||||
| Mark-to-market (income) loss, net | 40 | (4 | ) | - | 36 | |||||||||||||
| Other | - | - | 1 | 1 | ||||||||||||||
| Adjusted EBITDA (1) | $ | 4 | $ | 61 | $ | (22 | ) | $ | 43 | |||||||||
| (1) | EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on May 7, 2014, for definitions, utility and uses of such non-GAAP financial measures. A reconciliation of EBITDA to Operating loss is presented below. Management does not allocate interest expense and income taxes on a segment level and therefore uses Operating loss as the most directly comparable GAAP measure. | |||||||||||||||||
| Three Months Ended March 31, 2013 | ||||||||||||||||||
| Coal | Gas | Other | Total | |||||||||||||||
| Operating loss | $ | (80 | ) | $ | (8 | ) | $ | (27 | ) | $ | (115 | ) | ||||||
| Depreciation expense | 13 | 40 | 1 | 54 | ||||||||||||||
| Amortization of intangible assets and liabilities, net | 31 | 32 | - | 63 | ||||||||||||||
| Other items, net | - | 1 | - | 1 | ||||||||||||||
| EBITDA | $ | (36 | ) | $ | 65 | $ | (26 | ) | $ | 3 | ||||||||
|
Regulation G Reconciliation DYNEGY INC. 2014 Guidance (IN MILLIONS) |
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| Dynegy Consolidated | |||||||||||
| Low | High | ||||||||||
| Net Loss | $ | (111 | ) | $ | (83 | ) | |||||
| Plus / (Less): | |||||||||||
| Interest expense | 145 | 145 | |||||||||
| Operating Income | $ | 34 | $ | 62 | |||||||
| Depreciation expense | 225 | 235 | |||||||||
| Amortization of intangible assets and liabilities, net | 40 | 50 | |||||||||
| EBITDA (1) | 299 | 347 | |||||||||
| Plus: | |||||||||||
| Acquisition and integration costs | 1 | 3 | |||||||||
| Adjusted EBITDA (1) | $ | 300 | $ | 350 | |||||||
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(1) |
EBITDA and Adjusted EBITDA are non-GAAP measures. Management does not allocate interest expense and income taxes on a segment level and therefore uses Operating Income (Loss) as the most directly comparable GAAP measure. |
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DYNEGY INC. OPERATING DATA |
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The following table provides summary financial data regarding our Coal, IPH and Gas segment results of operations for the three months ended March 31, 2014 and 2013, respectively. There were no IPH operations during the three months ended March 31, 2013 as IPH operations were acquired on December 2, 2013. |
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Three Months Ended |
Three Months Ended |
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| Coal | ||||||||||
| Million Megawatt Hours Generated (1) | 5.3 | 5.0 | ||||||||
| In Market Availability for Coal-Fired Facilities (2) | 88 | % | 89 | % | ||||||
| Average Quoted Market Power Prices ($/MWh) (3): | ||||||||||
| On-Peak: Indiana (Indy Hub) | $ | 71.51 | $ | 34.15 | ||||||
| Off-Peak: Indiana (Indy Hub) | $ | 42.97 | $ | 26.93 | ||||||
| IPH | ||||||||||
| Million Megawatt Hours Generated (1) | 6.7 | N/A | ||||||||
| In Market Availability for Coal-Fired Facilities (2) | 90 | % | N/A | |||||||
| Average Quoted Market Power Prices ($/MWh) (3): | ||||||||||
| On-Peak: Indiana (Indy Hub) | $ | 71.51 | N/A | |||||||
| Off-Peak: Indiana (Indy Hub) | $ | 42.97 | N/A | |||||||
| Gas | ||||||||||
| Million Megawatt Hours Generated (4) | 4.5 | 4.3 | ||||||||
| In Market Availability for Combined Cycle Facilities (2) | 99 | % | 97 | % | ||||||
| Average Capacity Factor for Combined Cycle Facilities (5) | 47 | % | 45 | % | ||||||
| Average Market On-Peak Spark Spreads ($/MWh) (6): | $ | 29.87 | $ | 13.15 | ||||||
| Average Market Off-Peak Spark Spreads ($/MWh) (6): | $ | (6.31 | ) | $ | 4.25 | |||||
| Average natural gas price - Henry Hub ($/MMBtu) (7) | $ | 5.05 | $ | 3.48 | ||||||
| (1) | Reflects production volumes in million MWh generated. | |
| (2) | In Market Availability is an internal measurement calculation that reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched. This calculation excludes certain events out of management control such as weather-related issues. | |
| (3) | Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized. | |
| (4) | Includes our ownership percentage in the MWh generated by our investment in the Black Mountain power generation facility. | |
| (5) | Reflects actual production as a percentage of available capacity. | |
| (6) | Reflects the average of our on- and off-peak spark spreads at the following facilities: Commonwealth Edison (NI Hub), PJM West, North of Path (NP 15), New York - Zone A and Mass Hub. | |
| (7) | Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us. |
