Exhibit 99.1
April 29, 2015
Eagle Rock Reports First Quarter 2015 Financial Results
HOUSTON - Eagle Rock Energy Partners, L.P. (“Eagle Rock” or the “Partnership”) (NASDAQ: EROC) today announced its unaudited financial results for the three months ended March 31, 2015.
First Quarter 2015 Highlights
| • | Average daily production was 79.7 MMcfe/d, a 5.7% increase over fourth quarter 2014 |
| • | Distributable cash flow of $11.9 million, equivalent to $0.08/unit |
| • | Announced a distribution of $0.07/unit for the first quarter, or $0.28/unit annualized |
| • | Distribution coverage of 1.12x Distributable Cash Flow for the first quarter; expect to be at or above 1.0x coverage for the full year 2015 |
| • | Adjusted EBITDA of $25.5 million for the first quarter, compared to $34.5 million for the fourth quarter 2014, as lower realized prices were partially offset by higher production volumes and lower operating costs |
| • | Total liquidity of $231 million as of March 31, 2015, including the market value of the Regency Energy Partners, L.P. (“Regency”) common units owned by the Partnership |
| • | Leverage ratio of 1.8x as of March 31, 2015 |
| • | Placed additional hedges on ~86% of expected NGL volumes for the remainder of 2015, providing greater cash flow protection |
Joseph A. Mills, the Partnership's Chairman and Chief Executive Officer, stated, "Eagle Rock had a strong first quarter, especially given the tumultuous commodity price environment. We increased our daily production by 6% over fourth quarter 2014 volumes, and we are realizing meaningful reductions to our operating and capital costs while at the same time reducing our leverage to 1.8x LTM EBITDA. We have maintained significant liquidity and protected the distribution with our strong hedge portfolio.”
Mills added, “The Partnership continues to remain very active in its business development efforts, evaluating more than $1 billion worth of MLP-appropriate asset acquisition opportunities year to date. We continue to take a patient approach to acquisitions, and we expect to have an opportunity to utilize our liquidity to make a meaningful accretive acquisition in 2015 that will enable us to achieve greater scale and diversify our asset base while growing distributable cash flow.”
First Quarter 2015 Financial and Operating Results
Significant results from continuing operations for the first quarter of 2015:
| • | Adjusted EBITDA of $25.5 million, compared to $34.5 million for fourth quarter 2014, as lower commodity prices were partially offset by higher production volumes and lower operating costs. |
| • | Distributable Cash Flow of $11.9 million or $0.08/unit, compared to $0.12/unit for fourth quarter 2014. |
| • | Net Loss of $58.7 million, driven by $68.3 million of impairment charges primarily related to the impact of lower commodity prices on the Partnership’s oil and gas reserves, mainly in the Arkoma and Permian areas. |
| • | Participated in 20 gross (3.2 net) wells in the Mid-Continent region, of which 4 gross (2.7 net) were Eagle Rock operated wells. Additionally, conducted 1 gross (1 net) workover. |
| • | Total production was 7.17 Bcfe, compared to 6.94 Bcfe in fourth quarter 2014. Average daily production was 79.7 MMcfe/d, compared to 75.4 MMcfe/d in fourth quarter 2014. |
| • | Oil production decreased 2% quarter over quarter from 357 MBbl to 349 MBbl |
| • | NGL production increased 10% quarter over quarter from 298 MBbl to 327 MBbl |
| • | Natural gas production increased 4% quarter over quarter from 3.01 Bcf to 3.11 Bcf |
| • | The overall increase in production volumes was primarily due to strong production from three completed operated wells in the Golden Trend play; one completed operated, plus a number of non-operated, wells in the prolific horizontal Woodford “SCOOP” play; and other prior period adjustments |
| • | Golden Trend well results: |
| • | McLemore 1-29, which the Partnership operates with an 84% working interest, had an IP30 of 792 boe/d |
| • | 21 Ranch 1-16, which the Partnership operates with a 69% working interest, had an IP30 of 1,797 boe/d |
| • | Brown 1-29, which the Partnership operates with an 89% working interest, had an IP30 of 680 boe/d |
| • | SCOOP well results: |
| • | Linton 1-05-32XH, which the Partnership operates with a 31% working interest, had an IP30 of 1,532 boe/d |
