HOUSTON--(BUSINESS WIRE)--Dynegy Inc. (NYSE: DYN):
Summary of Second Quarter 2017 Financial Results (in millions):
|
Three Months Ended |
Six Months Ended |
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| 2017 | 2016 | 2017 | 2016 | |||||||||||||||||
| Operating Revenues | $ | 1,164 | $ | 904 | $ | 2,411 | $ | 2,027 | ||||||||||||
| Net Income (loss) | $ | (296 | ) | $ | (803 | ) | $ | 300 | $ | (813 | ) | |||||||||
| Adjusted EBITDA (1) | $ | 240 | $ | 187 | $ | 470 | $ | 438 | ||||||||||||
Reaffirming 2017 Guidance Ranges (in millions):
| Adjusted EBITDA (1) | $1,200 - $1,400 | |||||
| Adjusted Free Cash Flow (1) | $300 - $500 | |||||
Second Quarter Operating Highlights:
- Achieved top decile safety performance across the entire company
- Generated more than 25 million megawatt hours
- Ceased operations at Brayton Point facility on May 31; related inventory financing fully repaid
- Outstanding collateral declined by approximately $85 million during the quarter
- $1.4 billion in liquidity at June 30, 2017; excludes asset sale proceeds of approximately $480 million received in July
Portfolio Transformation:
- Completed sale of Troy and Armstrong facilities; received approximately $480 million in cash proceeds
- Announced sale of Dighton, Lee and Milford (MA) facilities for approximately $300 million
- Completed 43 MW of uprates at Liberty and Milford (CT) averaging $175/kW
- Closed Conesville/Zimmer transaction with AEP
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__________________________________________ |
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| (1) | Adjusted EBITDA and Adjusted Free Cash Flow are non-GAAP financial measures. See “Regulation G Reconciliations” for further details. | |
Dynegy Inc. (NYSE: DYN) reported a net loss of $296 million for the second quarter of 2017, compared to a net loss of $803 million for the second quarter of 2016. Results for the most recent quarter were impacted by positive contributions from assets acquired from ENGIE (ENGIE assets) in February 2017 and a non-cash asset impairment related to certain coal facilities in MISO. Results for the second quarter of 2016 were negatively impacted by a non-cash asset impairment charge related to the retirement of certain generation units last year.
The Company reported consolidated Adjusted EBITDA of $240 million for the 2017 second quarter compared to $187 million for the 2016 second quarter as the positive contribution from the ENGIE assets and higher capacity revenues in the MISO and IPH segments more than offset lower energy margins in PJM.
Net income for the first half of 2017 was $300 million compared to a net loss of $813 million for the first half of 2016. The year-to-date increase was primarily driven by a $329 million deferred tax valuation allowance reversal, a $482 million gain related to the Genco financial restructuring and contributions from the ENGIE assets, while second quarter 2016 results were impacted by the asset impairment noted above.
For the first half of 2017, the Company reported consolidated Adjusted EBITDA of $470 million compared to $438 million for the first half of 2016. The $32 million increase in Adjusted EBITDA was primarily driven by the ENGIE assets. Partially offsetting these improvements were compressed energy margins, particularly in our natural gas fleet, as natural gas prices rose faster than power prices which compressed spark spreads during the period.
“Going into the second quarter, our priorities were to prepare the fleet and workforce for the important summer season, hit our financial targets and increase our liquidity in preparation for the pay down of our 2019 debt maturity later this year. By all measures we had a very successful quarter,” said Robert Flexon, Dynegy President and Chief Executive Officer. “The balance of the year will bring added emphasis on analyzing our operating practices to drive additional efficiencies in preparation for the next generation of our PRIDE improvement plan and reducing our leverage.”
Second Quarter Comparative Results
| Quarter Ended June 30, | |||||||||||||||||
| 2017 | 2016 | ||||||||||||||||
| (in millions) |
Operating |
Adjusted EBITDA (1) |
Operating |
Adjusted EBITDA (1) | |||||||||||||
| PJM | $ | 6 | $ | 168 | $ | 71 | $ | 152 | |||||||||
| NY/NE | (1 | ) | 60 | (5 | ) | 34 | |||||||||||
| ERCOT | (30 | ) | 1 |
- |
- |
||||||||||||
| MISO | (98 | ) | 3 | (729 | ) | 4 | |||||||||||
| IPH | 11 | 47 | 3 | 11 | |||||||||||||
| CAISO | (19 | ) | (1 | ) | 4 | 21 | |||||||||||
| Other | (51 | ) | (38 | ) | (46 | ) | (35 | ) | |||||||||
| Total | $ | (182 | ) | $ | 240 | $ | (702 | ) | $ | 187 | |||||||
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| (1) | Adjusted EBITDA is a non-GAAP financial measure. See “Regulation G Reconciliations” for further details. | |
Segment Review of Results Quarter-over-Quarter
PJM - Operating income for the 2017 second quarter totaled $6 million, compared to operating income of $71 million for the same period of 2016. The decline was primarily due to lower spark spreads, non-cash mark-to-market losses on derivatives and a non-cash loss associated with the Conesville/Zimmer ownership interest exchange. Adjusted EBITDA totaled $168 million during the 2017 second quarter compared to $152 million during the same period in 2016 as contributions from the ENGIE assets and higher energy margins from the coal fleet more than offset weaker spark spreads at the gas fleet.
NY/NE - Operating loss for the 2017 second quarter totaled $1 million, compared to operating loss of $5 million for the same period in 2016. Adjusted EBITDA totaled $60 million during the 2017 second quarter, compared to $34 million during the same period in 2016 with the increase primarily due to the contributions from the ENGIE assets.
ERCOT - Operating loss for the 2017 second quarter totaled $30 million as energy margin of $29 million was offset by $29 million of O&M expenses, $21 million of depreciation expense and $8 million of non-cash mark-to-market losses on derivatives. Adjusted EBITDA was $1 million for the same period. During the second quarter, Dynegy completed multiple planned outages at the ERCOT facilities in order to prepare for the summer cooling season.
