Attached files
| file | filename |
|---|---|
| 8-K - 8-K - EAGLE ROCK ENERGY PARTNERS L P | form8-kq42013earningsrelea.htm |
| EX-10.1 - EXHIBIT 10.1 - EAGLE ROCK ENERGY PARTNERS L P | exhibit101thirdamendmentq4.htm |
Exhibit 99.1
February 26, 2014
Eagle Rock Reports Fourth Quarter and Year End 2013 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 2013 and three months ended December 31, 2013. Financial results with respect to fourth quarter 2013 included the following:
• | Reported Adjusted EBITDA of $57.4 million, a decrease of approximately 10% as compared to the $63.5 million reported for the third quarter of 2013, driven by the impact of severe winter weather in both its Midstream and Upstream Businesses (approximately $4.6 million) and lower crude oil and condensate prices as compared to Q3 2013. |
• | Reported Distributable Cash Flow of $18.5 million as compared to the $25.6 million reported for the third quarter of 2013, with the decrease primarily driven by the same factors impacting Adjusted EBITDA and slightly higher maintenance capital expenditures. |
• | Reported a Net Loss of $168.9 million, which in addition to the factors mentioned above was driven by impairment charges in its Upstream Business, primarily related to the Partnership’s positions in the Cana Shale. |
Adjusted EBITDA and Distributable Cash Flow exclude the impact of general and administrative expenses incurred in connection with the Partnership’s strategic review and Midstream Business Contribution (as defined below), which is consistent with the calculation of Consolidated EBITDA under its senior secured credit facility.
Other notable financial and operational activities of the Partnership for the fourth quarter of 2013 included the following:
• | Announced the execution of a definitive agreement on December 23, 2013, to contribute its Midstream Business to Regency Energy Partners, L.P. (“Regency”) for total consideration of up to $1.325 billion. |
• | Announced a quarterly distribution with respect to the fourth quarter of 2013 of $0.15 per common unit, equal to the third quarter 2013 distribution. |
• | Amended its senior secured credit facility to provide covenant relief and additional liquidity through the closing of the transaction with Regency. |
For the full year 2013, Eagle Rock generated $230.3 million of Adjusted EBITDA, a decrease of 6% from the $245.8 million reported for the full year 2012. The decrease in 2013 was primarily due to lower realized NGL and sulfur prices, lower Upstream natural gas production, and higher general and administrative and operating expenses.
Update Regarding Contribution of Midstream Business
The consummation of the Partnership’s contribution of its Midstream Business to Regency (the “Midstream Business Contribution”) is expected to close in the second quarter of 2014, subject to regulatory and unitholder approvals, as well as other customary conditions. The Partnership filed a preliminary Proxy Statement with the Securities and Exchange Commission (SEC) on January 31, 2014.
The Partnership intends to use the cash proceeds from the Midstream Business Contribution to pay down borrowings under its revolving credit facility. In advance of closing, Regency will conduct an exchange offer for the full $550 million face amount of the Partnership’s senior unsecured notes. Assuming all of the senior unsecured notes are exchanged, Eagle Rock expects to reduce its total debt by over $1 billion as a result of the Midstream Business Contribution. Following the consummation of the transaction, Eagle Rock will be a pure-play upstream MLP with a strong balance sheet, improved credit metrics and greater liquidity for future growth.
Year-End Upstream Proved Reserves
Eagle Rock estimates its proved reserves at year-end 2013 totaled 57.7 MMBoe, essentially unchanged from year-end 2012. Total production for 2013 was 4.51 MMBoe, or 12.4 Mboe/d, a decrease of 11% from total production in 2012. This decrease was due in part to the Partnership’s drilling focus on crude oil and NGLs during 2013 as compared to drilling for natural gas targets in 2012 and the Partnership’s sale of its Barnett Shale assets in the fourth quarter 2012. While natural gas production volumes declined from 2012 levels, both crude oil and NGL production increased by more than 3% year over year. The Partnership’s extensions and discoveries in 2013 were 10.7 MMBoe, which represents a production replacement rate of 238%. Total year-end reserves were flat to 2012 due primarily to moving certain undeveloped natural gas focused well locations from proved to probable reserves as current expectations for future natural gas prices do not support their development in the next five years. In 2013, the Partnership developed 5.5 MMBoe of reserves at a unit development cost of $20.34/Boe. As of December 31, 2013, approximately 74% of the Partnership’s total proved reserves were classified as proved developed.
Update on Upstream Drilling Activity
During 2013, the Partnership participated in the drilling and completion of 45 total wells, of which 14 were operated by the Partnership. Drilling activity was concentrated in the Mid-Continent region, primarily in the Golden Trend field and Cana Southeast Shale plays (also known as the SCOOP play) of western Oklahoma. In addition, during 2013, the Partnership participated in recompletion and workover projects on 42 wells, of which 38 were operated by the Partnership.
