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| 8-K - FORM 8-K - EAGLE ROCK ENERGY PARTNERS L P | form8-kq42011earningsrelea.htm |
Exhibit 99.1
February 22, 2012
Eagle Rock Reports Fourth Quarter and Year End 2011 Financial Results
HOUSTON - Eagle Rock Energy Partners, L.P. (“Eagle Rock” or the “Partnership”) (NASDAQ: EROC) today announced its unaudited financial results for the full year and three months ended December 31, 2011. Financial highlights with respect to fourth quarter 2011 included the following:
• | Reported Adjusted EBITDA of $61.8 million, down only slightly from the $62.2 million reported for the third quarter of 2011, despite a quarter-over-quarter drop in natural gas prices of approximately 14%. |
• | Reported Distributable Cash Flow of $35.2 million, a decrease of approximately 2% as compared to the $36.1 million reported for the third quarter of 2011. |
• | Announced a quarterly distribution with respect to the fourth quarter of 2011 of $0.21 per common unit, a 5% increase from the $0.20 per common unit paid for the third quarter of 2011. |
• | Reported a Net Loss of $25.6 million, compared to Net Income of $97.4 million for the third quarter of 2011; the decrease was driven primarily by unrealized, non-cash, mark-to-market losses on the Partnership's commodity derivative portfolio. |
Other notable financial and operational activities of the Partnership during the fourth quarter of 2011 included the following:
• | Completed construction of the 30 MMcf/d expansion of the Phoenix-Arrington Ranch Plant (the “Phoenix Plant”) increasing the Phoenix Plant's capacity from 50 MMcf/d to 80 MMcf/d. |
• | Continued construction of the 60 MMcf/d Woodall Plant to be installed in Hemphill County in the Texas Panhandle early in the second quarter of 2012. |
• | Announced the planned installation of the Wheeler Plant (originally designed at 125 MMcf/d but re-sized to 60 MMcf/d in first quarter of 2012) to further increase the Partnership's processing capacity in the Granite Wash play. |
• | Announced an increase in the upstream component of the Partnership's borrowing base from $353 million to $375 million by its commercial lenders as part of the Partnership's regularly scheduled semi-annual redetermination. |
• | Conducted a seven day turnaround at the Big Escambia Creek plant and a twelve day turnaround at the Flomaton plant in October. Both plants process the Partnership's upstream production in Southern Alabama; in total, the impact of turnarounds reduced fourth quarter production by an estimated 2.0 MMcf/d and negatively impacted Adjusted EBITDA by approximately $4.4 million. |
• | Received proceeds of $11.5 million from the exercise of 1.9 million warrants on November 15, 2011; the Partnership used the proceeds to repay outstanding borrowings under its revolving credit facility. |
For the full year 2011, Eagle Rock generated $208.2 million of Adjusted EBITDA, an increase of 65% from the $126.0 million reported for the full year 2010. The increase was primarily driven
by the acquisition of the Mid-Continent assets which closed on May 3, 2011.
“In spite of the weak natural gas price environment, we posted another solid quarter driven by our focus on liquids-rich areas,” said Joseph A. Mills, Eagle Rock's Chairman and Chief Executive Officer. “The fourth quarter marked the end of a very active year for Eagle Rock. During 2011, we closed the Mid-Continent upstream acquisition, which was the largest acquisition in the Partnership's history, announced multiple midstream expansions in the Texas Panhandle Granite Wash and increased the distribution per common unit by 40%. As we look forward to 2012, we continue to be excited about numerous opportunities we see to capitalize on our core operational areas."
Update Regarding Midstream Expansion in Texas Panhandle Granite Wash
As noted above, in 2011, the Partnership expanded the processing capacity of its Phoenix Plant in the Texas Panhandle from 50 MMcf/d to 80 MMcf/d. The Partnership also announced plans for two new high-efficiency, cryogenic processing plants in the area (the Woodall Plant and the Wheeler Plant). Construction of the 60 MMcf/d Woodall Plant is on schedule and is expected to be in service by early in the second quarter of 2012.
Plans for the Wheeler Plant, originally contemplated at 125 MMcf/d of processing capacity, have been revised to 60 MMcf/d, with the associated capital costs reduced from $100 million to approximately $67 million. Management anticipates the Wheeler Plant will be in service in early 2013.
Plant sites and infrastructure associated with both the Wheeler Plant and Woodall Plant are designed to support further processing expansions. Management believes adding future capacity in more gradual increments will better match the timing of anticipated production growth and available NGL takeaway capacity, thereby limiting periods of under-utilization, while reducing near-term capital requirements.
Eagle Rock currently anticipates these projects will result in an increase to its high-efficiency processing capacity servicing Granite Wash production from approximately 100 MMcf/d at the beginning of 2011 to approximately 250 MMcf/d by early 2013.
Update on Upstream Drilling Activity
During 2011, the Partnership drilled and completed 11 operated wells and participated in 31 non-operated wells across its upstream business's leasehold, predominately in its newly acquired Mid-Continent asset area. The Partnership's upstream business achieved strong results from its program in the liquids-rich Golden Trend field in Grady County, Oklahoma, drilling four operated wells and completing them in multiple producing formations. In response, management intends to accelerate development in the Golden Trend field by adding a second operated rig during the first quarter 2012. In addition, the Partnership continued its program in the expanding Cana Shale play by drilling two operated wells and participating in 31 non-operated wells as the play continues to prove up additional leasehold across Canadian, Blaine and Dewey counties in Oklahoma. Eagle Rock continues to operate one rig in the Cana Shale play as well as participating with a non-operated interest in several rigs across the play. Management continues to evaluate its long-term drilling program in certain areas within the Mid-Continent in light of the current natural gas price environment. For 2011, the Partnership's drilling and recompletion program developed 39 Bcfe at an overall cost of $2.19/Mcfe.
Year-End Proved Reserves
Eagle Rock estimates its proved reserves at year-end 2011 totaled 371 Bcfe, up 191% from year-end 2010. Approximately 76% of the total proved reserves as of December 31, 2011 were classified as proved developed. Total production for 2011 was 24.2 Bcfe, or 66 MMcfe/d, an increase of 120% from total production in 2010. The Partnership added 272 Bcfe of reserves during 2011 through extensions, discoveries and acquisitions, replacing 1,025% of 2011 production. The reserve additions were driven primarily by the acquisition of Crow Creek Energy in May of 2011 and by new drilling activity.