MISO - Operating loss for the 2017 second quarter totaled $98 million, compared to an operating loss of $729 million for the same period in 2016. Previous year results were impacted by asset impairments, however 2017 results benefited from lower O&M costs and non-cash mark-to-market income on derivatives. Adjusted EBITDA totaled $3 million during the 2017 second quarter compared to $4 million during the same period in 2016.
IPH - Operating income for the 2017 second quarter totaled $11 million, compared to $3 million for the same period of 2016 due to higher capacity revenues. Adjusted EBITDA totaled $47 million during the 2017 second quarter compared to $11 million during the same period in 2016 due to higher capacity revenues and the receipt of contingent proceeds in 2017 related to the 2013 Ameren acquisition.
CAISO - Operating loss for the 2017 second quarter totaled $19 million, compared to operating income of $4 million for the same period in 2016. The decrease is due to lower capacity revenues and higher depreciation. Adjusted EBITDA loss totaled $1 million during the 2017 second quarter compared to Adjusted EBITDA of $21 million during the same period in 2016 due to lower capacity revenues and a one-time supplier settlement in 2016.
Liquidity
As of June 30, 2017, Dynegy’s total available liquidity was $1.4 billion as reflected in the table below.
| (amounts in millions) | |||||
| Revolving facilities and LC capacity (1) | $ | 1,650 | |||
| Less: | |||||
| Outstanding revolvers | (300 | ) | |||
| Outstanding LCs | (413 | ) | |||
| Revolving facilities and LC availability | 937 | ||||
| Cash and cash equivalents | 447 | ||||
| Total available liquidity | $ | 1,384 | |||
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__________________________________________ |
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| (1) | Dynegy Inc. includes $1.5 billion in senior secured revolving credit facilities and $105 million related to LCs. | |
During the second quarter, outstanding collateral declined by approximately $85 million primarily due to the AEP transaction closing and the subsequent return of a $58 million letter of credit, as well as other collateral efficiency initiatives. Additionally, upon retirement of the Brayton Point Power Station, the associated inventory financing was fully paid and extinguished.
Consolidated Cash Flow
Cash provided by operations totaled $230 million for the first half of 2017. During the period, our power generation facilities and retail operations provided cash of $523 million. Corporate activities, primarily related to general and administrative, interest and acquisition-related expenses, as well as other working capital changes, used cash of $293 million during the period.
Cash used in investing activities totaled $3.3 billion during the first half of 2017 as Dynegy used $3,263 million at the ENGIE acquisition closing and invested $86 million in capital expenditures.
Cash used in financing activities totaled $275 million for the first half of 2017.
2017 Guidance
Dynegy’s full-year 2017 Adjusted EBITDA guidance range remains unchanged at $1,200-1,400 million. The Company’s Adjusted free cash flow range is affirmed at $300-$500 million. The Company is maintaining these guidance ranges despite foregoing approximately $55 million in forecasted Adjusted EBITDA from the later than expected closing of the ENGIE acquisition and the mid-year sale of the Troy and Armstrong facilities which were included for the full 12 months guidance target when originally issued.
Retail Growth
Dynegy’s business has grown to serve approximately 1.2 million residential and commercial accounts. The retail business expanded to New England this summer with its municipal aggregation contracts in the greater Boston area. The Company now provides electricity to more than 550 communities in Illinois, Massachusetts and Ohio.
Safety
Dynegy’s safety performance has reached the top decile for the industry. Both coal and gas facilities are focused on intensive safety initiatives helping to drive safety culture: second quarter 2017 saw safety performance improved with 40% fewer injuries overall compared to 2016. Dynegy expects that all its plants will complete the Voluntary Protection Program (VPP) certification, a rigorous evaluation process conducted by the Occupational Safety and Health Administration, within the next three years. The Lake Road plant received its VPP certification renewal during the second quarter.
Asset Portfolio Updates
PJM and ISO-NE Asset Sales
On July 10, Dynegy reached agreements to sell three generating assets for approximately $300 million.
Lee Energy Facility, a 625 MW (summer capacity rating) gas-fueled peaking asset in the PJM ComEd region will be sold to an affiliate of Rockland Capital for $180 million in cash, and the sale will enable the company to avoid significant incremental capital investments necessary to convert the plant to dual fuel status in order to meet PJM capacity performance obligations.
Dynegy also signed a purchase and sale agreement with Starwood Energy Group Global to sell two intermediate gas-fueled plants located in Dighton and Milford, Massachusetts for $119 million in cash. The Dighton and Milford sale fulfills the mitigation plan approved by the Federal Energy Regulatory Commission (FERC) regarding the Company’s purchase of ENGIE’s US-based asset portfolio.
On July 11, Dynegy completed the sale of two peaking units, Troy and Armstrong Energy Facilities, and received approximately $480 million in cash proceeds.
In total, these asset sales will provide approximately $780 million in proceeds which will be used for debt reduction.
AEP Conesville/Zimmer Transaction Complete
On May 9, Dynegy finalized the sale of its 40% ownership interest (312 MW) in Conesville Power Station to AEP and acquired AEP’s 25.4% ownership interest (330 MW) in Zimmer Power Station. No cash was exchanged, no additional debt incurred and AEP returned $58 million in letters of credit previously posted by Dynegy.
As a result, Dynegy owns 71.9% (971 MW) and continues to operate Zimmer. Dynegy no longer has an ownership interest in the AEP-operated Conesville.
AES Miami Fort/Zimmer Ownership Consolidation Update
On April 21, Dynegy reached agreement to purchase AES’ 28.1% ownership interest in Zimmer and 36% in Miami Fort stations, totaling approximately 740 MW of generating capacity, for $50 million, subject to certain adjustments. The transaction close is pending FERC approval, anticipated to come by year end.
Uprate Program Developments
We completed 43 MW of low-cost uprates at Liberty and Milford (CT) averaging $175/kW, bringing our uprate total to 702 MW over the past three years.