| • | Product revenue of $29.5 million, compared to $43.1 million for fourth quarter 2014, due to lower commodity prices partially offset by higher production volumes. |
| • | Realized commodity derivative gains of $14.4 million, compared to $8.7 million for fourth quarter 2014, due to lower commodity prices. |
| • | Cash distributions of $2.1 million received on the Regency common units held by the Partnership, compared to $4.0 million in fourth quarter 2014, due to the sale of Regency units by the Partnership. |
| • | Operating expenses, including taxes, of $11.5 million, 11% lower than fourth quarter 2014, primarily due to lower service costs and lower severance taxes resulting from decreased sales revenue. |
| • | General and administrative expenses, net of severance payments, (excluding amortization of expenses pursuant to the Long-Term Incentive Plan) were $8.5 million for the first quarter 2015, flat as compared to fourth quarter 2014. |
| • | Operating income decreased to $15.0 million (excluding an impairment charge of $68.3 million) as compared to operating income of $92.5 million for fourth quarter 2014 (excluding an impairment charge of $378.6 million), primarily due to lower commodity prices and a decrease in unrealized gains on commodity derivatives. |
| • | Maintenance capital expenditures of $10.3 million, as compared to $14.6 million spent in the fourth quarter 2014. Maintenance capital requirements in 2015 are expected to be $3.3 million per month, down from $4.5 million per month in 2014, as a result of meaningful reductions to capital costs in the Partnership’s operations. |
Regency Unit Sale
As of April 28, 2015, the Partnership had sold approximately 5.7 million Regency units received as part of the consideration for the Midstream Business Contribution, and proceeds were approximately $140.4 million. These proceeds were used to fund the Partnership's common unit repurchase program, pay down debt and for general corporate purposes. Eagle Rock plans to continue to sell the majority of the approximately 2.5 million remaining Regency common units in the near term in order to further strengthen liquidity.
Capitalization and Liquidity Update
As of March 31, 2015, the Partnership’s total liquidity was $231 million. The Partnership’s borrowing base under its senior secured credit facility totaled $320 million, and based on outstanding borrowings, the Partnership had approximately $158 million of availability under its senior secured credit facility. As of March 31, 2015 the market value of the 3.2 million remaining Regency units held by the Partnership was $72.9 million.
On April 1, 2015, the Partnership’s borrowing base decreased from $320 million to $270 million, as expected, as part of the regularly scheduled semi-annual redetermination by its commercial lenders. The decrease was primarily driven by lower commodity prices. As of April 28, 2015, the Partnership’s total liquidity was approximately $164 million, comprised of approximately $108 million of availability under its senior secured credit facility and approximately 2.5 million Regency units valued at $56 million.
As of March 31, 2015, the Partnership had 150.9 million common units outstanding eligible to receive the distribution, including 1.9 million unvested restricted common units issued under the Partnership’s Amended and Restated Long-Term Incentive Plan. As of April 28, 2015, the Partnership had 150.8 million common units outstanding eligible to receive the distribution, including 1.8 million unvested restricted common units issued under its Amended and Restated Long-Term Incentive Plan.
In order to preserve liquidity for potential acquisition opportunities, the Partnership has not repurchased any of its units since its last update as of February 23, 2015. The common unit repurchase program of up to $100 million is still in effect until March 2016, and Eagle Rock has repurchased 8.6 million units to date for total consideration of $22 million.
Second Quarter and Full Year 2015 Guidance
During the second quarter of 2015, the Partnership plans to spend approximately $21 million on capital expenditures, and expects $10 million to be categorized as maintenance capital expenditures and $11 million to be categorized as growth capital expenditures. Subject to results from the Partnership’s drilling program, the Partnership expects production to average between 76 and 79 MMcfe/d during second quarter 2015.