Fourth Quarter 2013 Financial and Operating Results
The Partnership’s financial results are reported in the following segments: (a) the Midstream Business -- Texas Panhandle; (b) the Midstream Business -- East Texas and Other Midstream; (c) the Midstream Business -- Marketing and Trading; (d) the Upstream Business; and (e) the Corporate Segment.
The following discussion of the Partnership's operating income by business segment compares the Partnership's financial results in the fourth quarter of 2013 to those of the third quarter of 2013. Please refer to the financial tables at the end of this release for further detailed information.
Midstream Business - Operating income for the Midstream Business in the fourth quarter of 2013 decreased by approximately $0.9 million, or 7%, compared to the third quarter of 2013. This decrease was primarily attributable to lower equity NGL volumes and lower realized condensate prices, and was partially offset by slightly higher natural gas and NGL prices.
In the Texas Panhandle, gathered volumes and combined equity NGL and condensate volumes were in line with third quarter volumes despite the impact of the severe winter weather experienced
in November and December. The severe weather caused shut-ins and prolonged reduced flow from many of the producing wells in the Partnership’s Texas Panhandle segment as well as delays by producers in hooking up new wells to the Partnership’s gathering systems and also caused reduced recovery efficiencies at the Partnership’s processing facilities. The Partnership estimates the severe weather negatively impacted operating income from the Texas Panhandle in excess of $3.0 million in the fourth quarter of 2013.
In the Partnership’s East Texas and Other Midstream segment, gathered volumes were up 3%, with combined equity NGL and condensate volumes down compared to the third quarter of 2013, on a reported basis. The increase in gathered volumes was due to increased dedicated production around the Partnership’s systems servicing the liquids-rich Woodbine formation in East Texas. Excluding fourth quarter adjustments made to true-up third quarter actual NGL settlements, combined equity NGL and condensate volumes for the fourth quarter of 2013 were down 82%, as compared to the third quarter of 2013, primarily due to the Partnership’s decision to reject ethane at its Brookeland Plant for the entire fourth quarter versus its decision to reject ethane for only a portion of the third quarter. Under certain fixed recovery contracts at the Brookeland and Tyler County plants in East Texas, the Partnership pays the underlying producers a specified percent of the ethane in the well stream even if the ethane is not recovered. This can result in Eagle Rock having a short position in ethane. Eagle Rock’s decision to reject ethane is an economic decision based on the Partnership’s contract portfolio and the price spread between ethane and natural gas.
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. Operating income for the Marketing and Trading segment in the fourth quarter of 2013, including intercompany sales and intersegment cost of sales, increased by approximately $1.7 million compared to the third quarter of 2013.
Upstream Business - Operating income for Eagle Rock's Upstream Business in the fourth quarter of 2013, excluding the impact of impairments, decreased by approximately $5.1 million, or 27%, compared to the third quarter of 2013. The decrease was primarily due to lower realized crude oil and sulfur prices, and increased operating costs. Production volumes in the Upstream Business averaged 75.5 MMcfe/d during the quarter, in line with third quarter 2013 production volumes, despite the negative impact of the severe winter weather. The severe weather caused power outages, facility freeze-ups, completion delays, along with pipeline and trucking curtailments at certain producing wells in the Partnership’s Texas, Oklahoma and Alabama properties during the quarter. The Partnership estimates the financial impact of the winter weather in the fourth quarter at approximately $1.6 million. Eagle Rock recorded an impairment of $151.1 million in the fourth quarter of 2013 related to its Upstream Business resulting from lower reserve forecasts for certain proved properties and from moving certain undeveloped well locations from proved to probable reserves primarily due to the uncertainty of their development over the next five years, primarily in the Cana Shale in the Mid-Continent.
Corporate Segment - Operating loss for the Corporate segment, excluding the impact of unrealized derivative gains and losses, was $19.2 million for the fourth quarter of 2013 as compared to a $17.6 million loss for the third quarter of 2013. The increased loss was primarily attributable to a $1.9 million increase in General and Administrative expenses and a decrease in net intercompany eliminations, partially offset by a $1.7 million increase in realized commodity derivative gains. The increase in General and Administrative expenses was due to approximately $4.0 million in costs incurred in connection with the Partnership’s strategic review and Midstream Business Contribution.
These costs are considered non-recurring and have been excluded from the calculation of Adjusted EBITDA and Distributable Cash Flow.