PRIDE and ENGIE Synergies Update
Dynegy’s PRIDE Energized (Producing Results through Innovation by Dynegy Employees) program is on track to meet or exceed its 2017 target of $65 million in EBITDA by the end of the fourth quarter. Through its PRIDE program, Dynegy has already exceeded its three-year goal of $400 million in balance sheet improvements with $422 million in improvements accomplished in 2016. Dynegy has identified more than $100 million of incremental balance sheet opportunities that will result in more than $500 million in PRIDE improvements secured over the course of 2016 and 2017.
Dynegy has completed the ENGIE integration and achieved the expected $120 million in synergies. Any future opportunities related to the ENGIE assets will be incorporated in the PRIDE program for which we expect to provide enhanced targets later this year.
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. The Company will answer questions about its 2017 second quarter financial results during an investor conference call and webcast tomorrow, August 4, 2017 at 9 am ET/8 am CT. Participants may access the webcast from the Company’s website.
About Dynegy
At Dynegy, we generate more than just power for our customers. We are committed to being a leader in the electricity sector. Throughout the Northeast, Mid-Atlantic, Midwest and Texas, Dynegy operates power generating facilities capable of producing more than 28,000 megawatts of electricity—or enough energy to power about 22 million American homes. We’re proud of what we do, but it’s about much more than just output. We’re always striving to generate power safely and responsibly for our wholesale and retail electricity customers who depend on that energy to grow and thrive.
Forward-Looking Statement
This news release contains statements reflecting assumptions, expectations, projections, intentions or beliefs about future events that are intended as “forward-looking statements,” particularly those statements concerning Dynegy’s beliefs and expectations regarding sale of the Lee, Dighton and Milford (MA) facilities; execution of its PRIDE Energized target in balance sheet and operating improvements, including beliefs regarding the next generation of PRIDE; broadening the retail platform; achievement of OSHAs VPP certification within the next three years; the execution and timing of debt repayments and various delevering strategies; anticipated FERC approval, closing and ownership consolidation of Zimmer and Miami Fort units; anticipated earnings and cash flows and Dynegy’s 2017 Adjusted EBITDA and Adjusted 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 2016 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) beliefs and assumptions about weather and general economic conditions; (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 power market prices, if any; (iii) beliefs and assumptions about market competition, generation capacity, and regional supply and demand characteristics of the wholesale and retail power markets, including the anticipation of plant retirements and higher market pricing over the longer term; (iv) sufficiency of, access to, and costs associated with coal, fuel oil, and natural gas inventories and transportation thereof; (v) the effects of, or changes to the power and capacity procurement processes in the markets in which we operate; (vi) expectations regarding, or impacts of, 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 that we are, or could become, subject to, which could increase our costs, result in an impairment of our assets, cause us to limit or terminate the operation of certain of our facilities, or otherwise have a negative financial effect; (vii) beliefs about the outcome of legal, administrative, legislative, and regulatory matters, including any impacts from the change in administration to these matters; (viii) projected operating or financial results, including anticipated cash flows from operations, revenues, and profitability; (ix) our focus on safety and our ability to operate our assets efficiently so as to capture revenue generating opportunities and operating margins; (x) our ability to mitigate forced outage risk, including managing risk associated with CP in PJM and performance incentives in ISO-NE; (xi) our ability to optimize our assets through targeted investment in cost effective technology enhancements; (xii) the effectiveness of our strategies to capture opportunities presented by changes in commodity prices and to manage our exposure to energy price volatility; (xiii) efforts to secure retail sales and the ability to grow the retail business; (xiv) efforts to identify opportunities to reduce congestion and improve busbar power prices; (xv) ability to mitigate impacts associated with expiring reliability must run “RMR” and/or capacity contracts; (xvi) expectations regarding our compliance with the Credit Agreement, including collateral demands, interest expense, any applicable financial ratios, and other payments; (xvii) expectations regarding performance standards and