For full year 2015, the Partnership plans to spend approximately $75 million on capital expenditures, and expects $40 million to be categorized as maintenance capital expenditures and $35 million to be categorized as growth capital expenditures. Subject to results from the Partnership’s drilling program, the Partnership expects production to average between 75 and 78 MMcfe/d for full year 2015. The Partnership currently expects its quarterly General & Administrative expenses, excluding amortization of expenses related to its Long Term Incentive Plan, to average a run rate between $7.3 and $7.7 million per quarter during 2015. The Partnership expects distributable cash flow to be at or above 1.0x coverage for the full year 2015.
Hedging Update
The Partnership employs risk mitigation strategies to protect its cash flows and reduce volatility in cash flows from commodity price fluctuations. One important risk mitigation strategy is the use of commodity price hedging to stabilize cash flows. As of March 31, 2015, the Partnership’s hedge portfolio had an estimated mark-to-market value of approximately $100 million. As of April 29, 2015, the Partnership’s estimated hedge profile is as follows:
Rem 2015E(1) | 2016E | 2017E | 2018E | 2019E | |
| Oil Production Hedged: | |||||
| % Oil Hedged | 85% | 72% | 34% | 30% | 27% |
| Average WTI Strike Price ($/Bbl) | $89.88 | $84.66 | $88.02 | $87.50 | $87.07 |
| Average LLS Strike Price ($/Bbl) | -- | -- | $91.25 | $90.75 | $90.25 |
| Natural Gas and Ethane Production Hedged: | |||||
| % Natural Gas and Ethane Hedged | 77% | 68% | 15% | -- | -- |
| Average Henry Hub Strike Price ($/MMbtu) | $4.07 | $4.25 | $3.34 | -- | -- |
| Natural Gas Liquids Production Hedged: | |||||
| % NGL (>C2) Hedged | 86% | -- | -- | -- | -- |
| Average Propane Strike Price ($/Gal) | $0.564 | -- | -- | -- | -- |
| Average N Butane Strike Price ($/Gal) | $0.672 | -- | -- | -- | -- |
| Average I Butane Strike Price ($/Gal) | $0.675 | -- | -- | -- | -- |
| Average Pentanes Strike Price ($/Gal) | $1.187 | -- | -- | -- | -- |
(1) May 1 - Dec 31, 2015.
Note: Percent-hedged depicted against midpoint of 2015 production guidance (i.e., 76.5 MMcfe/d) held flat for 2015 and (for ease of modeling but not as guidance) for 2016 through 2019.
The Partnership has not entered into any additional commodity hedges since its last hedging update on April 29, 2015. The latest presentation can be accessed by going to www.eaglerockenergy.com: select Investor Relations, then select Presentations.
First Quarter 2015 Conference Call Information
Eagle Rock will hold a conference call to discuss its first quarter 2015 financial and operating results on Thursday, April 30, 2015 at 2:00 p.m. Eastern Time (1:00 p.m. Central Time).
Interested parties may listen to the earnings conference call live over the Internet or via telephone. To listen live over the Internet, participants are advised to log on to the Partnership's web site at www.eaglerockenergy.com and select the “Events & Presentations” sub-tab under the “Investor Relations” tab. To participate by telephone, the call in number is (877) 293-5457, conference ID 19487996. Participants are advised to dial into the call at least 15 minutes prior to the call. An audio replay of the conference call will also be available for thirty days by dialing (855) 859-2056, conference ID 19487996. In addition, a replay of the audio webcast will be available by accessing the Partnership's web site after the call is concluded.
About the Partnership
Eagle Rock is a growth-oriented master limited partnership engaged in (a) the exploitation, development, and production of oil and natural gas properties and (b) ancillary gathering, compressing, treating, processing and marketing services with respect to its production of natural gas, natural gas liquids, condensate and crude oil.
Contact:
Eagle Rock Energy Partners, L.P.
Bob Haines, 281-408-1303
Senior Vice President and Chief Financial Officer
Chad Knips, 281-408-1203
Director, Corporate Finance and Investor Relations
Use of Non-GAAP Financial Measures
This news release and the accompanying schedules include the non-generally accepted accounting principles, or non-GAAP, financial measures of Adjusted EBITDA and Distributable Cash Flow. The accompanying non-GAAP financial measures schedules (after the financial schedules) provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measures calculated and presented in accordance with accounting principles generally accepted in the United States, or GAAP. Non-GAAP financial measures should not be considered alternatives to GAAP measures such as net income (loss), operating income (loss), cash flows from operating activities or any other GAAP measure of liquidity or financial performance.
