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| 8-K - 8-K - EAGLE ROCK ENERGY PARTNERS L P | form8-kq32012earningsrelea.htm |
Exhibit 99.1
October 31, 2012
Eagle Rock Reports Third Quarter 2012 Financial Results
HOUSTON - Eagle Rock Energy Partners, L.P. (together with its subsidiaries, "Eagle Rock" or the "Partnership") (NASDAQ: EROC) today announced its unaudited financial results for the three months ended September 30, 2012. Key financial results with respect to third quarter 2012 included the following:
• | Reported Adjusted EBITDA of $59.1 million, up from the $57.7 million reported for the second quarter of 2012, despite lower quarter-over-quarter crude oil and natural gas liquids (NGL) prices. |
• | Reported Distributable Cash Flow of $27.0 million, a decrease as compared to the $31.6 million reported for the second quarter of 2012, primarily resulting from higher maintenance capital expenditures and higher interest expense during the quarter. |
• | Announced a quarterly distribution with respect to the third quarter of 2012 of $0.22 per common unit, equivalent to $0.88 per unit on an annualized basis. This distribution is equal to the distribution paid for the second quarter 2012 and represents a 10% increase over that paid for the third quarter of 2011. |
• | Reported a Net Loss of $106.9 million compared to Net Income of $61.8 million reported for the second quarter of 2012; the decrease was driven almost entirely by unrealized mark-to-market losses on commodity hedges and impairments, both of which are non-cash charges to earnings. |
Other notable financial and operational activities of the Partnership since June 30, 2012, included the following:
• | Closed the acquisition of BP America Production Company's ("BP") midstream assets in the Texas Panhandle (the "BP Acquisition") on October 1, 2012, for total consideration of $230.6 million in cash. In conjunction with the acquisition, Eagle Rock entered into a 20-year, fixed-fee gas gathering and processing agreement with BP covering a dedicated acreage area. |
• | Announced an amendment to Eagle Rock's existing gas gathering and processing agreement with Anadarko E&P Company LP to, among other things, (i) expand the original dedication area by adding a 10-year dedication for any new wells drilled in an additional area of approximately 800,000 acres in western Louisiana and (ii) provide for a fixed-fee gathering arrangement for all new wells spud on or after April 1, 2012 in either the original or additional dedication areas. |
• | Announced the Upstream component of the borrowing base under the Partnership's senior secured credit facility was increased by 17% to $400 million by its commercial lenders as part of its regularly scheduled semi-annual redetermination. |
• | Completed a public offering of 10,120,000 common units for total net proceeds of approximately $84.5 million on August 17, 2012. The Partnership used the proceeds to repay a portion of the outstanding borrowings under its revolving credit facility in advance of funding the BP Acquisition on October 1, 2012. |
• | Completed a private offering of $250 million of 8.375% senior unsecured notes on July 13, 2012, due 2019. The Partnership used the proceeds to repay outstanding borrowings under its revolving credit facility. |
“We posted a solid quarter despite a continuing challenging commodity price environment,” said Joseph A. Mills, Eagle Rock's Chairman and Chief Executive Officer. “We have further positioned Eagle Rock for future growth and greater cash flow stability with the BP Acquisition and the expansion of our relationship with Anadarko in western Louisiana, both of which are meaningfully based on fixed-fee contract structures. In addition, we continue to focus our Upstream capital activity in the Golden Trend and the Southeast Cana Woodford plays and to further evaluate the full resource potential of our acreage position in the South Central Oklahoma Oil Province (“SCOOP”) area.”
Update Regarding BP Acquisition and Integration
On October 1, 2012, the Partnership completed the acquisition of BP's Sunray and Hemphill processing plants and associated 2,500 mile gathering system serving the liquids-rich Texas Panhandle (the "BP Panhandle System") for $230.6 million, as adjusted under the Purchase and Sale Agreement. As of September 30, 2012, $22.8 million was held as a deposit on the acquisition. The remaining purchase price was funded on October 1, 2012, through borrowings on the Partnership's revolving credit facility.
In addition, Eagle Rock and BP entered into a 20-year, fixed-fee gas gathering and processing agreement. Under the agreement, Eagle Rock is gathering and processing BP's natural gas production from existing connected wells, and BP has committed itself and its farmees to Eagle Rock for the term of the agreement, under substantially the same gas gathering and processing terms, for all future natural gas production from new wells drilled within an initial two-year period from closing, subject to mutually-agreed extensions, and within a two-mile radius of the BP Panhandle System. The BP Panhandle System gathering volumes in the first half of 2012 averaged approximately 180 MMcf/d, and the Partnership expects to continue to grow its overall gathering volumes from the Texas Panhandle area based on expected drilling programs of BP and third party producers active in the area.
Eagle Rock is currently in the process of integrating the BP Panhandle System with its existing system in the area, which will result in approximately 6,463 miles of combined gathering pipelines serving over 5,000 wells and over 480 MMcf/d of combined processing capacity in the Texas Panhandle; an additional 60 MMcf/d of capacity is expected to come on-line in the first half of 2013 following the completion of Eagle Rock's Wheeler Plant. The combined system will strengthen Eagle Rock's position in the growing Granite Wash, Cleveland, Tonkawa and Hogshooter plays and provide increased flexibility and capacity in serving its producer customers.
As anticipated at the time of the announcement of the acquisition, Eagle Rock expects the integration of the two systems, including the planned interconnects, to be completed in the second quarter of 2013 and to result in future cost savings and an enhanced ability to optimize the total gathering and processing capacity.
Activity in the Texas Panhandle remains robust with approximately 10 active rigs in the area dedicated to the combined Eagle Rock and BP Panhandle systems and over 400 wells permitted over the past six months in the Texas Panhandle region.
Update Regarding Construction of the Wheeler Processing Plant
In 2011, the Partnership announced plans for an additional high-efficiency cryogenic processing plant to be installed in the Texas Panhandle - the Wheeler Plant.
Construction of the 60 MMcf/d Wheeler Plant, located in Wheeler County, and associated gathering and compression infrastructure is expected to be completed in the first half of 2013 at a cost of approximately $67 million, of which $32.4 million was spent through September 30, 2012. The addition of the Wheeler Plant to the Partnership's existing processing infrastructure in the Texas Panhandle Segment is in response to incremental processing demand driven by continued drilling activity in the Granite Wash, Cleveland and Tonkawa plays.