Total revenue for the fourth quarter of 2013, including the impact of Eagle Rock's realized and unrealized commodity derivative gains and losses, was $316.2 million, up 5% compared with the $301.2 million reported for the third quarter of 2013. The increase in revenue was primarily due to lower unrealized losses on commodity derivatives compared to the third quarter of 2013. Eagle Rock recorded an unrealized loss on commodity derivatives of $8.7 million in the fourth quarter 2013, as compared to an unrealized loss on commodity derivatives of $29.6 million in the third quarter 2013. Unrealized gain (loss) on commodity derivatives is a non-cash, mark-to-market amount.
Revenues associated with the sale of crude oil, natural gas, NGLs, condensate, sulfur and helium were down 2.6% in the fourth quarter of 2013 relative to the third quarter of 2013, driven primarily by lower average received condensate and sulfur prices. Adjusted EBITDA was $57.4 million, down 10% from the third quarter of 2013, and Distributable Cash Flow was $18.5 million for the fourth quarter of 2013, down 28% as compared to the third quarter of 2013. The decrease in Distributable Cash Flow was primarily attributable to lower Adjusted EBITDA and slightly higher maintenance capital expenditures in the fourth quarter. The Partnership recorded $19.5 million of maintenance capital in the fourth quarter of 2013, an increase of $0.7 million as compared to the third quarter of 2013.
The Partnership recorded a net loss of approximately $168.9 million for the fourth quarter of 2013, which was primarily driven by the impairment charge in its Upstream Business and unrealized commodity derivative losses.
Fourth Quarter Distribution
On January 27, 2014, the Partnership declared a cash distribution on common units (including eligible restricted common units) of $0.15 per unit for the quarter ended December 31, 2013, equivalent to $0.60 per unit on an annualized basis. This distribution is equal to the distribution paid for the third quarter 2013. As declared, the distribution was paid on Friday, February 14, 2014, on common and eligible restricted units and to unitholders of record as of the close of business on Friday, February 7, 2014.
Full Year 2013 Financial and Operating Results
Total revenue for 2013, including the impact of Eagle Rock's realized and unrealized derivative gains and losses, was $1.2 billion, up 21.5% compared with $984.0 million reported for 2012. The largest contributor to the increase in total revenue was the revenues associated with the sale of natural gas, NGLs, oil, condensate, sulfur and helium, which were up 31% relative to those in 2012. In addition, fee revenues associated with gathering, compression, processing and treating were up approximately 47% relative to those of 2012. Total revenue in 2013 included a realized gain on commodity derivatives of $25.4 million, as compared to a realized gain of $51.3 million in 2012. The Partnership recorded an unrealized loss on commodity derivatives of $43.9 million in 2013, as compared to an unrealized gain on commodity derivatives of $6.6 million in 2012.
Adjusted EBITDA was $230.3 million and Distributable Cash Flow was $89.1 million in 2013 as compared to $245.8 million and $129.0 million, respectively, in 2012. The Partnership recorded a net loss of approximately $278.0 million for the full year of 2013, versus net loss of $150.6 million
for the full year of 2012. Net loss for the year excluding the impact of impairments and unrealized gains or losses was approximately $19.8 million.
With regard to the Partnership's Midstream Business operations, gas gathering volumes in 2013 were up 20.8% as compared to 2012, primarily due to the BP Acquisition which closed on October 1, 2012. Combined NGL and condensate volumes were down 12.1%, as compared to 2012, primarily due to increased ethane rejection in 2013 and the change in the Partnership’s contract portfolio resulting from the fixed recovery contracts that were acquired in the BP Acquisition. With regard to prices, the Midstream Business realized higher condensate and natural gas prices in 2013 relative to 2012 and realized lower NGL prices relative to 2012.
With regard to the Partnership's Upstream Business operations, total production was down 10.6% as compared to production in 2012. In 2013 natural gas production was lower by 10 MMcfd (22%) primarily due to the sale of the Partnership’s Barnett assets, decline in the Cana Shale play, and increased fuel use associated with the Partnership’s Alabama sulfur treating process. Both condensate and NGL production were higher, boosted by the Partnership’s drilling activity in the liquids-rich Golden Trend and SCOOP plays. With regard to prices, the Upstream Business realized higher crude oil and condensate and natural gas prices in 2013 relative to 2012 and realized lower NGL and sulfur prices relative to 2012.
Capitalization and Liquidity Update
Total debt outstanding as of December 31, 2013 was $1.25 billion, consisting of $545.3 million of senior unsecured notes (net of an unamortized debt discount of $4.7 million) and borrowings of $706.8 million under the Partnership's senior secured credit facility. Total debt increased during the fourth quarter of 2013 primarily due to borrowings to fund growth capital expenditures associated with Midstream well connects and the Partnership’s Upstream drilling program.