capital and maintenance expenditures; (xviii) the timing and anticipated benefits to be achieved through our Company-wide improvement programs, including our PRIDE initiative; (xix) expectations regarding strengthening the balance sheet, managing debt maturities and improving Dynegy’s leverage profile; (xx) expectations, timing and benefits of the AES transaction; (xxi) efforts to divest assets and the associated timing of such divestitures, and anticipated use of proceeds from such divestitures; (xxii) anticipated timing, outcome and impact of expected retirements; (xxiii) beliefs about the costs and scope of the ongoing demolition and site remediation efforts; and (xxiv) expectations regarding the synergies, anticipated benefits and FERC mitigation efforts resulting from the ENGIE Acquisition. 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) |
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|
Three Months Ended |
Six Months Ended |
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| 2017 | 2016 | 2017 | 2016 | |||||||||||||||
| Revenues | $ | 1,164 | $ | 904 | $ | 2,411 | $ | 2,027 | ||||||||||
| Cost of sales, excluding depreciation expense | (681 | ) | (493 | ) | (1,438 | ) | (1,038 | ) | ||||||||||
|
Gross margin |
483 | 411 | 973 | 989 | ||||||||||||||
| Operating and maintenance expense | (282 | ) | (256 | ) | (514 | ) | (477 | ) | ||||||||||
| Depreciation expense | (209 | ) | (160 | ) | (409 | ) | (331 | ) | ||||||||||
| Impairments | (99 | ) | (645 | ) | (119 | ) | (645 | ) | ||||||||||
| Loss on sale of assets, net | (29 | ) |
- |
(29 | ) |
- |
||||||||||||
| General and administrative expense | (42 | ) | (39 | ) | (82 | ) | (76 | ) | ||||||||||
| Acquisition and integration costs | (7 | ) | 3 | (52 | ) | (1 | ) | |||||||||||
| Other | 3 | (16 | ) | 1 | (16 | ) | ||||||||||||
| Operating loss | (182 | ) | (702 | ) | (231 | ) | (557 | ) | ||||||||||
| Bankruptcy reorganization items | (1 | ) |
- |
482 |
- |
|||||||||||||
| Earnings from unconsolidated investments | 1 | 1 |
- |
3 | ||||||||||||||
| Interest expense | (159 | ) | (141 | ) | (326 | ) | (283 | ) | ||||||||||
| Other income and expense, net | 29 | 30 | 46 | 31 | ||||||||||||||
| Loss before income taxes | (312 | ) | (812 | ) | (29 | ) | (806 | ) | ||||||||||
| Income tax benefit (expense) | 16 | 9 | 329 | (7 | ) | |||||||||||||
| Net income (loss) | (296 | ) | (803 | ) | 300 | (813 | ) | |||||||||||
| Less: Net loss attributable to noncontrolling interest |
- |
(2 | ) | (1 | ) | (2 | ) | |||||||||||
| Net income (loss) attributable to Dynegy Inc. | (296 | ) | (801 | ) | 301 | (811 | ) | |||||||||||
| Less: Dividends on preferred stock | 6 | 6 | 11 | 11 | ||||||||||||||
| Net income (loss) attributable to Dynegy Inc. common stockholders | $ | (302 | ) | $ | (807 | ) | $ | 290 | $ | (822 | ) | |||||||
| Earnings (Loss) Per Share: | ||||||||||||||||||
| Basic earnings (loss) per share attributable to Dynegy Inc. common stockholders | $ | (1.96 | ) | $ | (6.73 | ) | $ | 1.91 | $ | (6.97 | ) | |||||||
| Diluted earnings (loss) per share attributable to Dynegy Inc. common stockholders | $ | (1.96 | ) | $ | (6.73 | ) | $ | 1.76 | $ | (6.97 | ) | |||||||
| Basic shares outstanding | 154 | 120 | 152 | 118 | ||||||||||||||
| Diluted shares outstanding | 154 | 120 | 171 | 118 | ||||||||||||||
The following table reflects significant components of our weighted average shares outstanding used in the basic and diluted loss per share calculations for the three and six months ended June 30, 2017 and 2016:
|
Three Months Ended |
Six Months Ended |
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| (in millions) | 2017 | 2016 | 2017 | 2016 | |||||||||
| Shares outstanding at the beginning of the period (1) | 154 | 117 | 140 | 117 | |||||||||
| Weighted-average shares outstanding during the period of: | |||||||||||||
| Shares issued under long-term compensation plans |
- |
- |
1 |
- |
|||||||||
| Shares issued under the PIPE Transaction |
- |
- |
11 |
- |
|||||||||
| Prepaid stock purchase contract (TEUs) (1) |
- |
3 |
- |
1 | |||||||||
| Basic weighted-average shares outstanding | 154 | 120 | 152 | 118 | |||||||||
| Dilution from potentially dilutive shares (2) |
- |
- |
19 |
- |
|||||||||
| Diluted weighted-average shares outstanding (3) | 154 | 120 | 171 | 118 | |||||||||
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| (1) |
The minimum settlement amount of the TEUs, or 23,092,460 shares, is considered to be outstanding since the issuance date of June 21, 2016, and is included in the computation of basic earnings (loss) per share for the three and six months ended June 30, 2017 and 2016. |
|
| (2) | Shares included in the computation of diluted earnings (loss) per share for the six months ended June 30, 2017 primarily consist of approximately 5.4 million shares related to our TEUs and 12.9 million shares related to our mandatory convertible preferred stock. | |
| (3) | 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 the three months ended June 30, 2017 and three and six months ended June 30, 2016. | |