Amendment to Existing Gathering and Processing Agreement with Anadarko E&P Company LP
On October 3rd, the Partnership announced that it had entered into an Amendment (the "Amendment") to its existing Gas Gathering and Processing Agreement (the "Agreement") with Anadarko E&P Company LP ("Anadarko") to support Anadarko's drilling program in western Louisiana. The Amendment, among other things, (i) expands the original dedication area of approximately 1.1 million acres (which remains life-of-lease dedicated) by adding a 10-year dedication for any new wells drilled in an additional area of approximately 800,000 acres in western Louisiana, (ii) provides for a fixed gathering fee arrangement (rather than a commodity-price sensitive processing fee) for all wells spud on or after April 1, 2012 in either the original or additional dedication areas, and (iii) revises the mechanism that provides for Eagle Rock's recovery of capital expenditures for connecting its pipelines to Anadarko-operated wells spud on or after April 1, 2012.
Update Regarding the Partnership's Position in the South Central Oklahoma Oil Province (“SCOOP”)
Eagle Rock's Golden Trend field and Southeast Cana leasehold are located in the heart of the South Central Oklahoma Oil Province (“SCOOP”) in Grady, McClain and Garvin Counties, Oklahoma recently highlighted by Continental Resources Inc. and other producers. The Partnership owns approximately 14,000 net acres in the “SCOOP” area that produce from multiple formations including horizontal completions in the Woodford shale. During most of 2012, the Partnership has operated three drilling rigs and participated in third party operated wells in the Golden Trend and Southeast Cana, drilling both vertical tests through multiple formations and horizontal Woodford wells. Eagle Rock's initial operated Southeast Cana horizontal Woodford well, the Beckham 1-27H, is producing to sales and averaged 4.3 MMcfd and 197 Bopd in its first thirty days of production. A second operated well and two non-operated wells are currently drilling, and a third non-operated well is waiting on completion.
“We are excited about both our and the industry's production results from the Woodford horizontal drilling in Southeast Cana”, said Joseph A. Mills, Eagle Rock's Chairman and Chief Executive Officer. “Our Golden Trend field and primary term leasehold in Southeast Cana are extremely well-positioned in the de-risked portion of this extended Woodford horizontal drilling play.”
Third Quarter 2012 Financial and Operating Results
During the fourth quarter of 2011, the East Texas/Louisiana, South Texas and Gulf of Mexico segments were collapsed into a single reporting segment and a new Marketing and Trading reporting segment was 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 2011 to reflect these changes. The Partnership's Upstream segment and functional (Corporate) segments were not affected.
The following discussion of Eagle Rock's operating income by business segment compares the Partnership's financial results in the third quarter of 2012 to those of the second quarter of 2012. The Partnership believes comparing these periods is more illustrative of current operating trends than comparing the current quarter to results achieved in the third quarter of 2011. 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 third quarter of 2012 decreased by approximately $3.8 million compared to the second quarter of 2012. This decrease was due to lower average NGL and condensate realized prices and a 13% decrease in combined equity NGL and condensate volumes. Midstream gathered volumes rose compared to the second quarter as a result of increased volumes in the Partnership's Texas Panhandle segment, which were attributable to a full quarter of service from the Woodall and Phoenix-Arrington Ranch Plants and higher gathering volumes resulting from increased drilling in the area as compared to the second quarter. These gains were offset by lower gathering volumes in the Partnership's East Texas and Other segment, primarily associated with loss of production in the Gulf of Mexico due to Hurricane Isaac, which formed on August 21, 2012, and continued production declines in South Texas.
In the Texas Panhandle, gathered volumes were up approximately 37%, with combined equity NGL and condensate volumes down approximately 15%, compared to the second quarter of 2012. The decline in combined equity NGL and condensate volumes was partially attributable to reduced efficiencies at the Partnership's Phoenix-Arrington Ranch Plant, which was placed back into service on July 2, 2012 after an incident in April 2012 caused the plant to be shut down. Due to re-start issues, however, the Phoenix-Arrington Ranch Plant continues to operate at reduced NGL recovery rates.
Equity volumes were also negatively impacted by constrained processing capacity at the 60 MMcf/d Woodall Plant, located in Hemphill County, Texas, which was placed into service on May 30, 2012. Throughput at the plant peaked at over 45 MMcf/d in early June before Woodall Plant throughput was constrained as a result of a third-party incident on June 5, 2012 involving the residue gas pipeline downstream of Eagle Rock's plant tailgate. The Partnership mitigated this reduced flow by utilizing capacity on a back-up residue outlet but constraints remained on the ability to flow at full capacity. In September, the Partnership connected into a new residue outlet, which has fully alleviated the processing restrictions, and the Woodall Plant is currently running at full capacity. Eagle Rock estimates that its results were negatively impacted by this downstream incident by approximately $2.5 million during the quarter.
The Partnership's Texas Panhandle segment is currently gathering approximately 420 MMcf/d, which consists of 225 MMcf/d attributable to legacy Eagle Rock processing facilities and approximately 195 MMcf/d attributable to the recently acquired BP Texas Panhandle assets.
In the East Texas and Other Midstream segment, gathered volumes were down approximately 7%, with combined equity NGL and condensate volumes also down approximately 7%, compared to the second quarter of 2012. The decrease in gathered volumes and combined equity NGL and condensate volumes was due to natural declines in the production of existing wells, loss of production in the Gulf of Mexico due to Hurricane Isaac, and reduced drilling activity in South Texas. Partially offsetting the declines, gathering volumes around the Partnership's systems servicing the liquids-rich Austin Chalk play in East Texas increased approximately 3% as compared to the second quarter of 2012.
The Partnership's Yscloskey Plant in Louisiana, in which Eagle Rock has a non-operated ownership interest, suffered significant damage from Hurricane Isaac in August 2012. The Yscloskey Plant has been shut down since that time. The Partnership estimates that its results were negatively impacted by approximately $250,000 during the quarter as a consequence of the Yscloskey Plant downtime.
The Marketing and Trading segment includes the financial results of the Partnership's crude oil and condensate marketing, and natural gas marketing and trading operations. Eagle Rock's crude oil and condensate marketing effort was established in 2010 to develop and implement marketing uplift strategies for crude and condensate in Alabama and in the Texas Panhandle. Eagle Rock's natural gas marketing and trading operations were established 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 third quarter of 2012, including intercompany sales and intersegment cost of sales, increased by approximately $337,000, or 52%, compared to the second quarter of 2012, primarily due to higher natural gas prices during the quarter and increased throughput.