Fourth Quarter 2011 Financial and Operating Results
In December 2011, the Partnership's Chief Executive Officer decided that due to the relative size of the East Texas/Louisiana, South Texas and Gulf of Mexico segments, these three reporting segments would be collapsed into a single reporting segment and that a new Marketing and Trading reporting segment would be created. The Midstream Business's financial results are now reported in the following segments: (i) Texas Panhandle, which no longer includes the results of the Partnership's Marketing and Trading operations, (ii) East Texas and Other Midstream, which consolidates Eagle Rock's former East Texas/Louisiana, South Texas and Gulf of Mexico segments, and (iii) Marketing and Trading, which is a new reporting segment. Operating results for the reportable segments have been recast for the years ending December 31, 2010 and 2009 to reflect these changes. The Partnership's Upstream segment and functional (Corporate) segments remained unchanged from what has been previously reported.
The following discussion of Eagle Rock's operating income by business segment compares the Partnership's financial results in the fourth quarter of 2011 to those of the third quarter of 2011. The Partnership believes comparing these periods is more illustrative of current operating trends than comparing the current quarter to results achieved in the fourth quarter of 2010. Please refer to the financial tables at the end of this release for further detailed information.
Midstream Business - Operating income from continuing operations, excluding the impact of impairments, for the Midstream Business in the fourth quarter of 2011 decreased by approximately $2.0 million, or 13%, compared to the third quarter of 2011. This decrease was due to lower average realized prices for natural gas, NGLs and condensate; a 6% decrease in natural gas gathering volumes; and an 8% decrease in equity condensate volumes. These factors were partially offset by higher equity NGLs volumes.
In the Texas Panhandle, gathered volumes were down 3%, with combined equity NGL and condensate volumes up approximately 4%, compared to the third quarter of 2011. Gathering volumes were down slightly due to “freeze-offs” at the wellhead resulting from extremely cold weather in the West Panhandle during certain periods in the fourth quarter. NGLs and condensate volumes were higher due to higher processing recoveries and increased pipeline pigging frequencies, as compared to the third quarter 2011.
In the East Texas and Other Midstream segment, gathered volumes were down 8%, with equity NGL and condensate volumes down approximately 7%, compared to the third quarter of 2011. The decrease in gathered volumes and combined equity NGL and condensate volumes were due to natural declines in the production of the existing wells and delays due to certain technical and completion difficulties experienced by the Partnership's producer customers during the quarter.
The Marketing and Trading segment includes the financial results of the Partnership's crude oil marketing and natural gas marketing and trading subsidiaries. Eagle Rock's crude oil marketing subsidiary was created in 2010 to develop and implement marketing uplift strategies surrounding crude and condensate in Alabama and in the Texas Panhandle. Eagle Rock's natural gas marketing and trading subsidiary, Eagle Rock Gas Services, LLC (“ERGS”), was created in 2011 to capitalize on physical and financial natural gas marketing and trading opportunities that extend from the Partnership's upstream and midstream assets. Operating income for the Marketing and Trading segment in the fourth quarter of 2011, including intercompany sales and intersegment cost of sales, increased by approximately $626,000, or 77%, compared to the third quarter of 2011. The primary driver behind the increase was the full quarter of activity from ERGS.
Upstream Business - Operating income for Eagle Rock's Upstream Business in the fourth quarter of 2011, excluding the impact of impairments, decreased by $5.0 million, or 18%, compared to the third quarter of 2011. The decrease was partially attributable to lower realized natural gas prices, higher unit operating costs and higher depletion expense, as compared to the third quarter of 2011. This decrease was partially offset by higher realized crude oil, condensate and NGL prices as well as higher production during the quarter, as compared to the third quarter of 2011. Production volumes in the Upstream Business averaged 87.7 MMcfe/d during the quarter, an increase of approximately 8% over the third quarter of 2011. The Partnership conducted a seven day turnaround in October at its Big Escambia Creek plant and a twelve day turnaround at its Flomaton plant. Both plants process the Partnership's upstream production in Southern Alabama; in total, the impact of turnarounds reduced fourth quarter production by an estimated 2.0 MMcf/d and negatively impacted Adjusted EBITDA by approximately $4.4 million. The Partnership also completed a nine day turnaround at its Big Escambia Creek facility in September, which lowered operating income during the third quarter of 2011 by approximately $3.0 million.
Corporate Segment - Operating loss for the Corporate segment, excluding the impact of unrealized derivative gains and losses, was $18.1 million for the fourth quarter of 2011 as compared to $17.7 million for the third quarter of 2011. The increased loss was attributable to changes in intercompany eliminations, partially offset by a $1.9 million reduction in General and Administrative expenses for the fourth quarter.
Total revenue for the fourth quarter of 2011, including the impact of Eagle Rock's realized and unrealized commodity derivative gains and losses, was $220.7 million, down 40% compared with the $370.1 million reported for the third quarter of 2011. The decrease in revenue was primarily due to higher unrealized losses on commodity derivatives compared to the third quarter of 2011. Eagle Rock recorded an unrealized loss on commodity derivatives of $33.3 million in the fourth quarter 2011, as compared to an unrealized gain on commodity derivatives of $97.0 million in the third quarter 2011. Unrealized gain (loss) on commodity derivatives is a non-cash, mark-to-market amount which includes the amortization of commodity hedging costs. Revenues associated with the sale of crude oil, natural gas, NGLs, condensate and sulfur were down 7% relative to the third quarter of 2011, driven primarily by lower average realized NGL and natural gas prices.
Adjusted EBITDA was $61.8 million and Distributable Cash Flow was $35.2 million for the fourth quarter of 2011. The Partnership's distribution of $0.21 per common unit with respect to the fourth quarter of 2011 was paid on Tuesday, February 14, 2012 to the Partnership's common
unitholders of record as of the close of business on Tuesday, February 7, 2012.
Update Regarding Distribution Policy
As previously stated, management anticipates recommending to the Board of Directors further increases in the distribution in 2012, with the objective of reaching an annualized distribution rate of $1.00 per unit by the end of 2012.
Management's intentions around future distribution recommendations are subject to change should factors affecting the general business climate, market conditions, commodity prices, the Partnership's specific operations, performance of the Partnership's underlying assets, applicable regulatory mandates, or the Partnership's ability to consummate accretive growth projects differ from current expectations. For example, Management's future distribution recommendations may be lower than the current guidance should the recent weakness in natural gas prices persist and impact the Partnership's and its producer customers' drilling plans.