Eagle Rock defines Adjusted EBITDA as net income (loss) plus or (minus) income tax provision (benefit); interest-net, including gains and losses arising from interest rate risk management instruments that settled during the period and other expense; depreciation, depletion and amortization expense; impairment expense; other operating expense, non-recurring; other non-cash operating and general and administrative expenses, including non-cash compensation related to the Partnership’s equity-based compensation program; mark-to-market (gains) losses on commodity and interest rate risk management related instruments; (gains) losses on discontinued operations; and other (income) expense.
Eagle Rock uses Adjusted EBITDA as a measure of its core profitability to assess the financial performance of its assets. Adjusted EBITDA also is used as a supplemental financial measure by external users of Eagle Rock's financial statements such as investors, commercial banks and research analysts. For example, the Partnership's lenders under its revolving credit facility use a variant of its Adjusted EBITDA in a compliance covenant designed to measure the viability of Eagle Rock and its ability to perform under the terms of the revolving credit facility; Eagle Rock, therefore, uses Adjusted EBITDA to measure its compliance with its revolving credit facility. Eagle Rock believes that investors benefit from having access to the same financial measures that its management uses in evaluating performance. Adjusted EBITDA is useful in determining Eagle Rock's ability to sustain or increase distributions. By excluding unrealized derivative gains (losses), a non-cash, mark-to-market benefit (charge) which represents the change in fair market value of the Partnership's executed derivative instruments and is independent of its assets' performance or cash flow generating ability, Eagle Rock believes Adjusted EBITDA reflects the Partnership's ability to generate cash sufficient to pay interest costs, support its level of indebtedness, make cash distributions to its unitholders and finance its maintenance capital expenditures. Eagle Rock further believes that Adjusted EBITDA also portrays the underlying performance of its operating assets by isolating the performance of its operating assets from the impact of an unrealized, non-cash measure designed to portray the fluctuating inherent value of a financial asset. Similarly, by excluding the impact of non-recurring discontinued operations, Adjusted EBITDA provides users of the Partnership's financial statements a picture of its current assets' cash generation ability, independently from that of assets which are no longer a part of its operations.
Eagle Rock's Adjusted EBITDA definition may not be comparable to Adjusted EBITDA or similarly titled measures of other entities, as other entities may not calculate Adjusted EBITDA in the same manner as Eagle Rock. Eagle Rock has reconciled Adjusted EBITDA to the GAAP financial measure of net income (loss) at the end of this release.
Adjusted EBITDA does not include interest expense, income taxes or depreciation and amortization expense. Because we have borrowed money to finance our operations, interest expense is a necessary element of our costs and our ability to generate net income. Because we use capital assets, depreciation and amortization are also necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net income (loss) and net cash flows provided by operating activities determined under GAAP, as well as Adjusted EBITDA, to evaluate our performance and liquidity. Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flows provided by operating activities or any other measure of financial performance presented in accordance with GAAP.
Distributable Cash Flow is defined as Adjusted EBITDA minus: (i) maintenance capital expenditures; (ii) cash interest expense; (iii) cash income taxes; and (iv) the addition of losses or subtraction of gains relating to other miscellaneous non-cash amounts affecting net income (loss) for the period. Maintenance capital expenditures represent capital expenditures necessary to maintain the Partnership's production. We estimate these amounts based on current projections and expectations, and do not undertake to adjust any historical amounts based on the actual impact of such expenditures on production. As a result, the included amount of maintenance capital expenditures could fail to maintain production if actual performance does not meet the Partnership’s projections and expectations, including, without limitation, on account of: (i) unanticipated mechanical issues; (ii) unanticipated delays; (iii) poorer than expected production performance of the Partnership’s new wells and recompletions; and/or (iv) unanticipated loss of, or higher than anticipated decline in, existing production.