In addition, timing of the Partnership's condensate sales in Alabama were negatively impacted by Hurricane Isaac, which made landfall on the coasts of Louisiana and Alabama in August 2012. Due to the storm, all maritime commerce in the region, including barge operations into and out of oil storage and processing facilities such as the Partnership's leased storage at a third-party terminal in Mobile, Alabama, was halted. The storm and subsequent clean-up and repair operations caused Eagle Rock's inventory levels to increase by about 50,000 barrels, which negatively impacted the Partnership's results by approximately $2.8 million during the quarter (recorded in the Corporate Segment as an intercompany elimination). Barge operations resumed during the second week of October, and the Partnership has since sold its excess inventory. Eagle Rock expects its condensate inventory levels to return to normal levels in the fourth quarter.
Upstream Business - Operating income for Eagle Rock's Upstream Business in the third quarter of 2012, excluding the impact of impairments, increased by approximately $5.0 million, or 51%, compared to the second quarter of 2012. The increase was attributable to increased production and lower unit operating costs during the quarter, which were partially offset by lower realized crude oil, NGL and sulfur prices.
Production volumes in the Upstream Business averaged 85.3 MMcfe/d during the quarter, an increase of approximately 3% compared to the second quarter of 2012. The production increase was driven primarily by the Partnership's drilling program in the Mid-Continent and by improved run-times at its Big Escambia Creek facility.
Total capital expenditures for the Upstream Segment in the third quarter were approximately $43.8 million, down by approximately $1.8 million as compared to the second quarter of 2012. Through the third quarter of 2012, the Partnership has spent approximately $8.6 million in capital expenditures related to previously-disclosed upgrades to its Alabama operations in order to fulfill permit obligations and comply with new environmental standards. The Partnership expects to spend a total of approximately $60 million on these upgrades through 2014, inclusive of the $8.6 million spent through the third quarter of 2012.
Corporate Segment - Operating loss for the Corporate segment, excluding the impact of unrealized derivative gains and losses, was $4.3 million for the third quarter of 2012 as compared to a loss of $2.6 million for the second quarter of 2012. The decrease was attributable to lower realized commodity derivative gains and intercompany eliminations for the third quarter, which was partially offset by lower General and Administrative expenses for the quarter compared to the second quarter of 2012.
Total revenue for the third quarter of 2012, excluding the impact of Eagle Rock's realized and unrealized commodity derivative gains and losses, was $198.9 million, up 7% compared with the $186.4 million reported for the second quarter of 2012. The increase in revenue was primarily due to increased sales of natural gas, NGLs, crude oil, condensate and sulfur as compared to the second quarter of 2012. Eagle Rock recorded an unrealized loss on commodity derivatives of $51.3 million in the third quarter 2012, as compared to an unrealized gain on commodity derivatives of $79.5 million in the second quarter 2012. Unrealized gain (loss) on commodity derivatives is a non-cash, mark-to-market amount.
Revenues less cost of goods sold associated with the sale of crude oil, natural gas, NGLs, condensate and sulfur decreased by approximately $1.0 million relative to the second quarter of 2012, driven primarily by lower average realized NGL and crude prices. Adjusted EBITDA for the third quarter of 2012 was $59.1 million, up 3% from the second quarter of 2012, and Distributable Cash Flow was $27.0 million for the third quarter of 2012, down 14% as compared to the second quarter of 2012. The decrease was attributable to higher interest expense following the senior notes issuance in July 2012 and to higher maintenance capital spending. The Partnership recorded $2.8 million of maintenance capital in the third quarter of 2012 related to the Alabama facility upgrades discussed above, relative to $1.5 million of such spending in the second quarter of 2012.
The Partnership recorded a net loss of approximately $106.9 million for the third quarter of 2012, versus net income of $61.8 million for the second quarter of 2012. The net loss was driven primarily by unrealized, non-cash mark-to-market losses totaling $51.3 million on the Partnership's commodity derivative portfolio and by an impairment charge of $55.9 million taken during the quarter. The Partnership incurred impairment charges in its Upstream Business related to its proved properties in the Barnett Shale that experienced reduced revenues resulting from lower natural gas prices and continuing relatively high operating costs associated with gas compression. The Partnership also incurred impairment charges in its Midstream Business primarily related to the substantial damage incurred at the Yscloskey processing plant as a result of Hurricane Isaac in August 2012.
Third Quarter Distribution
On October 24, 2012, the Partnership declared a cash distribution of $0.22 per common and restricted unit for the quarter ended September 30, 2012, equivalent to $0.88 per unit on an annualized basis. This distribution is equal to the distribution paid for the second quarter 2012 and represents a 10% increase over the distribution paid for the third quarter of 2011. The distribution will be paid on Wednesday, November 14, 2012 to unitholders of record as of the close of business on Wednesday, November 7, 2012.
Capitalization and Liquidity Update
Total debt outstanding as of September 30, 2012 was $875.4 million, consisting of $544.4 million of senior unsecured notes (net of an unamortized debt discount of $5.6 million) and borrowings of $331.0 million under the Partnership's senior secured credit facility. Borrowings during the third quarter of 2012 were primarily attributable to capital spending related to the Partnership's Wheeler Plant and Big Escambia Creek facility, new drilling activity in the Mid-Continent, and the $22.8 million deposit made for the BP Acquisition.
On July 13, 2012, the Partnership completed the sale of an additional $250.0 million of 8.375% senior unsecured notes through a private placement exempt from the registration requirements of the Securities Act of 1933. After the original discount of $3.7 million and excluding related offering expenses, the Partnership received net proceeds of approximately $246.3 million, which were used to repay borrowings outstanding under its revolving credit facility. The issuance supplemented the Partnership's prior $300 million of senior notes issued in May 2011, all of which are treated as a single series.
On August 17, 2012, the Partnership completed a public offering of 10,120,000 common units for total net proceeds of approximately $84.5 million. The Partnership used the proceeds to repay outstanding borrowings under its revolving credit facility in advance of funding the BP Acquisition on October 1, 2012. In addition, Eagle Rock issued 691,020 common units in the third quarter of 2012 under its equity shelf program for total net proceeds of approximately $6.1 million.