The Partnership is in compliance with its financial covenants and has no maturities under its senior secured credit facility until June 2016. Availability under the Partnership’s senior secured credit facility is subject to a borrowing base comprised of two components: the upstream component and the midstream component.
The Partnership entered into an amended credit agreement with its lender group which goes effective today and allows for greater liquidity under the senior secured credit facility and for greater covenant flexibility for the first quarter of 2014. Specifically, the amendment provides for:
• | An increase in the Total Leverage Ratio and Senior Secured Leverage Ratio (as defined in the Credit Agreement) to 5.85x and 3.40x, respectively, for the quarter ended March 31, 2014; |
• | The exclusion of fees and expenses associated with the strategic review and disposition of the Partnership’s Midstream Business from the calculation of Consolidated EBITDA (as defined in the Credit Agreement); |
• | Deferring the redetermination of the Upstream Borrowing Base until June 1, 2014; and |
• | The option for the Partnership, at its election, to expand the multiplier for the Midstream Borrowing Base from 3.75x to 4.00x for the four-quarter periods ended December 31, 2013 and March 31, 2014. |
The Partnership paid a nominal upfront fee to its lenders in connection with the amendment, and has agreed to increase its borrowing rate from the current level of LIBOR+275 basis points to LIBOR+300 basis points upon the earlier to occur of (i) the Partnership’s election to expand its
Midstream Borrowing Base multiplier and (ii) April 1, 2014, through the closing of the Midstream Business Contribution.
As of December 31, 2013, after taking into account the amendment, the Partnership had approximately $56.6 million of availability under its senior secured credit facility, based on its outstanding commitments, after taking into account $706.8 million of outstanding borrowings and approximately $19.2 million of outstanding letters of credit. Availability would increase to approximately $83.4 million if the Partnership elected to expand the multiplier for the Midstream Borrowing Base.
Excluding acquisitions or the potential divestiture of the Partnership’s Midstream Business, the current capital budget for 2014 is approximately $188 million, which includes $61 million allocated to the Midstream Business and $124 million allocated to the Upstream Business (with the remainder allocated to general corporate purposes). Approximately $76 million of the total capital budgeted is expected to be classified as maintenance capital. For the year ended December 31, 2013, the Partnership’s capital expenditures, excluding acquisitions, were approximately $224.2 million, of which $65.8 million were related to maintenance capital expenditures and $158.3 million were related to growth capital expenditures.
As of December 31, 2013, the Partnership had 159.4 million common units outstanding, including unvested restricted common units issued under its Long-Term Incentive Plan.
Hedging Update
The Partnership entered into the following commodity hedges since its last hedging update on November 27, 2013. In order to convert a portion of its existing proxy hedges into direct NGL hedges, these hedges were structured as “at-the-money” swaps and involved no up-front cost to the Partnership.
Transaction Date | Product / (Type) | Quantity | Price | Term |
1/22/14 | OPIS Propane Conway (Swap) | 630,000 Gallons/month | $1.126 | April-Dec 2014 |
1/22/14 | WTI Crude (Swap) | (7,669) Bbls/month | $92.55 | April-Dec 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.
Fourth Quarter and Full Year 2013 Earnings Release Date and Conference Call Information
Eagle Rock will hold a conference call to discuss its fourth quarter and full year 2013 financial and operating results on Thursday, February 27, 2014 at 2:00 p.m. Eastern Time (1:00 p.m. Central Time).
Interested parties may listen to the earnings conference call live over the Internet or via telephone. To listen live over the Internet, participants are advised to log on to the Partnership's web site at www.eaglerockenergy.com and select the “Events & Presentations” sub-tab under the “Investor Relations” tab. To participate by telephone, the call in number is 877-293-5457, conference ID
49070823. 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 49070823. 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
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 and condensate 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.
The term “Board of Directors” as used herein refers to the board of directors of the general partner of the Partnership’s general partner.
Contacts:
Eagle Rock Energy Partners, L.P.
Jeff Wood, 281-408-1203
Senior Vice President and Chief Financial Officer
Adam Altsuler, 281-408-1350
Vice President, Corporate Finance and Investor Relations; Treasurer
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; excluding certain general and administrative expenses incurred in connection with the Partnership’s strategic review and Midstream Business Contribution.