Actual future distributions will be determined, declared and paid at the discretion of the Board of Directors.
Full Year 2011 Financial and Operating Results
Total revenue for 2011, including the impact of Eagle Rock's realized and unrealized derivative gains and losses, was $1.1 billion, up 45% compared with $732.3 million reported for 2010. The largest contributor to the increase in total revenue was the Mid-Continent assets which Eagle Rock acquired on May 3, 2011. The Partnership recorded an unrealized gain on commodity derivatives of $52.9 million in 2011, as compared to an unrealized gain on commodity derivatives of $8.2 million in 2010. Revenues associated with the sale of crude oil, natural gas, NGLs, condensate and sulfur were up 42% relative to those in 2010, driven by higher production volumes associated with the acquisition of the Mid-Continent assets and higher average realized crude oil and condensate prices. 2011 revenues included a realized loss on commodity derivatives of $20.4 million, as compared to a realized loss of $17.0 million in 2010.
Adjusted EBITDA was $208.2 million and Distributable Cash Flow was $119.3 million in 2011 as compared to $126.0 million and $64.9 million, respectively, in 2010.
With regard to the Partnership's Midstream Business operations, gas gathering volumes were down 3%, and combined NGL and condensate volumes were down 8% for the year, as compared to those in 2010. The impact of these declines were offset by higher average realized prices for NGLs and condensate which were up 19% and 20%, respectively, as compared to NGL and condensate prices in 2010.
With regard to the Partnership's Upstream Business operations, total production was up 120% as compared to production in 2010 primarily due to the acquisition of the Mid-Continent assets on May 3, 2011.
Capitalization and Liquidity Update
Total debt outstanding as of December 31, 2011 was $779.5 million, consisting of $298.0 million of senior unsecured notes (net of an unamortized debt discount of $2.0 million) and borrowings of $481.5 million under the Partnership's senior secured credit facility. Total debt increased during the fourth quarter of 2011 by $38.5 million, due primarily to capital spending related to the
Woodall Plant and to new drilling activity.
The Partnership is in compliance with its financial covenants and has no maturities under its credit facility until June 2016. Availability under the credit facility is subject to a borrowing base comprised of two components: the upstream component and the midstream component. As of December 31, 2011, the Partnership had approximately $194 million of availability under the credit facility, based on its outstanding commitments.
With the reduced capital requirements for the Wheeler Plant, the Partnership has revised its expected 2012 capital budget to approximately $280 million, from $335 million. Management continues to evaluate its Upstream drilling program in certain areas in light of the current natural gas price environment. Any cutbacks to expected drilling activity would further reduce expected 2012 capital expenditures.
Hedging Update
During the fourth quarter 2011, the Partnership entered into the following hedges:
In October of 2011, the Partnership entered into the hedges outlined below to replace a portion of its 2012 “proxy hedges” (where one commodity is hedged with a closely-correlated commodity) with direct NGL product hedges.
NYMEX WTI Crude to Direct NGL Product Hedges:
Product / (Type) | Quantity | Price | Term | |||
WTI Crude (Swap Unwind) | (7,800) Bbls/month | $97.42 | Cal. 2012 | |||
WTI Crude (Remaining Swap) | 12,200 Bbls/month | $103.31 | Cal. 2012 | |||
Note: Proceeds from unwind rolled into strike price on remaining volumes.
Product / (Type) | Quantity | Price | Term | |||
OPIS Propane (Swap) | 961,800 Gallons/month | $1.3425 | Cal. 2012 | |||
OPIS IsoButane (Swap) | 310,800 Gallons/month | $1.7700 | Cal. 2012 | |||
OPIS Normal Butane (Swap) | 453,600 Gallons/month | $1.6700 | Cal. 2012 | |||
OPIS Natural Gasoline (Swap) | 252,000 Gallons/month | $2.1900 | Cal. 2012 | |||
NYMEX Henry Hub Natural Gas to Direct Ethane Hedges:
Product / (Type) | Quantity | Price | Term | |||
Natural Gas (Swap Offset) | (260,000) MMbtu/month | $3.965 | Jan-Jun 2012 | |||
OPIS Ethane (Swap) | 3,150,000 Gallons/month | $0.7300 | Jan-Jun 2012 | |||
Note: Natural gas transaction offsets an existing hedge with the same counterparty.
In November of 2011, the Partnership entered into the following hedges with regard to its 2013 and 2014 projected crude oil, condensate and NGL production:
Product / (Type) | Quantity | Price | Term | |||
WTI Crude (Swap) | 45,000 Bbls/month | $93.47 | Cal. 2013 | |||
WTI Crude (Swap) | 45,000 Bbls/month | $92.28 | Cal. 2014 | |||
In addition, the Partnership entered into the following hedge transactions in February of 2012:
Product / (Type) | Quantity | Price | Term | |||
WTI Crude (Swap) | 50,000 Bbls/month | $98.27 | Cal. 2014 | |||
Details of the recent hedging transactions are included in the updated Commodity Hedging Overview presentation Eagle Rock posted today to its website. The latest presentation can be accessed by going to www.eaglerockenergy.com; select Investor Relations; then select Presentations.
Conference Call
Eagle Rock will hold a conference call to discuss its fourth quarter and full year 2011 financial and operating results on Thursday, February 23, 2012 at 2:00 p.m. Eastern Time (1:00 p.m. Central Time).
Interested parties may listen live over the internet or via telephone. To listen live over the internet, log on to the Partnership's web site at www.eaglerockenergy.com. To participate by telephone, the call-in number is 888-680-0869, confirmation code 91452793. Investors are advised to dial into the call at least 15 minutes prior to the call to register. Participants may pre-register for the call by using the following link: https://www.theconferencingservice.com/prereg/key.process?key=PKKBG4G8F. Interested parties can also view important information about the Partnership's conference call by following this link. Pre-registering is not mandatory but is recommended as it will provide you immediate entry to the call and will facilitate the timely start of the call. Pre-registration only takes a few minutes and you may pre-register at any time, including up to and after the start of the call. An audio replay of the conference call will also be available for thirty days by dialing 888-286-8010, confirmation code 29765383. 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 Energy is a growth-oriented limited partnership engaged in: (i) the business of gathering, compressing, treating, processing, transporting, marketing and trading natural gas; fractionating, transporting and marketing natural gas liquids; and crude oil logistics and marketing; and (ii) the business of developing and producing hydrocarbons in oil and natural gas properties. Its corporate office is located in Houston, Texas.