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DYNEGY INC. OPERATING DATA |
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The following table provides summary financial data regarding our PJM, NY/NE, ERCOT, MISO, IPH and CAISO segment results of operations for the three and six months ended June 30, 2017 and 2016, respectively. |
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|
Three Months Ended |
Six Months Ended |
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| 2017 | 2016 | 2017 | 2016 | |||||||||||||||
| PJM | ||||||||||||||||||
| Million Megawatt Hours Generated (1) | 10.9 | 11.2 | 24.3 | 24.2 | ||||||||||||||
| IMA (1)(2): | ||||||||||||||||||
| Combined Cycle Facilities | 87 | % | 98 | % | 88 | % | 98 | % | ||||||||||
| Coal-Fueled Facilities | 70 | % | 79 | % | 68 | % | 78 | % | ||||||||||
| Average Capacity Factor (1)(3): | ||||||||||||||||||
| Combined Cycle Facilities | 51 | % | 62 | % | 59 | % | 72 | % | ||||||||||
| Coal-Fueled Facilities | 50 | % | 46 | % | 55 | % | 44 | % | ||||||||||
| CDDs (4) | 349 | 331 | 350 | 334 | ||||||||||||||
| HDDs (4) | 411 | 589 | 2,636 | 3,038 | ||||||||||||||
| Average Market On-Peak Spark Spreads ($/MWh) (5): | ||||||||||||||||||
| PJM West | $ | 15.76 | $ | 21.15 | $ | 13.57 | $ | 19.94 | ||||||||||
| AD Hub | $ | 16.56 | $ | 27.53 | $ | 14.59 | $ | 29.68 | ||||||||||
| Average Market On-Peak Power Prices ($/MWh) (6): | ||||||||||||||||||
| PJM West | $ | 33.24 | $ | 32.07 | $ | 32.88 | $ | 31.78 | ||||||||||
| AD Hub | $ | 33.59 | $ | 30.43 | $ | 32.49 | $ | 29.61 | ||||||||||
| Average natural gas price—TetcoM3 ($/MMBtu) (7) | $ | 2.50 | $ | 1.55 | $ | 2.76 | $ | 1.69 | ||||||||||
| NY/NE | ||||||||||||||||||
| Million Megawatt Hours Generated (1) | 4.2 | 3.8 | 8.9 | 7.7 | ||||||||||||||
| IMA for Combined Cycle Facilities (1)(2) | 96 | % | 95 | % | 97 | % | 92 | % | ||||||||||
| Average Capacity Factor for Combined Cycle Facilities (1)(3) | 37 | % | 46 | % | 37 | % | 43 | % | ||||||||||
| CDDs (4) | 202 | 150 | 202 | 150 | ||||||||||||||
| HDDs (4) | 780 | 839 | 3,552 | 3,558 | ||||||||||||||
| Average Market On-Peak Spark Spreads ($/MWh) (5): | ||||||||||||||||||
| New York—Zone C | $ | 9.63 | $ | 13.73 | $ | 10.69 | $ | 13.04 | ||||||||||
| Mass Hub | $ | 12.07 | $ | 11.02 | $ | 9.35 | $ | 10.92 | ||||||||||
| Average Market On-Peak Power Prices ($/MWh) (6): | ||||||||||||||||||
| New York—Zone C | $ | 26.67 | $ | 24.09 | $ | 28.59 | $ | 22.71 | ||||||||||
| Mass Hub | $ | 32.19 | $ | 28.17 | $ | 34.98 | $ | 31.01 | ||||||||||
| Average natural gas price—Algonquin Citygates ($/MMBtu) (7) | $ | 2.87 | $ | 2.44 | $ | 3.66 | $ | 2.87 | ||||||||||
| ERCOT | ||||||||||||||||||
| Million Megawatt Hours Generated (1) | 3.2 |
- |
3.8 |
- |
||||||||||||||
| IMA (1)(2): | ||||||||||||||||||
| Combined-Cycle Facilities | 91 | % |
- |
% | 93 | % |
- |
% | ||||||||||
| Coal-Fueled Facility | 100 | % |
- |
% | 98 | % |
- |
% | ||||||||||
| Average Capacity Factor (1)(3): | ||||||||||||||||||
| Combined-Cycle Facilities | 26 | % |
- |
% | 20 | % |
- |
% | ||||||||||
| Coal-Fueled Facility | 81 | % |
- |
% | 56 | % |
- |
% | ||||||||||
| CDDs (4) | 1,070 | 982 | 1,337 | 1,102 | ||||||||||||||
| HDDs (4) | 17 | 30 | 511 | 788 | ||||||||||||||
| Average Market On-Peak Spark Spreads ($/MWh) (5): | ||||||||||||||||||
| ERCOT North | $ | 7.71 | $ | 10.64 | $ | 5.91 | $ | 8.64 | ||||||||||
| Average Market On-Peak Power Prices ($/MWh) (6): | ||||||||||||||||||
| ERCOT North | $ | 26.76 | $ | 24.29 | $ | 25.15 | $ | 21.95 | ||||||||||
| Average natural gas price—Waha Hub ($/MMBtu) (7) | $ | 2.72 | $ | 1.95 | $ | 2.75 | $ | 1.90 | ||||||||||
| MISO | ||||||||||||||||||
| Million Megawatt Hours Generated | 2.7 | 3.6 | 5.4 | 7.0 | ||||||||||||||
| IMA for Coal-Fueled Facilities (2) | 84 | % | 86 | % | 87 | % | 87 | % | ||||||||||
| Average Capacity Factor for Coal-Fueled Facilities (3) | 65 | % | 59 | % | 65 | % | 54 | % | ||||||||||
| CDDs (4) | 420 | 472 | 476 | 500 | ||||||||||||||
| HDDs (4) | 459 | 535 | 2,662 | 2,959 | ||||||||||||||
| Average Market On-Peak Power Prices ($/MWh) (6): | ||||||||||||||||||
| Indiana (Indy Hub) | $ | 35.03 | $ | 31.14 | $ | 33.84 | $ | 28.38 | ||||||||||
| Commonwealth Edison (NI Hub) | $ | 33.16 | $ | 28.87 | $ | 31.71 | $ | 28.11 | ||||||||||
| IPH | ||||||||||||||||||
| Million Megawatt Hours Generated | 4.2 | 3.3 | 8.0 | 6.6 | ||||||||||||||
| IMA for IPH Facilities (2) | 88 | % | 91 | % | 87 | % | 89 | % | ||||||||||
| Average Capacity Factor for IPH Facilities (3) | 58 | % | 38 | % | 55 | % | 38 | % | ||||||||||
| CDDs (4) | 420 | 472 | 476 | 500 | ||||||||||||||
| HDDs (4) | 459 | 535 | 2,662 | 2,959 | ||||||||||||||
| Average Market On-Peak Power Prices ($/MWh) ($/MWh) (6): | ||||||||||||||||||
| Indiana (Indy Hub) | $ | 35.03 | $ | 31.14 | $ | 33.84 | $ | 28.38 | ||||||||||
| Commonwealth Edison (NI Hub) | $ | 33.16 | $ | 28.87 | $ | 31.71 | $ | 28.11 | ||||||||||
| CAISO | ||||||||||||||||||
| Million Megawatt Hours Generated | 0.2 | 0.8 | 0.5 | 1.4 | ||||||||||||||