Eagle Rock uses Adjusted EBITDA as a measure of its core profitability to assess the financial performance of its assets. Adjusted EBITDA also is used as a supplemental financial measure by external users of Eagle Rock's financial statements such as investors, commercial banks and research analysts. For example, the Partnership's lenders under its revolving credit facility use a
variant of its Adjusted EBITDA in a compliance covenant designed to measure the viability of Eagle Rock and its ability to perform under the terms of the revolving credit facility; Eagle Rock, therefore, uses Adjusted EBITDA to measure its compliance with its revolving credit facility. Eagle Rock believes that investors benefit from having access to the same financial measures that its management uses in evaluating performance. Adjusted EBITDA is useful in determining Eagle Rock's ability to sustain or increase distributions. By excluding unrealized derivative gains (losses), a non-cash, mark-to-market benefit (charge) which represents the change in fair market value of the Partnership's executed derivative instruments and is independent of its assets' performance or cash flow generating ability, Eagle Rock believes Adjusted EBITDA reflects the Partnership's ability to generate cash sufficient to pay interest costs, support its level of indebtedness, make cash distributions to its unitholders and finance its maintenance capital expenditures. Eagle Rock further believes that Adjusted EBITDA also portrays the underlying performance of its operating assets by isolating the performance of its operating assets from the impact of an unrealized, non-cash measure designed to portray the fluctuating inherent value of a financial asset. Similarly, by excluding the impact of non-recurring discontinued operations, Adjusted EBITDA provides users of the Partnership's financial statements a picture of its current assets' cash generation ability, independently from that of assets which are no longer a part of its operations.
Eagle Rock's Adjusted EBITDA definition may not be comparable to Adjusted EBITDA or similarly titled measures of other entities, as other entities may not calculate Adjusted EBITDA in the same manner as Eagle Rock. Eagle Rock has reconciled Adjusted EBITDA to the GAAP financial measure of net income (loss) at the end of this release.
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. Eagle Rock has reconciled Distributable Cash Flow to the GAAP financial measure of net income/(loss) at the end of this release.
Additional Information and Where to Find It
This press release does not constitute the solicitation of any vote, proxy or approval. This press release relates to a potential transaction between the Partnership and Regency. This press release is not a substitute for any proxy statement or any other document which the Partnership may file with the SEC in connection with the proposed transaction. In connection with the proposed transaction, the Partnership has filed a preliminary proxy statement with the SEC on January 31, 2014. The Partnership has yet to file a definitive proxy statement with the SEC for the unitholders of the Partnership. INVESTORS AND SECURITY HOLDERS ARE URGED TO READ THE PROXY STATEMENT AND OTHER RELEVANT DOCUMENTS FILED WITH THE SEC CAREFULLY IN THEIR ENTIRETY IF AND WHEN THEY BECOME AVAILABLE BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE PROPOSED TRANSACTION. Any such documents will be available free of charge through the website maintained by the SEC at www.sec.gov or by directing a request to the Partnership’s Investor Relations Department, Eagle Rock Energy, L.P., 1415 Louisiana Street, Suite 2700, Houston, TX 77002, telephone number (281) 408-1200.
Participants in the Solicitation
The Partnership and Regency and their respective general partner’s directors and executive officers may be deemed to be participants in the solicitation of proxies from the unitholders of the Partnership in respect of the proposed transaction. Information regarding the persons who may, under the rules of the SEC, be deemed participants in the solicitation of the unitholders of the Partnership in connection with the proposed transaction, including a description of their direct or indirect interests, by security holdings or otherwise, will be set forth in the proxy statement when it is filed with the SEC.