Contacts:
Eagle Rock Energy Partners, L.P.
Jeff Wood, 281-408-1203
Senior Vice President and Chief Financial Officer
Adam Altsuler, 281-408-1350
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 realized interest rate risk management instruments 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 our equity-based compensation program; unrealized (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 more accurately 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 more accurately 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 more accurate 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. For example, the Partnership includes in Adjusted EBITDA the actual settlement revenue created from its commodity hedges by virtue of transactions undertaken by it to reset commodity hedges to prices higher than those reflected in the forward curve at the time of the transaction or to purchase puts or other similar floors despite the fact that the Partnership excludes from Adjusted EBITDA any charge for amortization of the cost of such commodity hedge reset transactions or puts. Eagle Rock has reconciled Adjusted EBITDA to the GAAP financial measure of net income (loss) at the end of this release.
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 made to replace partially or fully depreciated assets; to meet regulatory requirements; to maintain the existing operating capacity of the Partnership's gathering, processing and treating assets or to maintain the Partnership's natural gas, NGL, crude or sulfur production.
Distributable Cash Flow is a significant 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. See the example given above for Adjusted EBITDA related to amortization of costs of commodity hedges, including costs of hedge reset transactions. Eagle Rock has reconciled Distributable Cash Flow to the GAAP financial measure of net income/(loss) at the end of this release.
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; market demand for oil, natural gas and natural gas liquids; the effectiveness of the Partnership's hedging activities; the Partnership's ability to retain key customers; the Partnership's ability to continue to obtain new sources of production and supplies of oil, natural gas and natural gas liquids; the availability of local, intrastate and interstate transportation systems and other facilities to transport 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 Securities and Exchange Commission (“SEC”) for the year ended December 31, 2010 and the Partnership's Forms 10-Q filed with the SEC for subsequent quarters, 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 December 31, | Twelve Months Ended December 31, | Three Months Ended September 30, 2011 | |||||||||||||||||
2011 | 2010 | 2011 | 2010 | ||||||||||||||||
REVENUE: | |||||||||||||||||||
Natural gas, natural gas liquids, oil, condensate and sulfur sales | $ | 245,461 | $ | 171,776 | $ | 977,952 | $ | 688,052 | $ | 264,119 | |||||||||
Gathering, compression, processing and treating fees | 10,654 | 9,802 | 47,770 | 50,608 | 11,567 | ||||||||||||||
Unrealized commodity derivative (losses) gains | (33,288 | ) | (29,615 | ) | 52,876 | 8,224 | 97,011 | ||||||||||||
Realized commodity derivative losses | (2,408 | ) | (6,979 | ) | (20,366 | ) | (17,010 | ) | (2,698 | ) | |||||||||
Other revenue | 270 | 2,550 | 1,676 | 2,435 | 141 | ||||||||||||||
Total revenue | 220,689 | 147,534 | 1,059,908 | 732,309 | 370,140 | ||||||||||||||
COSTS AND EXPENSES: | |||||||||||||||||||
Cost of natural gas and natural gas liquids | 146,898 | 115,077 | 633,184 | 468,304 | 166,293 | ||||||||||||||
Operations and maintenance | 26,725 | 18,904 | 93,048 | 76,415 | 24,897 | ||||||||||||||
Taxes other than income | 6,087 | 3,277 | 19,148 | 12,226 | 4,556 | ||||||||||||||
General and administrative | 14,145 | 9,284 | 57,891 | 45,775 | 16,068 | ||||||||||||||
Other operating income | — | — | (2,893 | ) | — | — | |||||||||||||
Impairment | 1,534 | 104 | 16,288 | 6,666 | 9,870 | ||||||||||||||
Depreciation, depletion and amortization | 41,297 | 25,593 | 131,611 | 106,398 | 35,040 | ||||||||||||||
Total costs and expenses | 236,686 | 172,239 | 948,277 | 715,784 | 256,724 | ||||||||||||||
OPERATING (LOSS) INCOME | (15,997 | ) | (24,705 | ) | 111,631 | 16,525 | 113,416 | ||||||||||||
OTHER INCOME (EXPENSE): | |||||||||||||||||||
Interest income | 12 | (73 | ) | 25 | 111 | 7 | |||||||||||||
Interest expense, net | (10,055 | ) | (3,091 | ) | (29,647 | ) | (15,147 | ) | (10,057 | ) | |||||||||
Realized interest rate derivative losses | (3,622 | ) | (4,959 | ) | (16,996 | ) | (19,971 | ) | (3,713 | ) | |||||||||
Unrealized interest rate derivative (losses) gains | 3,404 | 5,124 | 5,595 | (7,164 | ) | (3,165 | ) | ||||||||||||
Other (expense) income | (17 | ) | 402 | (184 | ) | 450 | (3 | ) | |||||||||||
Total other income (expense) | (10,278 | ) | (2,597 | ) | (41,207 | ) | (41,721 | ) | (16,931 | ) | |||||||||
(LOSS) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | (26,275 | ) | (27,302 | ) | 70,424 | (25,196 | ) | 96,485 | |||||||||||
INCOME TAX BENEFIT | (622 | ) | (1,615 | ) | (2,432 | ) | (2,585 | ) | (1,077 | ) | |||||||||
(LOSS) INCOME FROM CONTINUING OPERATIONS | (25,653 | ) | (25,687 | ) | 72,856 | (22,611 | ) | 97,562 | |||||||||||
DISCONTINUED OPERATIONS, NET OF TAX | 66 | (26,549 | ) | 276 | 17,262 | (197 | ) | ||||||||||||
NET (LOSS) INCOME | $ | (25,587 | ) | $ | (52,236 | ) | $ | 73,132 | $ | (5,349 | ) | $ | 97,365 | ||||||
Eagle Rock Energy Partners, L.P.