Distributable Cash Flow is a performance metric used by senior management to compare cash flows generated by the Partnership (excluding growth capital expenditures and prior to the establishment of any retained cash reserves by the Board of Directors) to the cash distributions expected to be paid to unitholders. Using this metric, management can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. This financial measure also is important to investors as an indicator of whether the Partnership is generating cash flow at a level that can sustain, or support an increase in, quarterly distribution rates. Actual distributions are set by the Board of Directors.
The GAAP measure most directly comparable to Distributable Cash Flow is net income (loss). Eagle Rock's Distributable Cash Flow definition may not be comparable to Distributable Cash Flow or similarly titled measures of other entities, as other entities may not calculate Distributable Cash Flow (and Adjusted EBITDA, on which it builds) in the same manner as Eagle Rock. Eagle Rock has reconciled Distributable Cash Flow to the GAAP financial measure of net income (loss) at the end of this release.
Forward-Looking Statements
This news release may include "forward-looking statements." All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Partnership expects, believes or anticipates will or may occur in the future are forward-
looking statements and speak only as of the date on which such statement is made. These statements are based on certain assumptions made by the Partnership based on its experience and perception of historical trends, current conditions, expected future developments and other factors it believes are appropriate under the circumstances. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Partnership. These include, but are not limited to, risks related to volatility of commodity prices; drilling and geological / exploration risks; market demand for crude oil, natural gas and natural gas liquids; our ability to make favorable acquisitions; the effectiveness of the Partnership's hedging activities; the availability of local, intrastate and interstate transportation systems and other facilities to transport crude oil, natural gas and natural gas liquids; competition in the oil and gas industry; the Partnership's ability to obtain credit and access the capital markets; general economic conditions; and the effects of government regulations and policies. Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, the Partnership's actual results and plans could differ materially from those implied or expressed by any forward-looking statements. The Partnership assumes no obligation to update any forward-looking statement as of any future date. For a detailed list of the Partnership's risk factors, please consult the Partnership's Form 10-K, filed with the SEC for the year ended December 31, 2014 and the Partnership's Forms 10-Q filed with the SEC for subsequent quarters, including the Form 10-Q to be filed for the quarter ended March 31, 2015, as well as any other public filings and press releases.
Eagle Rock Energy Partners, L.P.
Consolidated Statement of Operations
($ in thousands)
(unaudited)
| Three Months Ended March 31, | Three Months Ended December 31, 2014 | |||||||||
| 2015 | 2014 | |||||||||
| REVENUE: | ||||||||||
| Natural gas, natural gas liquids, oil, condensate and sulfur sales | $ | 29,513 | $ | 55,084 | $ | 43,115 | ||||
| Unrealized commodity derivative gains (losses) | 8,230 | (6,895 | ) | 85,862 | ||||||
| Realized commodity derivative gains (losses) | 14,370 | (3,138 | ) | 8,716 | ||||||
| Other revenue | 9 | 152 | 40 | |||||||
| Total revenue | 52,122 | 45,203 | 137,733 | |||||||
| COSTS AND EXPENSES: | ||||||||||
| Operations and maintenance | 10,082 | 11,498 | 10,558 | |||||||
| Taxes other than income | 1,388 | 3,791 | 2,354 | |||||||
| General and administrative | 10,989 | 13,290 | 9,663 | |||||||
| Impairment | 68,344 | — | 378,587 | |||||||
| Depreciation, depletion and amortization | 14,645 | 20,406 | 22,615 | |||||||
| Total costs and expenses | 105,448 | 48,985 | 423,777 | |||||||
| OPERATING LOSS | (53,326 | ) | (3,782 | ) | (286,044 | ) | ||||
| OTHER (EXPENSE) INCOME: | ||||||||||
| Interest expense, net | (2,318 | ) | (4,754 | ) | (2,357 | ) | ||||
| Realized interest rate derivative (losses) gains | (940 | ) | (1,708 | ) | 140 | |||||
| Unrealized interest rate derivative (losses) gains | (2,126 | ) | 1,418 | (932 | ) | |||||
| Loss on short-term investments | (2,004 | ) | — | (62,028 | ) | |||||
| Other income, net | 2,135 | 1 | 4,211 | |||||||
| Total other (expense) income | (5,253 | ) | (5,043 | ) | (60,966 | ) | ||||
| LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | (58,579 | ) | (8,825 | ) | (347,010 | ) | ||||
| INCOME TAX BENEFIT | (826 | ) | (865 | ) | (2,767 | ) | ||||
| LOSS FROM CONTINUING OPERATIONS | (57,753 | ) | (7,960 | ) | (344,243 | ) | ||||
| DISCONTINUED OPERATIONS, NET OF TAX | (966 | ) | (10,603 | ) | (348 | ) | ||||
| NET LOSS | $ | (58,719 | ) | $ | (18,563 | ) | $ | (344,591 | ) | |
Eagle Rock Energy Partners, L.P.