Forward-Looking Statements
This news release may include "forward-looking statements." All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Partnership expects, believes or anticipates will or may occur in the future are forward-looking statements and speak only as of the date on which such statement is made. These statements are based on certain assumptions made by the Partnership based on its experience and perception of historical trends, current conditions, expected future developments and other factors it believes are appropriate under the circumstances. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Partnership. These include, but are not limited to, risks related to volatility of commodity prices; 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 SEC for the year ended December 31, 2012 and the Partnership's Forms 10-Q filed with the SEC for
subsequent quarters, as well as any other public filings, including, when filed, the Partnership's Form 10-K for the year ended December 31, 2013, 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, 2013 | |||||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||||||
REVENUE: | |||||||||||||||||||
Natural gas, natural gas liquids, oil, condensate, sulfur and helium sales | $ | 298,921 | $ | 284,732 | $ | 1,129,333 | $ | 864,884 | $ | 306,820 | |||||||||
Gathering, compression, processing and treating fees | 21,430 | 21,265 | 83,659 | 56,831 | 21,134 | ||||||||||||||
Unrealized commodity derivative (losses) gains | (8,727 | ) | (6,864 | ) | (43,908 | ) | 6,562 | (29,591 | ) | ||||||||||
Realized commodity derivative gains | 4,443 | 12,904 | 25,375 | 51,332 | 2,757 | ||||||||||||||
Other revenue | 97 | 374 | 820 | 4,350 | 113 | ||||||||||||||
Total revenue | 316,164 | 312,411 | 1,195,279 | 983,959 | 301,233 | ||||||||||||||
COSTS AND EXPENSES: | |||||||||||||||||||
Cost of natural gas and natural gas liquids | 211,361 | 193,921 | 790,618 | 532,719 | 213,509 | ||||||||||||||
Operations and maintenance | 34,789 | 38,143 | 135,205 | 119,828 | 33,075 | ||||||||||||||
Taxes other than income | 5,519 | 4,914 | 20,270 | 19,432 | 5,825 | ||||||||||||||
General and administrative | 22,434 | 17,610 | 81,214 | 69,994 | 20,537 | ||||||||||||||
Impairment | 151,058 | 54,179 | 214,286 | 177,003 | 61,389 | ||||||||||||||
Depreciation, depletion and amortization | 43,135 | 43,002 | 167,170 | 161,045 | 42,641 | ||||||||||||||
Total costs and expenses | 468,296 | 351,769 | 1,408,763 | 1,080,021 | 376,976 | ||||||||||||||
OPERATING LOSS | (152,132 | ) | (39,358 | ) | (213,484 | ) | (96,062 | ) | (75,743 | ) | |||||||||
OTHER INCOME (EXPENSE): | |||||||||||||||||||
Interest expense, net | (17,594 | ) | (16,391 | ) | (68,762 | ) | (51,478 | ) | (17,475 | ) | |||||||||
Realized interest rate derivative losses | (1,727 | ) | (1,649 | ) | (6,756 | ) | (10,227 | ) | (1,693 | ) | |||||||||
Unrealized interest rate derivative gains | 1,389 | 1,082 | 5,652 | 5,500 | 1,234 | ||||||||||||||
Other income (expense) | 73 | 6 | 257 | (38 | ) | 79 | |||||||||||||
Total other expense | (17,859 | ) | (16,952 | ) | (69,609 | ) | (56,243 | ) | (17,855 | ) | |||||||||
LOSS BEFORE INCOME TAXES | (169,991 | ) | (56,310 | ) | (283,093 | ) | (152,305 | ) | (93,598 | ) | |||||||||
INCOME TAX BENEFIT | (1,059 | ) | (1,147 | ) | (5,114 | ) | (1,703 | ) | (2,033 | ) | |||||||||
NET LOSS | $ | (168,932 | ) | $ | (55,163 | ) | $ | (277,979 | ) | $ | (150,602 | ) | $ | (91,565 | ) | ||||
Eagle Rock Energy Partners, L.P.
Consolidated Balance Sheets
($ in thousands)
(unaudited)
December 31, 2013 | December 31, 2012 | ||||||
ASSETS | |||||||
CURRENT ASSETS: | |||||||
Cash and cash equivalents | $ | 76 | $ | 25 | |||
Accounts receivable | 145,963 | 138,732 | |||||
Risk management assets | 9,162 | 33,340 | |||||
Prepayments and other current assets | 8,183 | 9,867 | |||||
Total current assets | 163,384 | 181,964 | |||||
PROPERTY, PLANT AND EQUIPMENT - Net | 1,828,768 | 1,968,206 | |||||