| IMA for Combined Cycle Facilities (2) | 78 | % | 99 | % | 85 | % | 99 | % | ||||||||||
| Average Capacity Factor for Combined Cycle Facilities (3) | 11 | % | 32 | % | 12 | % | 31 | % | ||||||||||
| CDDs (4) | 303 | 284 | 328 | 328 | ||||||||||||||
| HDDs (4) | 148 | 122 | 866 | 715 | ||||||||||||||
| Average Market On-Peak Spark Spreads ($/MWh) (5): | ||||||||||||||||||
| North of Path 15 (NP 15) | $ | 9.50 | $ | 10.76 | $ | 8.92 | $ | 10.74 | ||||||||||
| Average natural gas price—PG&E Citygate ($/MMBtu) (7) | $ | 3.27 | $ | 2.17 | $ | 3.31 | $ | 2.18 | ||||||||||
|
__________________________________________ |
||
| (1) | Million Megawatt Hours Generated and Average Capacity Factor include such activity for the full month of February. IMA excludes such activity for our period of ownership in February. | |
| (2) | IMA 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. The calculation excludes certain events outside of management control such as weather related issues. The calculation excludes our Brayton Point facility and CTs. | |
| (3) | Reflects actual production as a percentage of available capacity. The calculation excludes our Brayton Point facility and CTs. | |
| (4) | Reflects CDDs or HDDs for the region based on NOAA data. | |
| (5) | Reflects the simple average of the on-peak spark spreads available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas at a daily cash market price and does not reflect spark spreads available to us. | |
| (6) | Reflects the average of day-ahead settled prices for the periods presented and does not necessarily reflect prices we realized. | |
| (7) | Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us. | |
|
DYNEGY INC. REG G RECONCILIATIONS - ADJUSTED EBITDA THREE MONTHS ENDED JUNE 30, 2017 (UNAUDITED) (IN MILLIONS) |
|||||||||||||||||||||||||||||||||
|
The following table provides summary financial data regarding our Adjusted EBITDA by segment for the three months ended June 30, 2017: |
|||||||||||||||||||||||||||||||||
| Three Months Ended June 30, 2017 | |||||||||||||||||||||||||||||||||
| PJM | NY/NE | ERCOT | MISO | IPH | CAISO | Other | Total | ||||||||||||||||||||||||||
| Net loss | $ | (296 | ) | ||||||||||||||||||||||||||||||
| Plus / (Less): | |||||||||||||||||||||||||||||||||
| Income tax benefit | (16 | ) | |||||||||||||||||||||||||||||||
| Other income and expense, net | (29 | ) | |||||||||||||||||||||||||||||||
| Interest expense | 159 | ||||||||||||||||||||||||||||||||
| Earnings from unconsolidated investments | (1 | ) | |||||||||||||||||||||||||||||||
| Bankruptcy reorganization items | 1 | ||||||||||||||||||||||||||||||||
| Operating income (loss) | $ | 6 | $ | (1 | ) | $ | (30 | ) | $ | (98 | ) | $ | 11 | $ | (19 | ) | $ | (51 | ) | $ | (182 | ) | |||||||||||
| Depreciation and amortization expense | 98 | 59 | 22 | 7 | 13 | 14 | 2 | 215 | |||||||||||||||||||||||||
| Bankruptcy reorganization items |
- |
- |
- |
- |
(1 | ) |
- |
- |
(1 | ) | |||||||||||||||||||||||
| Earnings from unconsolidated investments | 1 |
- |
- |
- |
- |
- |
- |
1 | |||||||||||||||||||||||||
| Other income and expense, net |
- |
- |
- |
- |
25 |
- |
4 | 29 | |||||||||||||||||||||||||
| EBITDA (1) | 105 | 58 | (8 | ) | (91 | ) | 48 | (5 | ) | (45 | ) | 62 | |||||||||||||||||||||
| Plus / (Less): | |||||||||||||||||||||||||||||||||
| Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude noncontrolling interest | (1 | ) |
- |
- |
- |
(1 | ) |
- |
- |
(2 | ) | ||||||||||||||||||||||
| Acquisition, integration and restructuring costs |
- |
- |
- |
- |
- |
- |
6 | 6 | |||||||||||||||||||||||||
| Bankruptcy reorganization items |
- |
- |
- |
- |
1 |
- |
- |
1 | |||||||||||||||||||||||||
| Mark-to-market adjustments, including warrants | 31 | 2 | 8 | (4 | ) |
- |
4 | (3 | ) | 38 | |||||||||||||||||||||||
| Impairments |
- |
- |
- |
99 |
- |
- |
- |
99 | |||||||||||||||||||||||||
| Loss (gain) on sale of assets | 30 |
- |
- |
- |
(1 | ) |
- |
- |
29 | ||||||||||||||||||||||||
| Non-cash compensation expense |
- |
- |
- |
- |
- |
- |
5 | 5 | |||||||||||||||||||||||||
| Other | 3 |
- |
1 | (1 | ) |
- |
- |
(1 | ) | 2 | |||||||||||||||||||||||
| Adjusted EBITDA (1)(2) | $ | 168 | $ | 60 | $ | 1 | $ | 3 | $ | 47 | $ | (1 | ) | $ | (38 | ) | $ | 240 | |||||||||||||||
|
__________________________________________ |
||
| (1) | EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on August 3, 2017, for definitions, utility and uses of such non-GAAP financial measures. A reconciliation of EBITDA to Operating income (loss) is presented above. Management does not allocate G&A, interest expense and income taxes on a segment level and therefore uses Operating income (loss) as the most directly comparable GAAP measure. | |
| (2) | Not adjusted to exclude Wood River’s energy margin and O&M costs. | |
|
DYNEGY INC. REG G RECONCILIATIONS - ADJUSTED EBITDA THREE MONTHS ENDED JUNE 30, 2016 (UNAUDITED) (IN MILLIONS) |
|||||||||||||||||||||||||||||||||
|
The following table provides summary financial data regarding our Adjusted EBITDA by segment for the three months ended June 30, 2016: |