Availability under the credit facility is subject to a borrowing base comprised of two components: the upstream component and the midstream component. As of September 30, 2012, the Partnership had approximately $328.5 million of availability under its credit facility, based on its outstanding commitments, after taking into account $331 million of outstanding borrowings and approximately $15.6 million of outstanding letters of credit. On October 1, 2012, Eagle Rock borrowed approximately $207.9 million under its credit facility in connection with closing the BP Acquisition.
On October 9, 2012, the Partnership announced that the Upstream Segment component of the borrowing base under its revolving credit facility was increased to $400 million by its commercial lenders as part of its regularly scheduled semi-annual borrowing base redetermination. This represents an increase of $58 million from the previous level of $342 million. The redetermined borrowing base was effective October 1, 2012, with no additional fees or increase in interest rate spread incurred. The total borrowing capacity under the Partnership's credit facility is limited to the lower of the borrowing base and the total lender commitments, which remain unchanged at $675 million.
As of September 30, 2012, the Partnership had 147.4 million units outstanding, including unvested restricted common units outstanding under its Long-Term Incentive Plan.
Hedging Update
The Partnership has entered into the following commodity hedges since its last hedging update on August 1, 2012:
Transaction Date | Product / (Type) | Quantity | Price ($/MMBtu) | Term |
10/1/2012 | HH Natural Gas (Swap) | 150,000 MMbtu/month | $4.36 | Cal. 2015 |
9/25/2012 | WTI Crude (Swap) | 30,000 Bbls/month | $90.65 | Cal. 2014 |
9/25/2012 | WTI Crude (Swap) | 15,000 Bbls/month | $93.50 | Cal. 2013 |
9/24/2012 | HH Natural Gas (Swap) | 400,000 MMbtu/month | $4.02 | Cal. 2014 |
9/24/2012 | HH Natural Gas (Swap) | 300,000 MMbtu/month | $3.62 | Cal. 2013 |
Details of the recent hedging transactions are included in the updated Commodity Hedging Overview presentation Eagle Rock posted on October 31, 2012 to its website. The latest presentation can be accessed by going to www.eaglerockenergy.com: select Investor Relations, then select Presentations.
In July 2012, in conjunction with the Partnership's issuance of $250.0 million of senior unsecured notes, which increased its fixed interest rate exposure, the Partnership terminated the full $200.0 million notional amount of its existing 4.295% and 4.095% fixed rate interest rate swaps at a cost of $3.9 million.
Third Quarter Earnings Conference Call Information
The third quarter 2012 earnings conference call will be held at 2:00 p.m. Eastern Time (1:00 p.m. Central Time) on Thursday, November 1, 2012.
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 43758738. 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 43758738. In addition, a replay of the audio webcast will be available by accessing the Partnership's website after the call is concluded.
About the Partnership
The Partnership is a growth-oriented master limited partnership engaged in two businesses: a) midstream, which includes (i) gathering, compressing, treating, processing and transporting natural gas; (ii) fractionating and transporting natural gas liquids (NGLs); (iii) crude oil logistics and marketing; and (iv) natural gas marketing and trading; and b) upstream, which includes exploiting, developing, and producing hydrocarbons in oil and natural gas properties.
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 the Partnership's 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 crude 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 crude oil and natural gas supply; 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 Securities and Exchange Commission ("SEC") for the year ended December 31, 2011 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 September 30, | Nine Months Ended September 30, | Three Months Ended June 30, 2012 | |||||||||||||||||
2012 | 2011 | 2012 | 2011 | ||||||||||||||||
REVENUE: | |||||||||||||||||||
Natural gas, natural gas liquids, oil, condensate and sulfur sales | $ | 184,494 | $ | 264,119 | $ | 580,152 | $ | 732,491 | $ | 172,945 | |||||||||
Gathering, compression, processing and treating fees | 13,604 | 11,567 | 35,566 | 37,116 | 10,451 | ||||||||||||||
Unrealized commodity derivative (losses) gains | (51,305 | ) | 97,011 | 13,426 | 86,164 | 79,502 | |||||||||||||
Realized commodity derivative gains (losses) | 15,802 | (2,698 | ) | 38,428 | (17,958 | ) | 16,463 | ||||||||||||
Other revenue | 794 | 141 | 3,976 | 1,406 | 3,043 | ||||||||||||||
Total revenue | 163,389 | 370,140 | 671,548 | 839,219 | 282,404 | ||||||||||||||
COSTS AND EXPENSES: | |||||||||||||||||||
Cost of natural gas and natural gas liquids | 110,430 | 166,293 | 338,798 | 486,286 | 97,914 | ||||||||||||||
Operations and maintenance | 27,074 | 24,897 | 81,685 | 66,323 | 27,562 | ||||||||||||||
Taxes other than income | 4,748 | 4,556 | 14,518 | 13,061 | 4,620 | ||||||||||||||
General and administrative | 16,807 | 16,068 | 52,384 | 43,746 | 18,736 | ||||||||||||||
Other operating income | — | — | — | (2,893 | ) | — | |||||||||||||
Impairment | 55,900 | 9,870 | 122,824 | 14,754 | 21,402 | ||||||||||||||
Depreciation, depletion and amortization | 40,395 | 35,040 | 118,043 | 90,314 | 38,354 | ||||||||||||||
Total costs and expenses | 255,354 | 256,724 | 728,252 | 711,591 | 208,588 | ||||||||||||||
OPERATING (LOSS) INCOME | (91,965 | ) | 113,416 | (56,704 | ) | 127,628 | 73,816 | ||||||||||||
OTHER INCOME (EXPENSE): | |||||||||||||||||||
Interest expense, net | (14,199 | ) | (10,050 | ) | (35,087 | ) | (19,579 | ) | (10,647 | ) | |||||||||
Realized interest rate derivative losses | (1,733 | ) | (3,713 | ) | (8,578 | ) | (13,374 | ) | (3,470 | ) | |||||||||
Unrealized interest rate derivative (losses) gains | 615 | (3,165 | ) | 4,418 | 2,191 | 2,007 | |||||||||||||
Other (expense) income, net | 1 | (3 | ) | (44 | ) | (167 | ) | 4 | |||||||||||
Total other income (expense) | (15,316 | ) | (16,931 | ) | (39,291 | ) | (30,929 | ) | (12,106 | ) | |||||||||
(LOSS) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | (107,281 | ) | 96,485 | (95,995 | ) | 96,699 | 61,710 | ||||||||||||
INCOME TAX BENEFIT | (386 | ) | (1,077 | ) | (556 | ) | (1,810 | ) | (79 | ) | |||||||||
(LOSS) INCOME FROM CONTINUING OPERATIONS | (106,895 | ) | 97,562 | (95,439 | ) | 98,509 | 61,789 | ||||||||||||
DISCONTINUED OPERATIONS, NET OF TAX | — | (197 | ) | — | 210 | — | |||||||||||||
NET (LOSS) INCOME | $ | (106,895 | ) | $ | 97,365 | $ | (95,439 | ) | $ | 98,719 | $ | 61,789 | |||||||
Eagle Rock Energy Partners, L.P.