INTANGIBLE ASSETS - Net | 105,620 | 111,515 | |||||
DEFERRED TAX ASSET | 1,438 | 1,656 | |||||
RISK MANAGEMENT ASSETS | 5,461 | 7,953 | |||||
OTHER ASSETS | 22,879 | 22,922 | |||||
TOTAL ASSETS | $ | 2,127,550 | $ | 2,294,216 | |||
LIABILITIES AND MEMBERS' EQUITY | |||||||
CURRENT LIABILITIES: | |||||||
Accounts payable | $ | 170,124 | $ | 160,473 | |||
Accrued liabilities | 29,970 | 19,764 | |||||
Taxes payable | 149 | 46 | |||||
Risk management liabilities | 11,023 | 1,231 | |||||
Total current liabilities | 211,266 | 181,514 | |||||
LONG-TERM DEBT | 1,252,062 | 1,153,103 | |||||
ASSET RETIREMENT OBLIGATIONS | 45,849 | 44,814 | |||||
DEFERRED TAX LIABILITY | 37,953 | 43,000 | |||||
RISK MANAGEMENT LIABILITIES | 3,848 | 1,700 | |||||
OTHER LONG TERM LIABILITIES | 2,693 | 1,711 | |||||
MEMBERS' EQUITY | 573,879 | 868,374 | |||||
TOTAL LIABILITIES AND MEMBERS' EQUITY | $ | 2,127,550 | $ | 2,294,216 | |||
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, 2013 | |||||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||||||
Midstream | |||||||||||||||||||
Revenues: | |||||||||||||||||||
Natural gas, natural gas liquids, oil and condensate sales | $ | 257,812 | $ | 248,153 | $ | 975,773 | $ | 716,508 | $ | 265,732 | |||||||||
Intercompany sales - natural gas and condensate | (1,854 | ) | (2,325 | ) | (7,824 | ) | (10,134 | ) | (1,900 | ) | |||||||||
Gathering and treating services | 21,430 | 21,265 | 83,659 | 56,831 | 21,134 | ||||||||||||||
Other revenue | 14 | — | 119 | 2,864 | 68 | ||||||||||||||
Total revenue | 277,402 | 267,093 | 1,051,727 | 766,069 | 285,034 | ||||||||||||||
Cost of natural gas, natural gas liquids, oil and condensate | 211,403 | 194,004 | 790,618 | 532,719 | 213,509 | ||||||||||||||
Intersegment elimination - Cost of natural gas and condensate | 7,596 | 11,705 | 39,044 | 44,400 | 10,889 | ||||||||||||||
Operating costs and expenses: | |||||||||||||||||||
Operations and maintenance | 25,736 | 29,470 | 101,121 | 82,648 | 26,396 | ||||||||||||||
Impairment | — | 29,735 | — | 131,714 | — | ||||||||||||||
Depreciation, depletion and amortization | 19,507 | 20,760 | 77,685 | 70,495 | 20,160 | ||||||||||||||
Total operating costs and expenses | 45,243 | 79,965 | 178,806 | 284,857 | 46,556 | ||||||||||||||
Operating income (loss) | $ | 13,160 | $ | (18,581 | ) | $ | 43,259 | $ | (95,907 | ) | $ | 14,080 | |||||||
Upstream | |||||||||||||||||||
Revenue | |||||||||||||||||||
Oil and condensate sales | $ | 19,826 | $ | 14,332 | $ | 67,677 | $ | 58,420 | $ | 19,782 | |||||||||
Intersegment sales - condensate | 8,246 | 8,778 | 39,075 | 43,004 | 10,323 | ||||||||||||||
Natural gas sales | 9,558 | 9,631 | 37,249 | 32,105 | 9,155 | ||||||||||||||
Intersegment sales - natural gas | 1,878 | 2,530 | 7,973 | 10,339 | 1,907 | ||||||||||||||
Natural gas liquids sales | 10,925 | 9,771 | 40,583 | 43,831 | 10,786 | ||||||||||||||
Sulfur sales | 800 | 2,845 | 8,051 | 14,020 | 1,365 | ||||||||||||||
Other | 83 | 374 | 701 | 1,486 | 45 | ||||||||||||||
Total revenue | 51,316 | 48,261 | 201,309 | 203,205 | 53,363 | ||||||||||||||
Operating costs and expenses: | |||||||||||||||||||
Operations and maintenance | 14,572 | 13,709 | 54,354 | 56,734 | 12,504 | ||||||||||||||
Impairment | 151,058 | 24,444 | 214,286 | 45,289 | 61,389 | ||||||||||||||
Depreciation, depletion and amortization | 23,010 | 21,707 | 87,456 | 88,777 | 22,061 | ||||||||||||||
Total operating costs and expenses | 188,640 | 59,860 | 356,096 | 190,800 | 95,954 | ||||||||||||||
Operating (loss) income | $ | (137,324 | ) | $ | (11,599 | ) | $ | (154,787 | ) | $ | 12,405 | $ | (42,591 | ) | |||||
Corporate and Other | |||||||||||||||||||
Revenues: | |||||||||||||||||||
Unrealized commodity derivative (losses) gains | $ | (8,727 | ) | $ | (6,864 | ) | $ | (43,908 | ) | $ | 6,562 | $ | (29,591 | ) | |||||
Realized commodity derivative gains | 4,443 | 12,904 | 25,375 | 51,332 | 2,757 | ||||||||||||||
Intersegment elimination - Sales of natural gas and condensate | (8,270 | ) | (8,983 | ) | (39,224 | ) | (43,209 | ) | (10,330 | ) | |||||||||
Total revenue | (12,554 | ) | (2,943 | ) | (57,757 | ) | 14,685 | (37,164 | ) | ||||||||||