|||||||||||||||||||||||||||||||||
| Three Months Ended June 30, 2016 | |||||||||||||||||||||||||||||||||
| PJM | NY/NE | ERCOT | MISO | IPH | CAISO | Other | Total | ||||||||||||||||||||||||||
| Net loss | $ | (803 | ) | ||||||||||||||||||||||||||||||
| Plus / (Less): | |||||||||||||||||||||||||||||||||
|
Income tax benefit |
(9 | ) | |||||||||||||||||||||||||||||||
| Other income and expense, net | (30 | ) | |||||||||||||||||||||||||||||||
| Interest expense | 141 | ||||||||||||||||||||||||||||||||
| Earnings from unconsolidated investments | (1 | ) | |||||||||||||||||||||||||||||||
| Operating income (loss) | $ | 71 | $ | (5 | ) | $ |
- |
$ | (729 | ) | $ | 3 | $ | 4 | $ | (46 | ) | $ | (702 | ) | |||||||||||||
| Depreciation and amortization expense | 84 | 60 |
- |
9 | 3 | 6 | 2 | 164 | |||||||||||||||||||||||||
| Earnings from unconsolidated investments | 1 |
- |
- |
- |
- |
- |
- |
1 | |||||||||||||||||||||||||
| Other income and expense, net | 6 |
- |
- |
- |
14 | 12 | (2 | ) | 30 | ||||||||||||||||||||||||
| EBITDA (1) | 162 | 55 |
- |
(720 | ) | 20 | 22 | (46 | ) | (507 | ) | ||||||||||||||||||||||
| Plus / (Less): | |||||||||||||||||||||||||||||||||
| Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude noncontrolling interest | 1 |
- |
- |
- |
2 |
- |
- |
3 | |||||||||||||||||||||||||
| Acquisition, integration and restructuring costs |
- |
- |
- |
- |
(8 | ) |
- |
5 | (3 | ) | |||||||||||||||||||||||
| Mark-to-market adjustments, including warrants | (12 | ) | (21 | ) |
- |
65 | (2 | ) | (1 | ) |
- |
29 | |||||||||||||||||||||
| Impairments |
- |
- |
- |
645 |
- |
- |
- |
645 | |||||||||||||||||||||||||
| Non-cash compensation expense | 1 |
- |
- |
- |
- |
- |
4 | 5 | |||||||||||||||||||||||||
| Other (2) |
- |
- |
- |
14 | (1 | ) |
- |
2 | 15 | ||||||||||||||||||||||||
| Adjusted EBITDA (1) | $ | 152 | $ | 34 | $ |
- |
$ | 4 | $ | 11 | $ | 21 | $ | (35 | ) | $ | 187 | ||||||||||||||||
|
__________________________________________ |
||
| (1) | EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on August 3, 2017, for definitions, utility and uses of such non-GAAP financial measures. A reconciliation of EBITDA to Operating income (loss) is presented above. Management does not allocate G&A, interest expense and income taxes on a segment level and therefore uses Operating income (loss) as the most directly comparable GAAP measure. | |
| (2) | Other includes an adjustment to exclude Wood River’s energy margin and O&M costs of $15 million. | |
|
DYNEGY INC. REG G RECONCILIATIONS - ADJUSTED EBITDA SIX MONTHS ENDED JUNE 30, 2017 (UNAUDITED) (IN MILLIONS) |
|||||||||||||||||||||||||||||||||
|
The following table provides summary financial data regarding our Adjusted EBITDA by segment for the six months ended June 30, 2017: |
|||||||||||||||||||||||||||||||||
| Six Months Ended June 30, 2017 | |||||||||||||||||||||||||||||||||
| PJM | NY/NE | ERCOT | MISO | IPH | CAISO | Other | Total | ||||||||||||||||||||||||||
| Net income | $ | 300 | |||||||||||||||||||||||||||||||
| Plus / (Less): | |||||||||||||||||||||||||||||||||
| Income tax benefit | (329 | ) | |||||||||||||||||||||||||||||||
| Other income and expense, net | (46 | ) | |||||||||||||||||||||||||||||||
| Interest expense | 326 | ||||||||||||||||||||||||||||||||
| Bankruptcy reorganization items | (482 | ) | |||||||||||||||||||||||||||||||
| Operating income (loss) | $ | 92 | $ | (42 | ) | $ | (58 | ) | $ | (81 | ) | $ | 29 | $ | (33 | ) | $ | (138 | ) | $ | (231 | ) | |||||||||||
| Depreciation and amortization expense | 198 | 127 | 35 | 15 | 27 | 29 | 4 | 435 | |||||||||||||||||||||||||
| Bankruptcy reorganization items |
- |
- |
- |
- |
482 |
- |
- |
482 | |||||||||||||||||||||||||
| Other income and expense, net |
- |
- |
- |
- |
26 |
- |
20 | 46 | |||||||||||||||||||||||||
| EBITDA (1) | 290 | 85 | (23 | ) | (66 | ) | 564 | (4 | ) | (114 | ) | 732 | |||||||||||||||||||||
| Plus / (Less): | |||||||||||||||||||||||||||||||||
| Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude noncontrolling interest |
- |
- |
- |
- |
(1 | ) |
- |
- |
(1 | ) | |||||||||||||||||||||||
| Acquisition, integration and restructuring costs |
- |
- |
- |
- |
- |
- |
52 | 52 | |||||||||||||||||||||||||
| Bankruptcy reorganization items |
- |
- |
- |
- |
(482 | ) |
- |
- |
(482 | ) | |||||||||||||||||||||||
| Mark-to-market adjustments, including warrants | 16 | 17 | 14 | (19 | ) | (1 | ) |
- |
(15 | ) | 12 | ||||||||||||||||||||||
| Impairments | 20 |
- |
- |
99 |
- |
- |
- |
119 | |||||||||||||||||||||||||
| Loss (gain) on sale of assets | 30 |
- |
- |
- |
(1 | ) |
- |
- |
29 | ||||||||||||||||||||||||
| Non-cash compensation expense |
- |
- |
- |
- |
- |
- |
10 |
10 | |||||||||||||||||||||||||
| Other | 3 |
- |
1 | (1 | ) | (1 | ) |
- |
(3 | ) | (1 | ) | |||||||||||||||||||||
| Adjusted EBITDA (1)(2) | $ | 359 | $ | 102 | $ | (8 | ) | $ | 13 | $ | 78 | $ | (4 | ) | $ | (70 | ) | $ | 470 | ||||||||||||||
|
__________________________________________ |
||