Consolidated Balance Sheets
($ in thousands)
(unaudited)
September 30, 2012 | December 31, 2011 | ||||||
ASSETS | |||||||
CURRENT ASSETS: | |||||||
Cash and cash equivalents | $ | 194 | $ | 877 | |||
Accounts receivable | 96,637 | 97,832 | |||||
Risk management assets | 33,963 | 13,080 | |||||
Prepayments and other current assets | 13,547 | 13,739 | |||||
Total current assets | 144,341 | 125,528 | |||||
PROPERTY, PLANT AND EQUIPMENT - Net | 1,792,414 | 1,763,674 | |||||
INTANGIBLE ASSETS - Net | 85,917 | 109,702 | |||||
DEFERRED TAX ASSET | 1,449 | 1,432 | |||||
RISK MANAGEMENT ASSETS | 14,354 | 24,290 | |||||
OTHER ASSETS | 44,414 | 21,062 | |||||
TOTAL ASSETS | $ | 2,082,889 | $ | 2,045,688 | |||
LIABILITIES AND MEMBERS' EQUITY | |||||||
CURRENT LIABILITIES: | |||||||
Accounts payable | $ | 135,960 | $ | 145,985 | |||
Accrued liabilities | 29,753 | 12,734 | |||||
Taxes payable | 372 | 487 | |||||
Risk management liabilities | 1,396 | 11,649 | |||||
Total current liabilities | 167,481 | 170,855 | |||||
LONG-TERM DEBT | 875,446 | 779,453 | |||||
ASSET RETIREMENT OBLIGATIONS | 35,145 | 33,303 | |||||
DEFERRED TAX LIABILITY | 43,898 | 45,216 | |||||
RISK MANAGEMENT LIABILITIES | 3,012 | 6,893 | |||||
OTHER LONG TERM LIABILITIES | 2,522 | 2,621 | |||||
MEMBERS' EQUITY | 955,385 | 1,007,347 | |||||
TOTAL LIABILITIES AND MEMBERS' EQUITY | $ | 2,082,889 | $ | 2,045,688 | |||
Eagle Rock Energy Partners, L.P.
Segment Summary
Operating Income
($ in thousands)
(unaudited)
Three Months Ended September 30, | Nine Months Ended September 30, | Three Months Ended June 30, 2012 | |||||||||||||||||
2012 | 2011 | 2012 | 2011 | ||||||||||||||||
Midstream | |||||||||||||||||||
Revenues: | |||||||||||||||||||
Natural gas, natural gas liquids, oil and condensate sales | $ | 147,099 | $ | 213,593 | $ | 468,355 | $ | 624,939 | $ | 140,324 | |||||||||
Intercompany sales - natural gas | (2,846 | ) | (1,403 | ) | (7,809 | ) | (1,403 | ) | (2,113 | ) | |||||||||
Gathering and treating services | 13,604 | 11,567 | 35,566 | 37,116 | 10,451 | ||||||||||||||
Other | — | — | 2,864 | — | 2,864 | ||||||||||||||
Total revenue | 157,857 | 223,757 | 498,976 | 660,652 | 151,526 | ||||||||||||||
Cost of natural gas, natural gas liquids, oil and condensate | 110,430 | 166,293 | 338,798 | 486,286 | 97,914 | ||||||||||||||
Intersegment elimination - cost of condensate | 8,598 | 8,825 | 32,612 | 29,817 | 10,383 | ||||||||||||||
Operating costs and expenses: | |||||||||||||||||||
Operations and maintenance | 17,647 | 16,716 | 53,178 | 48,081 | 18,164 | ||||||||||||||
Impairment | 35,840 | — | 101,979 | 4,560 | 20,617 | ||||||||||||||
Depreciation, depletion and amortization | 16,488 | 16,093 | 49,735 | 48,250 | 16,565 | ||||||||||||||
Total operating costs and expenses | 69,975 | 32,809 | 204,892 | 100,891 | 55,346 | ||||||||||||||
Operating (loss) income from continuing operations | (31,146 | ) | 15,830 | (77,326 | ) | 43,658 | (12,117 | ) | |||||||||||
Discontinued Operations (1) | — | (197 | ) | — | (194 | ) | — | ||||||||||||
Operating (loss) income | $ | (31,146 | ) | $ | 15,633 | $ | (77,326 | ) | $ | 43,464 | $ | (12,117 | ) | ||||||
Upstream (2) | |||||||||||||||||||
Revenues: | |||||||||||||||||||
Oil and condensate sales | $ | 14,376 | $ | 17,269 | $ | 44,088 | $ | 33,799 | $ | 12,247 | |||||||||
Intersegment sales - condensate | 11,431 | 7,451 | 34,226 | 29,975 | 10,306 | ||||||||||||||
Natural gas sales (3) | 8,324 | 16,014 | 22,474 | 31,294 | 6,832 | ||||||||||||||
Intersegment sales - natural gas | 2,846 | 1,403 | 7,809 | 1,403 | 2,113 | ||||||||||||||
Natural gas liquids sales (4) | 10,979 | 12,186 | 34,060 | 29,678 | 10,340 | ||||||||||||||
Sulfur sales (5) | 3,716 | 5,057 | 11,175 | 12,781 | 3,202 | ||||||||||||||
Other | 794 | 141 | 1,112 | 1,406 | 179 | ||||||||||||||
Total revenue | 52,466 | 59,521 | 154,944 | 140,336 | 45,219 | ||||||||||||||
Operating costs and expenses: | |||||||||||||||||||
Operations and maintenance (1) | 14,175 | 12,737 | 43,025 | 31,369 | 14,018 | ||||||||||||||
Impairment | 20,060 | 9,870 | 20,845 | 10,194 | 785 | ||||||||||||||
Depreciation, depletion and amortization | 23,484 | 18,636 | 67,070 | 41,046 | 21,366 | ||||||||||||||
Total operating costs and expenses | 57,719 | 41,243 | 130,940 | 82,609 | 36,169 | ||||||||||||||
Operating (loss) income | $ | (5,253 | ) | $ | 18,278 | $ | 24,004 | $ | 57,727 | $ | 9,050 | ||||||||
Corporate and Other | |||||||||||||||||||
Revenues: | |||||||||||||||||||
Unrealized commodity derivative (losses) gains | $ | (51,305 | ) | $ | 97,011 | $ | 13,426 | $ | 86,164 | $ | 79,502 | ||||||||
Realized commodity derivative gains (losses) | 15,802 | (2,698 | ) | 38,428 | (17,958 | ) | 16,463 | ||||||||||||
Intersegment elimination - sales of condensate | (11,431 | ) | (7,451 | ) | (34,226 | ) | (29,975 | ) | (10,306 | ) | |||||||||
Total revenue | (46,934 | ) | 86,862 | 17,628 | 38,231 | 85,659 | |||||||||||||
Costs and expenses: | |||||||||||||||||||
Intersegment elimination - cost of condensate | (8,598 | ) | (8,825 | ) | (32,612 | ) | (29,817 | ) | (10,383 | ) | |||||||||
General and administrative | 16,807 | 16,068 | 52,384 | 43,746 | 18,736 | ||||||||||||||