Consolidated Balance Sheets
($ in thousands)
(unaudited)
| March 31, 2015 | December 31, 2014 | ||||||
| ASSETS | |||||||
| CURRENT ASSETS: | |||||||
| Cash and cash equivalents | $ | 37 | $ | 1,343 | |||
| Short-term investments | 72,924 | 153,448 | |||||
| Accounts receivable | 32,931 | 39,596 | |||||
| Risk management assets | 47,392 | 44,805 | |||||
| Prepayments and other current assets | 11,764 | 9,911 | |||||
| Total current assets | 165,048 | 249,103 | |||||
| PROPERTY, PLANT AND EQUIPMENT — Net | 432,291 | 487,988 | |||||
| INTANGIBLE ASSETS — Net | 3,023 | 3,072 | |||||
| DEFERRED TAX ASSET | 1,805 | 2,315 | |||||
| RISK MANAGEMENT ASSETS | 50,007 | 46,490 | |||||
| OTHER ASSETS | 5,063 | 5,307 | |||||
| TOTAL | $ | 657,237 | $ | 794,275 | |||
| LIABILITIES AND MEMBERS' EQUITY | |||||||
| CURRENT LIABILITIES: | |||||||
| Accounts payable | $ | 38,145 | $ | 49,226 | |||
| Accrued liabilities | 7,575 | 8,053 | |||||
| Taxes payable | 2,212 | 2,246 | |||||
| Total current liabilities | 47,932 | 59,525 | |||||
| LONG-TERM DEBT | 212,762 | 263,343 | |||||
| ASSET RETIREMENT OBLIGATIONS | 47,575 | 47,907 | |||||
| DEFERRED TAX LIABILITY | 28,921 | 30,321 | |||||
| OTHER LONG TERM LIABILITIES | 5,270 | 4,709 | |||||
| MEMBERS' EQUITY | 314,777 | 388,470 | |||||
| TOTAL | $ | 657,237 | $ | 794,275 | |||
Eagle Rock Energy Partners, L.P.