Consolidated Balance Sheets
($ in thousands)
(unaudited)
December 31, 2011 | December 31, 2010 | ||||||
ASSETS | |||||||
CURRENT ASSETS: | |||||||
Cash and cash equivalents | $ | 877 | $ | 4,049 | |||
Accounts receivable | 97,832 | 75,695 | |||||
Risk management assets | 13,080 | — | |||||
Prepayments and other current assets | 13,739 | 2,498 | |||||
Assets held for sale | — | 8,615 | |||||
Total current assets | 125,528 | 90,857 | |||||
PROPERTY, PLANT AND EQUIPMENT - Net | 1,763,674 | 1,137,239 | |||||
INTANGIBLE ASSETS - Net | 109,702 | 113,634 | |||||
DEFERRED TAX ASSET | 1,432 | 1,969 | |||||
RISK MANAGEMENT ASSETS | 24,290 | 1,075 | |||||
OTHER ASSETS | 21,062 | 4,623 | |||||
TOTAL ASSETS | $ | 2,045,688 | $ | 1,349,397 | |||
LIABILITIES AND MEMBERS' EQUITY | |||||||
CURRENT LIABILITIES: | |||||||
Accounts payable | $ | 145,939 | $ | 91,886 | |||
Due to affiliate | 46 | 56 | |||||
Accrued liabilities | 12,734 | 10,940 | |||||
Taxes payable | 487 | 1,102 | |||||
Risk management liabilities | 11,649 | 39,350 | |||||
Liabilities held for sale | — | 1,705 | |||||
Total current liabilities | 170,855 | 145,039 | |||||
LONG-TERM DEBT | 779,453 | 530,000 | |||||
ASSET RETIREMENT OBLIGATIONS | 33,303 | 24,711 | |||||
DEFERRED TAX LIABILITY | 45,216 | 38,662 | |||||
RISK MANAGEMENT LIABILITIES | 6,893 | 31,005 | |||||
OTHER LONG TERM LIABILITIES | 2,621 | 867 | |||||
MEMBERS' EQUITY | 1,007,347 | 579,113 | |||||
TOTAL LIABILITIES AND MEMBERS' EQUITY | $ | 2,045,688 | $ | 1,349,397 | |||
Eagle Rock Energy Partners, L.P.
Segment Summary
Operating Income
($ in thousands)
(unaudited)
Three Months Ended December 31, | Year Ended December 31, | Three Months Ended September 30, 2011 | |||||||||||||||||
2011 | 2010 | 2011 | 2010 | ||||||||||||||||
Midstream | |||||||||||||||||||
Revenues: | |||||||||||||||||||
Natural gas, natural gas liquids, oil and condensate sales | $ | 198,582 | $ | 155,338 | $ | 823,521 | $ | 601,815 | $ | 213,593 | |||||||||
Intercompany sales - natural gas | (4,084 | ) | — | (5,487 | ) | 47 | (1,403 | ) | |||||||||||
Gathering and treating services | 10,654 | 9,802 | 47,770 | 50,608 | 11,567 | ||||||||||||||
Total revenue | 205,152 | 165,140 | 865,804 | 652,470 | 223,757 | ||||||||||||||
Cost of natural gas, natural gas liquids, oil and condensate | 146,898 | 115,077 | 633,184 | 468,304 | 161,963 | ||||||||||||||
Intersegment elimination - Cost of natural gas, oil and condensate | 11,565 | 5,587 | 41,382 | 5,587 | 13,155 | ||||||||||||||
Operating costs and expenses: | |||||||||||||||||||
Operations and maintenance | 16,458 | 14,410 | 64,539 | 55,917 | 16,716 | ||||||||||||||
Impairment | — | — | 4,560 | 3,130 | — | ||||||||||||||
Depreciation, depletion and amortization | 16,413 | 19,286 | 64,663 | 74,424 | 16,093 | ||||||||||||||
Total operating costs and expenses | 32,871 | 33,696 | 133,762 | 133,471 | 32,809 | ||||||||||||||
Operating income from continuing operations | 13,818 | 10,780 | 57,476 | 45,108 | 15,830 | ||||||||||||||
Discontinued Operations (1) | 66 | (26,144 | ) | (128 | ) | (25,781 | ) | (197 | ) | ||||||||||
Operating income (loss) | $ | 13,884 | $ | (15,364 | ) | $ | 57,348 | $ | 19,327 | $ | 15,633 | ||||||||
Upstream | |||||||||||||||||||
Revenue | |||||||||||||||||||
Oil and condensate sales (2) | $ | 17,775 | $ | 6,790 | $ | 51,574 | $ | 44,444 | $ | 17,269 | |||||||||
Intersegment sales - condensate | 12,741 | 6,063 | 42,716 | 6,063 | 7,451 | ||||||||||||||
Natural gas sales (3) | 9,854 | 3,045 | 42,551 | 15,027 | 16,014 | ||||||||||||||
Intersegment sales - natural gas | 4,084 | — | 5,487 | — | 1,403 | ||||||||||||||
Natural gas liquids sales (4) | 14,278 | 4,488 | 42,553 | 19,973 | 12,186 | ||||||||||||||
Sulfur sales | 4,972 | 2,115 | 17,753 | 6,793 | 5,057 | ||||||||||||||
Other | 270 | 2,550 | 1,676 | 2,435 | 141 | ||||||||||||||
Total revenue | 63,974 | 25,051 | 204,310 | 94,735 | 59,521 | ||||||||||||||
Operating costs and expenses: | |||||||||||||||||||
Operations and maintenance (1) | 16,354 | 7,818 | 47,723 | 32,724 | 12,737 | ||||||||||||||
Intersegment operations and maintenance | — | — | — | 47 | — | ||||||||||||||
Impairment | 1,534 | 104 | 11,728 | 3,536 | 9,870 | ||||||||||||||
Depreciation, depletion and amortization | 24,485 | 5,991 | 65,531 | 30,424 | 18,636 | ||||||||||||||
Total operating costs and expenses | 42,373 | 13,913 | 124,982 | 66,731 | 41,243 | ||||||||||||||
Operating income | $ | 21,601 | $ | 11,138 | $ | 79,328 | $ | 28,004 | $ | 18,278 | |||||||||
Corporate and Other | |||||||||||||||||||
Revenues: | |||||||||||||||||||
Unrealized commodity derivative (losses) gains | $ | (33,288 | ) | $ | (29,615 | ) | $ | 52,876 | $ | 8,224 | $ | 97,011 | |||||||
Realized commodity derivative losses | (2,408 | ) | (6,979 | ) | (20,366 | ) | (17,010 | ) | (2,698 | ) | |||||||||
Intersegment elimination - Sales of natural gas, oil and condensate | (12,741 | ) | (6,063 | ) | (42,716 | ) | (6,110 | ) | (7,451 | ) | |||||||||
Total revenue | (48,437 | ) | (42,657 | ) | (10,206 | ) | (14,896 | ) | 86,862 | ||||||||||
Costs and expenses: | |||||||||||||||||||
Intersegment elimination - Cost of natural gas, oil and condensate | (11,565 | ) | (5,587 | ) | (41,382 | ) | (5,587 | ) | (8,825 | ) | |||||||||