Intersegment elimination - operations and maintenance | — | — | — | (66 | ) | — | |||||||||||||
Other operating Income | — | — | — | (2,893 | ) | — | |||||||||||||
Depreciation, depletion and amortization | 423 | 311 | 1,238 | 1,018 | 423 | ||||||||||||||
Operating (loss) income | $ | (55,566 | ) | $ | 79,308 | $ | (3,382 | ) | $ | 26,243 | $ | 76,883 | |||||||
____________________
(1) | Includes natural gas sales of $66 from the East Texas and Other Midstream Texas Segment to the Upstream Segment for the nine months ended September 30, 2011, respectively. |
(2) | Includes operations related to the Crow Creek Acquisition starting on May 3, 2011. |
(3) | Revenues include a change in the value of product imbalances of $18, $(37), $(38) and $22 for the three and nine months ended September 30, 2012 and 2011, respectively, and $(49) for the three months ended June 30, 2012. |
(4) | Revenues include a change in the value of product imbalances of $(215) , $(301), $270 and $155 for the three and nine months ended September 30, 2012 and 2011, respectively, and $(257) for the three months ended June 30, 2012. |
(5) | Revenues include a change in the value of product imbalances of $(32) , $0, $(125) and $(54) for the three and nine months ended September 30, 2012 and 2011, respectively, and $(2) for the three months ended June 30, 2012. |
Eagle Rock Energy Partners, L.P.
Midstream Segment
Operating Income
($ in thousands)
(unaudited)
Three Months Ended September 30, | Nine Months Ended September 30, | Three Months Ended June 30, 2012 | |||||||||||||||||
2012 | 2011 | 2012 | 2011 | ||||||||||||||||
Texas Panhandle | |||||||||||||||||||
Revenues: | |||||||||||||||||||
Natural gas, natural gas liquids, oil and condensate sales | $ | 60,213 | $ | 90,420 | $ | 189,230 | $ | 304,813 | $ | 55,937 | |||||||||
Intersegment sales - natural gas and condensate | 28,025 | 26,247 | 72,514 | 26,247 | 19,043 | ||||||||||||||
Gathering, compression, processing and treating services | 4,708 | 4,892 | 13,510 | 12,905 | 3,852 | ||||||||||||||
Other | — | — | 2,864 | — | 2,864 | ||||||||||||||
Total revenue | 92,946 | 121,559 | 278,118 | 343,965 | 81,696 | ||||||||||||||
Cost of natural gas, natural gas liquids, oil and condensate | 67,098 | 87,797 | 189,703 | 247,512 | 51,117 | ||||||||||||||
Operating costs and expenses: | |||||||||||||||||||
Operations and maintenance | 12,705 | 10,826 | 37,342 | 31,434 | 12,399 | ||||||||||||||
Impairment | — | — | — | 4,560 | — | ||||||||||||||
Depreciation, depletion and amortization | 10,164 | 9,145 | 29,554 | 27,382 | 9,873 | ||||||||||||||
Total operating costs and expenses | 22,869 | 19,971 | 66,896 | 63,376 | 22,272 | ||||||||||||||
Operating income | $ | 2,979 | $ | 13,791 | $ | 21,519 | $ | 33,077 | $ | 8,307 | |||||||||
East Texas and Other Midstream | |||||||||||||||||||
Revenues: | |||||||||||||||||||
Natural gas, natural gas liquids, oil and condensate sales | $ | 26,130 | $ | 59,590 | $ | 98,398 | $ | 193,785 | $ | 30,998 | |||||||||
Intercompany sales - natural gas | 10,020 | 4,330 | 26,471 | 4,330 | 6,928 | ||||||||||||||
Gathering, compression, processing and treating services | 8,896 | 6,675 | 22,056 | 24,211 | 6,599 | ||||||||||||||
Total revenue | 45,046 | 70,595 | 146,925 | 222,326 | 44,525 | ||||||||||||||
Cost of natural gas and natural gas liquids and condensate | 33,145 | 56,536 | 111,203 | 176,202 | 32,550 | ||||||||||||||
Operating costs and expenses: | |||||||||||||||||||
Operations and maintenance | 4,940 | 5,888 | 15,833 | 16,645 | 5,764 | ||||||||||||||
Impairment | 35,840 | — | 101,979 | — | 20,617 | ||||||||||||||
Depreciation, depletion and amortization | 6,232 | 6,948 | 20,034 | 20,868 | 6,667 | ||||||||||||||
Total operating costs and expenses | 47,012 | 12,836 | 137,846 | 37,513 | 33,048 | ||||||||||||||
Operating income (loss) from continuing operations | (35,111 | ) | 1,223 | (102,124 | ) | 8,611 | (21,073 | ) | |||||||||||
Discontinued Operations | — | (197 | ) | — | (194 | ) | — | ||||||||||||
Operating income (loss) | $ | (35,111 | ) | $ | 1,026 | $ | (102,124 | ) | $ | 8,417 | $ | (21,073 | ) | ||||||
Marketing and Trading | |||||||||||||||||||
Revenues: | |||||||||||||||||||
Natural gas, oil and condensate sales | $ | 60,756 | $ | 63,583 | $ | 180,727 | $ | 126,341 | $ | 53,389 | |||||||||
Intercompany sales - natural gas and condensate | (40,891 | ) | (31,980 | ) | (106,794 | ) | (31,980 | ) | (28,084 | ) | |||||||||
Total revenue | 19,865 | 31,603 | 73,933 | 94,361 | 25,305 | ||||||||||||||
Cost of natural gas and natural gas liquids | 10,187 | 21,960 | 37,892 | 62,572 | 14,247 | ||||||||||||||
Intersegment cost of sales - condensate | 8,598 | 8,825 | 32,612 | 29,817 | 10,383 | ||||||||||||||
Operating costs and expenses: | |||||||||||||||||||
Operations and maintenance | 2 | 2 | 3 | 2 | 1 | ||||||||||||||
Depreciation, depletion and amortization | 92 | — | 147 | — | 25 | ||||||||||||||
Total operating costs and expenses | 94 | 2 | 150 | 2 | 26 | ||||||||||||||
Operating income | $ | 986 | $ | 816 | $ | 3,279 | $ | 1,970 | $ | 649 | |||||||||
Eagle Rock Energy Partners, L.P.