Upstream Operations Information
(unaudited)
| Three Months Ended March 31, | Three Months Ended December 31, 2014 | ||||||||||
| 2015 | 2014 | ||||||||||
| Upstream | |||||||||||
| Production: | |||||||||||
| Oil and condensate (Bbl) | 349,221 | 317,126 | 356,831 | ||||||||
| Gas (Mcf) | 3,110,234 | 2,952,149 | 3,005,606 | ||||||||
| NGLs (Bbl) | 327,481 | 273,673 | 298,160 | ||||||||
| Total Mcfe | 7,170,446 | 6,496,943 | 6,935,552 | ||||||||
| Sulfur (long ton) | 23,847 | 24,461 | 24,483 | ||||||||
| Realized prices, excluding derivatives: | |||||||||||
| Oil and condensate (per Bbl) | $ | 38.17 | $ | 85.56 | $ | 63.05 | |||||
| Gas (Mcf) | $ | 2.76 | $ | 4.95 | $ | 3.87 | |||||
| NGLs (Bbl) | $ | 15.63 | $ | 41.90 | $ | 24.04 | |||||
| Sulfur (long ton) | $ | 104.44 | $ | 77.05 | $ | 74.78 | |||||
| Operating statistics: | |||||||||||
| Operating costs per Mcfe (incl production taxes) (1) | $ | 1.40 | $ | 2.14 | $ | 1.66 | |||||
| Operating costs per Mcfe (excl production taxes) (1) | $ | 1.21 | $ | 1.56 | $ | 1.32 | |||||
| Operating (loss) income per Mcfe (2) | $ | (8.98 | ) | $ | 3.11 | $ | (53.27 | ) | |||
| Drilling program (gross wells): | |||||||||||
| Development wells | 20 | 4 | 8 | ||||||||
| Completions | 20 | 4 | 8 | ||||||||
| Workovers | 1 | 5 | 4 | ||||||||
| Recompletions | — | 1 | 1 | ||||||||
______________________
| (1) | Excludes post-production costs of $1,398 and $1,371 for the three months ended March 31, 2015 and 2014, respectively and $1,388 for the three months ended December 31, 2014. |
| (2) | Excludes general and administrative expenses, commodity risk management activities and depreciation expense related to corporate type assets. |
Non-GAAP Financial Measures
The following tables present a reconciliation of the non-GAAP financial measures of Adjusted EBITDA and Distributable Cash Flow to the GAAP financial measure of net income for each of the periods indicated (in thousands).
Eagle Rock Energy Partners, L.P.
GAAP to Non-GAAP Reconciliations
($ in thousands)
(unaudited)
| Three Months Ended March 31, | Three Months Ended December 31, 2014 | ||||||||||
| 2015 | 2014 | ||||||||||
| Net loss to Adjusted EBITDA | |||||||||||
| Net loss, as reported | $ | (58,719 | ) | $ | (18,563 | ) | $ | (344,591 | ) | ||
| Depreciation, depletion and amortization | 14,645 | 20,406 | 22,615 | ||||||||
| Impairment | 68,344 | — | 378,587 | ||||||||
| (Gain) loss from risk management activities, net | (19,534 | ) | 10,323 | (93,786 | ) | ||||||
| Total commodity derivative settlements | 13,430 | (4,846 | ) | 8,856 | |||||||
| Non-cash mark-to-market of Upstream product imbalances | 126 | (6 | ) | 2 | |||||||
| Restricted units non-cash amortization expense | 1,856 | 2,583 | 1,208 | ||||||||
| Income tax benefit | (826 | ) | (865 | ) | (2,767 | ) | |||||
| Interest - net including realized risk management instruments and other expense | 3,257 | 6,461 | 2,006 | ||||||||
| Discontinued operations | 966 | 10,603 | 348 | ||||||||
| Loss on short-term investments | 2,004 | — | 62,028 | ||||||||
| Adjusted EBITDA | $ | 25,549 | $ | 26,096 | $ | 34,506 | |||||
| Net loss to Distributable Cash Flow | |||||||||||
| Net loss, as reported | $ | (58,719 | ) | $ | (18,563 | ) | $ | (344,591 | ) | ||
| Depreciation, depletion and amortization expense | 14,645 | 20,406 | 22,615 | ||||||||
| Impairment | 68,344 | — | 378,587 | ||||||||
| Gain (loss) from risk management activities, net | (19,534 | ) | 10,323 | (93,786 | ) | ||||||
| Total derivative settlements | 13,430 | (4,846 | ) | 8,856 | |||||||
| Capital expenditures-maintenance related | (10,326 | ) | (15,009 | ) | (14,584 | ) | |||||
| Non-cash mark-to-market of Upstream product imbalances | 126 | (6 | ) | 2 | |||||||
| Restricted units non-cash amortization expense | 1,856 | 2,583 | 1,208 | ||||||||
| Income tax benefit | (826 | ) | (865 | ) | (2,767 | ) | |||||
| Cash income taxes | (98 | ) | — | — | |||||||
| Discontinued operations | 966 | 10,603 | 348 | ||||||||
| Loss on short-term investments | 2,004 | — | 62,028 | ||||||||
| Distributable Cash Flow | $ | 11,868 | $ | 4,626 | $ | 17,916 | |||||
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