General and administrative | 14,145 | 9,284 | 57,891 | 45,775 | 16,068 | ||||||||||||||
Intersegment elimination - Operations and maintenance | — | — | (66 | ) | — | — | |||||||||||||
Other operating Income | — | — | (2,893 | ) | — | — | |||||||||||||
Depreciation, depletion and amortization | 399 | 316 | 1,417 | 1,550 | 311 | ||||||||||||||
Operating (loss) income | $ | (51,416 | ) | $ | (46,670 | ) | $ | (25,173 | ) | $ | (56,634 | ) | $ | 79,308 | |||||
____________________
(1) | Includes natural gas sales of $66 from the East Texas and Other Midstream Texas Segment to the Upstream Segment for the year ended December 31, 2011. |
(2) | Revenues include a change in the value of product imbalances of $21, $43, $(89) and $430 for the year ended December 31, 2011 and 2010, respectively, and $(38) for the three months ended September 30, 2011. |
(3) | Revenues include a change in the value of product imbalances of $(224), $451, $(69) and $370 for the year ended December 31, 2011 and 2010, respectively, and $270 for the three months ended September 30, 2011. |
(4) | Revenues include a change in the value of product imbalances of $6, $21, $(48) and $48 for the year ended December 31, 2011 and 2010, respectively, and $(125) for the three months ended September 30, 2011. |
Eagle Rock Energy Partners, L.P.
Midstream Segment
Operating Income
($ in thousands)
(unaudited)
Three Months Ended December 31, | Year Ended December 31, | Three Months Ended September 30, 2011 | |||||||||||||||||
2011 | 2010 | 2011 | 2010 | ||||||||||||||||
Texas Panhandle | |||||||||||||||||||
Revenues: | |||||||||||||||||||
Natural gas, natural gas liquids, oil and condensate sales | $ | 74,104 | $ | 84,021 | $ | 378,917 | $ | 334,614 | $ | 90,420 | |||||||||
Intersegment sales - natural gas | 33,990 | — | 60,237 | — | 26,247 | ||||||||||||||
Gathering, compression, processing and treating services | 4,169 | 3,146 | 17,074 | 11,957 | 4,892 | ||||||||||||||
Total revenue | 112,263 | 87,167 | 456,228 | 346,571 | 121,559 | ||||||||||||||
Cost of natural gas, natural gas liquids, oil and condensate | 80,263 | 55,395 | 327,775 | 231,880 | 87,797 | ||||||||||||||
Operating costs and expenses: | |||||||||||||||||||
Operations and maintenance | 10,315 | 9,347 | 41,749 | 35,013 | 10,826 | ||||||||||||||
Impairment | — | — | 4,560 | — | — | ||||||||||||||
Depreciation, depletion and amortization | 9,652 | 10,945 | 37,034 | 45,876 | 9,145 | ||||||||||||||
Total operating costs and expenses | 19,967 | 20,292 | 83,343 | 80,889 | 19,971 | ||||||||||||||
Operating income | $ | 12,033 | $ | 11,480 | $ | 45,110 | $ | 33,802 | $ | 13,791 | |||||||||
East Texas and Other Midstream | |||||||||||||||||||
Revenues: | |||||||||||||||||||
Natural gas, natural gas liquids, oil and condensate sales | $ | 49,888 | $ | 59,653 | $ | 243,673 | $ | 255,537 | $ | 59,590 | |||||||||
Intercompany Sales | 12,324 | — | 16,654 | 47 | 4,330 | ||||||||||||||
Gathering, compression, processing and treating services | 6,477 | 6,656 | 30,688 | 38,651 | 6,675 | ||||||||||||||
Total revenue | 68,689 | 66,309 | 291,015 | 294,235 | 70,595 | ||||||||||||||
Cost of natural gas and natural gas liquids | 55,440 | 54,095 | 231,642 | 230,837 | 56,536 | ||||||||||||||
Operating costs and expenses: | |||||||||||||||||||
Operations and maintenance | 6,145 | 5,044 | 22,790 | 20,885 | 5,888 | ||||||||||||||
Impairment | — | — | — | 3,130 | — | ||||||||||||||
Depreciation, depletion and amortization | 6,761 | 8,341 | 27,629 | 28,548 | 6,948 | ||||||||||||||
Total operating costs and expenses | 12,906 | 13,385 | 50,419 | 52,563 | 12,836 | ||||||||||||||
Operating income (loss) from continuing operations | 343 | (1,171 | ) | 8,954 | 10,835 | 1,223 | |||||||||||||
Discontinued Operations (1) | 66 | (26,144 | ) | (128 | ) | (25,781 | ) | (197 | ) | ||||||||||
Operating income (loss) | $ | 409 | $ | (27,315 | ) | $ | 8,826 | $ | (14,946 | ) | $ | 1,026 | |||||||
Marketing and Trading | |||||||||||||||||||
Revenues: | |||||||||||||||||||
Natural gas, natural gas liquids, oil and condensate sales | $ | 74,590 | $ | 11,664 | $ | 200,931 | $ | 11,664 | $ | 63,583 | |||||||||
Intercompany Sales | (50,398 | ) | — | (82,378 | ) | — | (31,980 | ) | |||||||||||
Gathering, compression, processing and treating services | 8 | — | 8 | — | — | ||||||||||||||
Total revenue | 24,200 | 11,664 | 118,561 | 11,664 | 31,603 | ||||||||||||||
Cost of natural gas and natural gas liquids | 11,195 | 5,587 | 73,767 | 5,587 | 17,630 | ||||||||||||||
Intersegment Cost of Sales | 11,565 | 5,587 | 41,382 | 5,587 | 13,155 | ||||||||||||||
Operating costs and expenses: | |||||||||||||||||||
Operations and maintenance | (2 | ) | 19 | — | 19 | 2 | |||||||||||||
Total operating costs and expenses | (2 | ) | 19 | — | 19 | 2 | |||||||||||||
Operating income | $ | 1,442 | $ | 471 | $ | 3,412 | $ | 471 | $ | 816 | |||||||||
____________________
(1) | Includes sales of natural gas of $66 and $24 to the Upstream Segment for the nine months ended September 30, 2011 and the three months ended September 30, 2011, respectively. |
Eagle Rock Energy Partners, L.P.