| (1) | EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on August 3, 2017, for definitions, utility and uses of such non-GAAP financial measures. A reconciliation of EBITDA to Operating income (loss) is presented above. Management does not allocate G&A, interest expense and income taxes on a segment level and therefore uses Operating income (loss) as the most directly comparable GAAP measure. | |
| (2) | Not adjusted to exclude Wood River’s energy margin and O&M costs. | |
|
DYNEGY INC. REG G RECONCILIATIONS - ADJUSTED EBITDA SIX MONTHS ENDED JUNE 30, 2016 (UNAUDITED) (IN MILLIONS) |
|||||||||||||||||||||||||||||||||
|
The following table provides summary financial data regarding our Adjusted EBITDA by segment for the six months ended June 30, 2016: |
|||||||||||||||||||||||||||||||||
| Six Months Ended June 30, 2016 | |||||||||||||||||||||||||||||||||
| PJM | NY/NE | ERCOT | MISO | IPH | CAISO | Other | Total | ||||||||||||||||||||||||||
| Net loss | $ | (813 | ) | ||||||||||||||||||||||||||||||
| Plus / (Less): | |||||||||||||||||||||||||||||||||
| Income tax expense | 7 | ||||||||||||||||||||||||||||||||
| Other income and expense, net | (31 | ) | |||||||||||||||||||||||||||||||
| Interest expense | 283 | ||||||||||||||||||||||||||||||||
| Earnings from unconsolidated investments | (3 | ) | |||||||||||||||||||||||||||||||
| Operating income (loss) | $ | 248 | $ | (7 | ) | $ |
- |
$ | (716 | ) | $ | 17 | $ | (10 | ) | $ | (89 | ) | $ | (557 | ) | ||||||||||||
| Depreciation and amortization expense | 167 | 135 |
- |
18 | 13 | 18 | 3 | 354 | |||||||||||||||||||||||||
| Earnings from unconsolidated investments | 3 |
- |
- |
- |
- |
- |
- |
3 | |||||||||||||||||||||||||
| Other income and expense, net | 6 |
- |
- |
- |
14 | 12 | (1 | ) | 31 | ||||||||||||||||||||||||
| EBITDA (1) | 424 | 128 |
- |
(698 | ) | 44 | 20 | (87 | ) | (169 | ) | ||||||||||||||||||||||
| Plus / (Less): | |||||||||||||||||||||||||||||||||
| Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude noncontrolling interest | 4 |
- |
- |
- |
2 |
- |
- |
6 | |||||||||||||||||||||||||
| Acquisition and integration costs |
- |
- |
- |
- |
(8 | ) |
- |
9 | 1 | ||||||||||||||||||||||||
| Bankruptcy reorganization items |
- |
- |
- |
- |
- |
- |
- |
- |
|||||||||||||||||||||||||
| Mark-to-market adjustments, including warrants | (68 | ) | (41 | ) |
- |
37 | (5 | ) | 1 | (1 | ) | (77 | ) | ||||||||||||||||||||
| Impairments |
- |
- |
- |
645 |
- |
- |
- |
645 | |||||||||||||||||||||||||
| Non-cash compensation expense | 1 |
- |
- |
- |
- |
- |
11 | 12 | |||||||||||||||||||||||||
| Other (2) |
- |
- |
- |
19 | (1 | ) |
- |
2 | 20 | ||||||||||||||||||||||||
| Adjusted EBITDA (1) | $ | 361 | $ | 87 | $ |
- |
$ | 3 | $ | 32 | $ | 21 | $ | (66 | ) | $ | 438 | ||||||||||||||||
|
__________________________________________ |
||
| (1) | EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on August 3, 2017, for definitions, utility and uses of such non-GAAP financial measures. A reconciliation of EBITDA to Operating income (loss) is presented above. Management does not allocate G&A, interest expense and income taxes on a segment level and therefore uses Operating income (loss) as the most directly comparable GAAP measure. | |
| (2) | Other includes an adjustment to exclude Wood River’s energy margin and O&M costs of $20 million for the six months ended June 30, 2016. | |
|
DYNEGY INC. REG G RECONCILIATIONS - 2017 GUIDANCE (UNAUDITED) (IN MILLIONS) |
||||||||||
|
The following table provides summary financial data regarding our 2017 Adjusted EBITDA and Adjusted Free Cash Flow guidance: |
||||||||||
| Dynegy Consolidated | ||||||||||
| Low | High | |||||||||
| Net income (1) | $ | 371 | $ | 566 | ||||||
| Plus / (Less): | ||||||||||
| Interest expense | 645 | 655 | ||||||||
| Tax benefit | (320 | ) | (330 | ) | ||||||
| Depreciation and amortization expense | 815 | 835 | ||||||||
| EBITDA (2) | 1,511 | 1,726 | ||||||||
| Plus / (Less): | ||||||||||
| Acquisition, integration and restructuring costs | 50 | 55 | ||||||||
| Bankruptcy reorganization items | (480 | ) | (500 | ) | ||||||
| Impairments | 119 | 119 | ||||||||
| Adjusted EBITDA (2) | $ | 1,200 | $ | 1,400 | ||||||
| Cash interest payments | (600 | ) | (600 | ) | ||||||
| Acquisition, integration and restructuring costs | (50 | ) | (55 | ) | ||||||
| Other cash items | (90 | ) | (90 | ) | ||||||
| Cash Flow from Operations | 460 | 655 | ||||||||
| Maintenance capital expenditures | (200 | ) | (200 | ) | ||||||
| Environmental capital expenditures | (10 | ) | (10 | ) | ||||||
| Acquisition, integration and restructuring costs | 50 | 55 | ||||||||
| Adjusted Free Cash Flow (2) | $ | 300 | $ | 500 | ||||||
|
__________________________________________ |
||
| (1) | For purposes of our 2017 guidance, fair value adjustments related to derivatives and our common stock warrants are assumed to be zero. | |
| (2) | EBITDA, Adjusted EBITDA and Adjusted Free Cash Flow are non-GAAP measures. Please refer to Item 2.02 of our Form 8-K filed on August 3, 2017, for definitions, utility and uses of such non-GAAP financial measures. | |