Midstream Operations Information
(unaudited)
Three Months Ended September 30, | Nine Months Ended September 30, | Three Months Ended June 30, 2012 | |||||||||||||||||
2012 | 2011 | 2012 | 2011 | ||||||||||||||||
Gas gathering volumes - (Average Mcf/d) | |||||||||||||||||||
Texas Panhandle | 183,415 | 163,665 | 159,229 | 154,011 | 133,590 | ||||||||||||||
East Texas and Other Midstream | 248,094 | 312,103 | 268,512 | 331,003 | 265,472 | ||||||||||||||
Total | 431,509 | 475,768 | 427,741 | 485,014 | 399,062 | ||||||||||||||
NGLs - (Net equity Bbls) | |||||||||||||||||||
Texas Panhandle (1) | 228,696 | 231,965 | 855,499 | 609,097 | 297,688 | ||||||||||||||
East Texas and Other Midstream | 81,997 | 114,280 | 258,322 | 345,255 | 84,981 | ||||||||||||||
Total | 310,693 | 346,245 | 1,113,821 | 954,352 | 382,669 | ||||||||||||||
Condensate - (Net equity Bbls) | |||||||||||||||||||
Texas Panhandle (1) | 164,246 | 260,228 | 499,660 | 728,860 | 163,320 | ||||||||||||||
East Texas and Other Midstream | 7,010 | 10,519 | 28,737 | 35,426 | 10,403 | ||||||||||||||
Total | 171,256 | 270,747 | 528,397 | 764,286 | 173,723 | ||||||||||||||
Natural gas short position - (Average MMbtu/d) | |||||||||||||||||||
Texas Panhandle | (990 | ) | (7,418 | ) | (4,661 | ) | (5,517 | ) | (5,629 | ) | |||||||||
East Texas and Other Midstream | 392 | 1,758 | 1,482 | 1,963 | 3,952 | ||||||||||||||
Total | (598 | ) | (5,660 | ) | (3,179 | ) | (3,554 | ) | (1,677 | ) | |||||||||
Average realized NGL price - per Bbl | |||||||||||||||||||
Texas Panhandle | $ | 36.23 | $ | 53.39 | $ | 39.55 | $ | 55.28 | $ | 38.30 | |||||||||
East Texas and Other Midstream | $ | 32.24 | $ | 52.57 | $ | 39.45 | $ | 51.13 | $ | 39.72 | |||||||||
Weighted Average | $ | 34.89 | $ | 53.08 | $ | 39.51 | $ | 53.51 | $ | 38.85 | |||||||||
Average realized condensate price - per Bbl | |||||||||||||||||||
Texas Panhandle | $ | 81.08 | $ | 79.43 | $ | 86.74 | $ | 82.31 | $ | 82.29 | |||||||||
East Texas and Other Midstream | $ | 91.57 | $ | 93.82 | $ | 100.66 | $ | 94.28 | $ | 103.71 | |||||||||
Total | $ | 81.82 | $ | 79.74 | $ | 87.94 | $ | 83.31 | $ | 83.90 | |||||||||
Average realized natural gas price - per MMbtu | |||||||||||||||||||
Texas Panhandle | $ | 2.64 | $ | 3.86 | $ | 2.37 | $ | 3.95 | $ | 1.93 | |||||||||
East Texas and Other Midstream | $ | 2.85 | $ | 4.36 | $ | 2.67 | $ | 4.42 | $ | 2.22 | |||||||||
Total | $ | 2.71 | $ | 4.05 | $ | 2.48 | $ | 4.14 | $ | 2.04 | |||||||||
(1) | Effective January 2012, reported NGL volumes include those volumes recovered from our equity condensate through stabilization. These NGL volumes were previously reported as condensate. This change results in an increase to reported NGLs equity barrels and a corresponding decrease to reported condensate equity barrels. |
Eagle Rock Energy Partners, L.P.