Midstream Operations Information
(unaudited)
Three Months Ended December 31, | Year Ended December 31, | Three Months Ended September 30, 2011 | |||||||||||||||||
2011 | 2010 | 2011 | 2010 | ||||||||||||||||
Gas gathering volumes - (Average Mcf/d) | |||||||||||||||||||
Texas Panhandle | 158,419 | 142,976 | 155,122 | 131,925 | 163,665 | ||||||||||||||
East Texas and Other Midstream (1) | 286,920 | 325,954 | 319,892 | 357,403 | 312,102 | ||||||||||||||
Total | 445,339 | 468,930 | 475,014 | 489,328 | 475,767 | ||||||||||||||
NGLs - (Net equity Bbls) | |||||||||||||||||||
Texas Panhandle | 271,252 | 244,540 | 880,348 | 905,379 | 231,965 | ||||||||||||||
East Texas and Other Midstream (1) | 105,793 | 182,585 | 451,048 | 545,666 | 114,279 | ||||||||||||||
Total | 377,045 | 427,125 | 1,331,396 | 1,451,045 | 346,244 | ||||||||||||||
Condensate - (Net equity Bbls) | |||||||||||||||||||
Texas Panhandle | 238,172 | 254,127 | 962,982 | 1,034,275 | 260,228 | ||||||||||||||
East Texas and Other Midstream (1) | 10,816 | 9,454 | 46,242 | 49,523 | 10,519 | ||||||||||||||
Total | 248,988 | 263,581 | 1,009,224 | 1,083,798 | 270,747 | ||||||||||||||
Natural gas short position - (Average MMbtu/d) | |||||||||||||||||||
Texas Panhandle | (5,932 | ) | (3,046 | ) | (5,622 | ) | (4,811 | ) | (7,418 | ) | |||||||||
East Texas and Other Midstream (1) | 1,765 | 968 | 1,913 | 1,698 | 1,758 | ||||||||||||||
Total | (4,167 | ) | (2,078 | ) | (3,709 | ) | (3,113 | ) | (5,660 | ) | |||||||||
Average realized NGL price - per Bbl | |||||||||||||||||||
Texas Panhandle | $ | 46.25 | $ | 48.50 | $ | 52.67 | $ | 45.85 | $ | 53.39 | |||||||||
East Texas and Other Midstream (1) | $ | 46.03 | $ | 41.16 | $ | 49.72 | $ | 39.76 | $ | 52.57 | |||||||||
Weighted Average | $ | 46.16 | $ | 45.20 | $ | 51.42 | $ | 43.07 | $ | 53.08 | |||||||||
Average realized condensate price - per Bbl | |||||||||||||||||||
Texas Panhandle | $ | 75.04 | $ | 71.61 | $ | 80.41 | $ | 66.68 | $ | 79.43 | |||||||||
East Texas and Other Midstream (1) | $ | 98.08 | $ | 87.72 | $ | 95.08 | $ | 78.50 | $ | 93.82 | |||||||||
Total | $ | 76.52 | $ | 72.94 | $ | 81.56 | $ | 67.75 | $ | 79.74 | |||||||||
Average realized natural gas price - per MMbtu | |||||||||||||||||||
Texas Panhandle | $ | 3.24 | $ | 3.72 | $ | 3.74 | $ | 3.92 | $ | 3.86 | |||||||||
East Texas and Other Midstream (1) | $ | 3.42 | $ | 3.76 | $ | 4.15 | $ | 4.69 | $ | 4.36 | |||||||||
Total | $ | 3.31 | $ | 3.74 | $ | 3.91 | $ | 4.31 | $ | 4.05 | |||||||||
____________________
(1) | The Partnership changed the way it reports NGL and condensate volumes under certain contracts in its East Texas/Louisiana Segment. For the three and twelve months ended December 31, 2011 and the three months ended September 30, 2011, volumes from Eagle Rock's Indian Springs plant, in which the Partnership owns 25%, are included in equity NGL and condensate volumes, as the Partnership believes including these volumes is more illustrative of current operating trends. In addition, volumes associated with a certain contract at the Partnership's Brookeland plant have been excluded from the three and twelve months ended December 31, 2011 and three months ended September 30, 2011 due to a change in reporting methodology. |
Eagle Rock Energy Partners, L.P.
Upstream Operations Information
(unaudited)
Three Months Ended December 31, | Year Ended December 31, | Three Months Ended September 30, 2011 | |||||||||||||||||
2011 | 2010 | 2011 | 2010 | ||||||||||||||||
Upstream | |||||||||||||||||||
Production: | |||||||||||||||||||
Oil and condensate (Bbl) | 345,428 | 194,762 | 1,117,778 | 808,077 | 302,766 | ||||||||||||||
Gas (Mcf) | 4,363,298 | 770,195 | 12,636,473 | 3,514,078 | 4,274,811 | ||||||||||||||
NGLs (Bbl) | 272,136 | 81,905 | 805,359 | 437,375 | 227,614 | ||||||||||||||
Total Mcfe | 8,069,682 | 2,430,197 | 24,175,297 | 10,986,790 | 7,457,091 | ||||||||||||||
Sulfur (long ton) (1) | 26,862 | 14,136 | 98,372 | 84,065 | 27,706 | ||||||||||||||
Realized prices, excluding derivatives: (2) | |||||||||||||||||||
Oil and condensate (per Bbl) | $ | 88.34 | $ | 66.52 | $ | 84.36 | $ | 62.35 | $ | 81.65 | |||||||||
Gas (Mcf) | $ | 3.19 | $ | 4.13 | $ | 3.69 | $ | 4.43 | $ | 4.08 | |||||||||
NGLs (Bbl) | $ | 53.29 | $ | 54.96 | $ | 54.66 | $ | 47.00 | $ | 52.35 | |||||||||
Sulfur (long ton) (1) | $ | 184.87 | $ | 150.26 | $ | 180.95 | $ | 88.36 | $ | 187.03 | |||||||||
Operating statistics: | |||||||||||||||||||
Operating costs per Mcfe (incl production taxes) (3) | $ | 1.86 | $ | 3.22 | $ | 1.88 | $ | 2.92 | $ | 1.42 | |||||||||
Operating costs per Mcfe (excl production taxes) (3) | $ | 1.25 | $ | 2.22 | $ | 1.24 | $ | 2.12 | $ | 0.84 | |||||||||
Operating income per Mcfe | $ | 3.39 | $ | 4.90 | $ | 3.52 | $ | 2.62 | $ | 3.56 | |||||||||
Drilling program (gross wells): | |||||||||||||||||||
Development wells | 10 | — | 42 | 6 | 13 | ||||||||||||||
Completions | 10 | — | 42 | 5 | 13 | ||||||||||||||
Workovers | 1 | 2 | 14 | 15 | 5 | ||||||||||||||
Recompletions | 1 | — | 9 | 11 | 4 | ||||||||||||||
______________________
(1) | During the three months ended March 31, 2010, an adjustment was made to decrease sulfur volumes by 5,230 long tons related to a prior period adjustment. This adjustment is excluded from the calculation of realized prices. |
(2) | Calculation does not include impact of product imbalances. |
(3) | Excludes sulfur disposal costs of $729 the year ended December 31, 2010 and excludes post-production costs of $1,359 and $2,390 for the three months and year ended December 31, 2011, respectively. |
Non-GAAP Financial Measures
The following tables present a reconciliation of the non-GAAP financial measures of Adjusted EBITDA and Distributable Cash Flow to the GAAP financial measure of net income for each of the periods indicated (in thousands).
Eagle Rock Energy Partners, L.P.
GAAP to Non-GAAP Reconciliations
($ in thousands)
(unaudited)
Three Months Ended December 31, | Year Ended December 31, | Three Months Ended September 30, 2011 | |||||||||||||||||
2011 | 2010 | 2011 | 2010 | ||||||||||||||||
Net (loss) income to Adjusted EBITDA | |||||||||||||||||||
Net (loss) income, as reported | $ | (25,587 | ) | $ | (52,236 | ) | $ | 73,132 | $ | (5,349 | ) | $ | 97,365 | ||||||
Depreciation, depletion and amortization | 41,297 | 25,593 | 131,611 | 106,398 | 35,040 | ||||||||||||||
Impairment | 1,534 | 104 | 16,288 | 6,666 | 9,870 | ||||||||||||||
Risk management interest related instruments - unrealized | (3,404 | ) | (5,124 | ) | (5,595 | ) | 7,164 | 3,165 | |||||||||||
Risk management commodity related instruments - unrealized, including amortization of commodity derivative costs | 33,288 | 29,615 | (52,876 | ) | (8,224 | ) | (97,011 | ) | |||||||||||
Other Operating Income | — | — | (2,893 | ) | — | — | |||||||||||||
Non-cash mark-to-market of Upstream product imbalances | 197 | (281 | ) | 74 | (746 | ) | (107 | ) | |||||||||||
Unrealized gains from other derivative activity | (234 | ) | — | (772 | ) | — | (538 | ) | |||||||||||
Restricted units non-cash amortization expense | 1,704 | 755 | 5,145 | 5,407 | 1,507 | ||||||||||||||
Income tax (benefit) provision | (622 | ) | (1,615 | ) | (2,432 | ) | (2,585 | ) | (1,077 | ) | |||||||||
Interest - net including realized risk management instruments and other expense | 13,682 | 8,123 | 46,802 | 35,058 | 13,766 | ||||||||||||||
Other income | — | (402 | ) | — | (501 | ) | — | ||||||||||||
Discontinued operations | (66 | ) | 26,549 | (276 | ) | (17,262 | ) | 197 | |||||||||||
Adjusted EBITDA | $ | 61,789 | $ | 31,081 | $ | 208,208 | $ | 126,026 | $ | 62,177 | |||||||||
Net (loss) income to Distributable Cash Flow | |||||||||||||||||||
Net (loss) income, as reported | $ | (25,587 | ) | $ | (52,236 | ) | $ | 73,132 | $ | (5,349 | ) | $ | 97,365 | ||||||
Depreciation, depletion and amortization expense | 41,297 | 25,593 | 131,611 | 106,398 | 35,040 | ||||||||||||||
Impairment | 1,534 | 104 | 16,288 | 6,666 | 9,870 | ||||||||||||||
Risk management interest related instruments-unrealized | (3,404 | ) | (5,124 | ) | (5,595 | ) | 7,164 | 3,165 | |||||||||||
Risk management commodity related instruments - unrealized, including amortization of commodity derivative costs | 33,054 | 29,615 | (53,648 | ) | (8,224 | ) | (97,549 | ) | |||||||||||
Capital expenditures-maintenance related | (12,426 | ) | (5,558 | ) | (40,855 | ) | (25,528 | ) | (11,980 | ) | |||||||||
Non-cash mark-to-market of Upstream product imbalances | 197 | (281 | ) | 74 | (746 | ) | (107 | ) | |||||||||||
Restricted units non-cash amortization expense | 1,704 | 755 | 5,145 | 5,407 | 1,507 | ||||||||||||||
Other Operating Income | — | — | (2,893 | ) | — | — | |||||||||||||
Income tax (benefit) provision | (622 | ) | (1,615 | ) | (2,432 | ) | (2,585 | ) | (1,077 | ) | |||||||||
Other income | — | (402 | ) | — | (501 | ) | — | ||||||||||||
Cash income taxes | (489 | ) | 29 | (1,291 | ) | (576 | ) | (325 | ) | ||||||||||
Discontinued operations | (66 | ) | 26,549 | (276 | ) | (17,262 | ) | 197 | |||||||||||
Distributable Cash Flow | $ | 35,192 | $ | 17,429 | $ | 119,260 | $ | 64,864 | $ | 36,106 | |||||||||
Supplemental Information | |||||||||||||||||||
($ in thousands) | |||||||||||||||||||
Three Months Ended December 31, | Year Ended December 31, | Three Months Ended September 30, 2011 | |||||||||||||||||
2011 | 2010 | 2011 | 2010 | ||||||||||||||||
Amortization of commodity derivative costs | $ | — | $ | 442 | $ | — | $ | 3,952 | $ | — | |||||||||
###