Upstream Operations Information
(unaudited)
Three Months Ended September 30, | Nine Months Ended September 30, | Three Months Ended June 30, 2012 | |||||||||||||||||
2012 | 2011 | 2012 | 2011 | ||||||||||||||||
Upstream | |||||||||||||||||||
Production: | |||||||||||||||||||
Oil and condensate (Bbl) | 310,349 | 302,766 | 900,873 | 772,350 | 266,580 | ||||||||||||||
Gas (Mcf) | 4,177,156 | 4,274,811 | 12,614,258 | 8,272,176 | 4,341,298 | ||||||||||||||
NGLs (Bbl) | 301,644 | 227,614 | 848,047 | 533,223 | 267,673 | ||||||||||||||
Total Mcfe | 7,849,113 | 7,457,091 | 23,107,779 | 16,105,615 | 7,546,811 | ||||||||||||||
Sulfur (long ton) | 28,414 | 27,706 | 79,111 | 71,509 | 21,705 | ||||||||||||||
Realized prices, excluding derivatives: (1) | |||||||||||||||||||
Oil and condensate (per Bbl) | $ | 83.16 | $ | 81.65 | $ | 86.93 | $ | 82.57 | $ | 84.60 | |||||||||
Gas (Mcf) | $ | 2.67 | $ | 4.08 | $ | 2.40 | $ | 3.95 | $ | 2.06 | |||||||||
NGLs (Bbl) | $ | 36.40 | $ | 52.35 | $ | 40.16 | $ | 55.37 | $ | 38.63 | |||||||||
Sulfur (long ton) | $ | 130.77 | $ | 187.03 | $ | 141.27 | $ | 179.48 | $ | 147.55 | |||||||||
Operating statistics: | |||||||||||||||||||
Operating costs per Mcfe (incl production taxes) (2) | $ | 1.60 | $ | 1.57 | $ | 1.69 | $ | 1.88 | $ | 1.68 | |||||||||
Operating costs per Mcfe (excl production taxes) (2) | $ | 1.11 | $ | 1.07 | $ | 1.18 | $ | 1.23 | $ | 1.18 | |||||||||
Operating income per Mcfe | $ | (0.67 | ) | $ | 2.45 | $ | 1.04 | $ | 3.58 | $ | 1.20 | ||||||||
Drilling program (gross wells): | |||||||||||||||||||
Development wells | 6 | 13 | 25 | 32 | 9 | ||||||||||||||
Completions | 6 | 13 | 25 | 32 | 9 | ||||||||||||||
Workovers | 10 | 5 | 19 | 13 | 4 | ||||||||||||||
Recompletions | 4 | 4 | 7 | 8 | 1 | ||||||||||||||
______________________
(1) | Calculation does not include impact of product imbalances. |
(2) | Excludes post-production costs of $1,601 and $4,068 for the three and nine months ended September 30, 2012, respectively, $1,031 for both the three and nine months ended September 30, 2011 and $1,319 for the three months ended June 30, 2012. |
Non-GAAP Financial Measures
The following tables present a reconciliation of the non-GAAP financial measures of Adjusted EBITDA and Distributable Cash Flow to the GAAP financial measure of net income for each of the periods indicated (in thousands).
Eagle Rock Energy Partners, L.P.
GAAP to Non-GAAP Reconciliations
($ in thousands)
(unaudited)
Three Months Ended September 30, | Nine Months Ended September 30, | Three Months Ended June 30, 2012 | |||||||||||||||||
2012 | 2011 | 2012 | 2011 | ||||||||||||||||
Net (loss) income to Adjusted EBITDA | |||||||||||||||||||
Net (loss) income, as reported | $ | (106,895 | ) | $ | 97,365 | $ | (95,439 | ) | $ | 98,719 | $ | 61,789 | |||||||
Depreciation, depletion and amortization | 40,395 | 35,040 | 118,043 | 90,314 | 38,354 | ||||||||||||||
Impairment | 55,900 | 9,870 | 122,824 | 14,754 | 21,402 | ||||||||||||||
Risk management interest related instruments - unrealized | (615 | ) | 3,165 | (4,418 | ) | (2,191 | ) | (2,007 | ) | ||||||||||
Risk management commodity related instruments - unrealized | 51,305 | (97,011 | ) | (13,426 | ) | (86,164 | ) | (79,502 | ) | ||||||||||
Other Operating Income | — | — | — | (2,893 | ) | — | |||||||||||||
Non-cash mark-to-market of Upstream product imbalances | 229 | (107 | ) | 338 | (123 | ) | 307 | ||||||||||||
Unrealized losses (gains) from other derivative activity | 157 | (538 | ) | 427 | (538 | ) | 473 | ||||||||||||
Restricted units non-cash amortization expense | 3,080 | 1,507 | 8,092 | 3,441 | 2,818 | ||||||||||||||
Income tax (benefit) provision | (386 | ) | (1,077 | ) | (556 | ) | (1,810 | ) | (79 | ) | |||||||||
Interest - net including realized risk management instruments and other expense | 15,931 | 13,766 | 43,709 | 33,120 | 14,113 | ||||||||||||||
Other income | — | — | — | — | — | ||||||||||||||
Discontinued operations | — | 197 | — | (210 | ) | — | |||||||||||||
Adjusted EBITDA | $ | 59,101 | $ | 62,177 | $ | 179,594 | $ | 146,419 | $ | 57,668 | |||||||||
Net (loss) income to Distributable Cash Flow | |||||||||||||||||||
Net (loss) income, as reported | $ | (106,895 | ) | $ | 97,365 | $ | (95,439 | ) | $ | 98,719 | $ | 61,789 | |||||||
Depreciation, depletion and amortization expense | 40,395 | 35,040 | 118,043 | 90,314 | 38,354 | ||||||||||||||
Impairment | 55,900 | 9,870 | 122,824 | 14,754 | 21,402 | ||||||||||||||
Risk management interest related instruments-unrealized | (615 | ) | 3,165 | (4,418 | ) | (2,191 | ) | (2,007 | ) | ||||||||||
Risk management commodity related instruments and other derivative activity - unrealized | 51,462 | (97,549 | ) | (12,999 | ) | (86,702 | ) | (79,029 | ) | ||||||||||
Capital expenditures-maintenance related | (15,982 | ) | (11,980 | ) | (35,824 | ) | (30,311 | ) | (11,816 | ) | |||||||||
Non-cash mark-to-market of Upstream product imbalances | 229 | (107 | ) | 338 | (123 | ) | 307 | ||||||||||||
Restricted units non-cash amortization expense | 3,080 | 1,507 | 8,092 | 3,441 | 2,818 | ||||||||||||||
Other Operating Income | — | — | — | (2,893 | ) | — | |||||||||||||
Income tax (benefit) provision | (386 | ) | (1,077 | ) | (556 | ) | (1,810 | ) | (79 | ) | |||||||||
Cash income taxes | (185 | ) | (325 | ) | (749 | ) | (802 | ) | (189 | ) | |||||||||
Discontinued operations | — | 197 | — | (210 | ) | — | |||||||||||||
Distributable Cash Flow | $ | 27,003 | $ | 36,106 | $ | 99,312 | $ | 82,186 | $ | 31,550 | |||||||||
###