Costs and expenses: | |||||||||||||||||||
Intersegment elimination - Cost of natural gas and condensate | (7,638 | ) | (11,788 | ) | (39,044 | ) | (44,400 | ) | (10,889 | ) | |||||||||
General and administrative | 22,434 | 17,610 | 81,214 | 69,994 | 20,537 | ||||||||||||||
Intersegment elimination - Operations and maintenance | — | (122 | ) | — | (122 | ) | — | ||||||||||||
Depreciation, depletion and amortization | 618 | 535 | 2,029 | 1,773 | 420 | ||||||||||||||
Operating loss | $ | (27,968 | ) | $ | (9,178 | ) | $ | (101,956 | ) | $ | (12,560 | ) | $ | (47,232 | ) | ||||
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, 2013 | |||||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||||||
Texas Panhandle | |||||||||||||||||||
Revenues: | |||||||||||||||||||
Natural gas, natural gas liquids, condensate and helium sales | $ | 128,464 | $ | 145,065 | $ | 484,634 | $ | 334,295 | $ | 141,271 | |||||||||
Intersegment sales - natural gas and condensate | 64,119 | 33,245 | 226,576 | 105,759 | 56,799 | ||||||||||||||
Gathering, compression, processing and treating services | 14,846 | 12,233 | 53,739 | 25,743 | 14,341 | ||||||||||||||
Other revenue | 14 | — | 119 | 2,864 | 68 | ||||||||||||||
Total revenue | 207,443 | 190,543 | 765,068 | 468,661 | 212,479 | ||||||||||||||
Cost of natural gas, natural gas liquids, condensate and helium | 162,835 | 143,089 | 594,125 | 332,792 | 163,768 | ||||||||||||||
Intersegment cost of sales - natural gas | 42 | 83 | 200 | 83 | 61 | ||||||||||||||
Operating costs and expenses: | |||||||||||||||||||
Operations and maintenance | 20,761 | 23,542 | 81,186 | 60,884 | 21,269 | ||||||||||||||
Depreciation, depletion and amortization | 15,108 | 14,897 | 57,781 | 44,451 | 14,823 | ||||||||||||||
Total operating costs and expenses | 35,869 | 38,439 | 138,967 | 105,335 | 36,092 | ||||||||||||||
Operating income | $ | 8,697 | $ | 8,932 | $ | 31,776 | $ | 30,451 | $ | 12,558 | |||||||||
East Texas and Other Midstream | |||||||||||||||||||
Revenues: | |||||||||||||||||||
Natural gas, natural gas liquids and condensate sales | $ | 27,037 | $ | 27,114 | $ | 106,889 | $ | 125,512 | $ | 25,867 | |||||||||
Intersegment sales - natural gas | 12,525 | 12,628 | 37,716 | 39,099 | 3,948 | ||||||||||||||
Gathering, compression, processing and treating services | 6,544 | 8,961 | 29,748 | 31,017 | 6,765 | ||||||||||||||
Total revenue | 46,106 | 48,703 | 174,353 | 195,628 | 36,580 | ||||||||||||||
Cost of natural gas, natural gas liquids and condensate | 35,928 | 36,290 | 131,966 | 147,493 | 26,464 | ||||||||||||||
Operating costs and expenses: | |||||||||||||||||||
Operations and maintenance | 4,968 | 5,929 | 19,943 | 21,762 | 5,140 | ||||||||||||||
Impairment | — | 29,735 | — | 131,714 | — | ||||||||||||||
Depreciation, depletion and amortization | 4,263 | 5,737 | 19,476 | 25,771 | 5,222 | ||||||||||||||
Total operating costs and expenses | 9,231 | 41,401 | 39,419 | 179,247 | 10,362 | ||||||||||||||
Operating income (loss) | $ | 947 | $ | (28,988 | ) | $ | 2,968 | $ | (131,112 | ) | $ | (246 | ) | ||||||
Marketing and Trading | |||||||||||||||||||
Revenues: | |||||||||||||||||||
Natural gas, oil and condensate sales | $ | 102,311 | $ | 75,974 | $ | 384,250 | $ | 256,701 | $ | 98,594 | |||||||||
Intersegment sales - natural gas and condensate | (78,498 | ) | (48,198 | ) | (272,116 | ) | (154,992 | ) | (62,647 | ) | |||||||||
Gathering, compression, processing and treating services | 40 | 71 | 172 | 71 | 28 | ||||||||||||||
Total revenue | 23,853 | 27,847 | 112,306 | 101,780 | 35,975 | ||||||||||||||
Cost of natural gas and condensate | 12,598 | 14,542 | 64,527 | 52,434 | 23,277 | ||||||||||||||
Intersegment cost of sales - natural gas and condensate | 7,596 | 11,705 | 38,844 | 44,317 | 10,828 | ||||||||||||||
Operating costs and expenses: | |||||||||||||||||||
Operations and maintenance | 7 | (1 | ) | (8 | ) | 2 | (13 | ) | |||||||||||
Depreciation, depletion and amortization | 136 | 126 | 428 | 273 | 115 | ||||||||||||||
Total operating costs and expenses | 143 | 125 | 420 | 275 | 102 | ||||||||||||||
Operating income | $ | 3,516 | $ | 1,475 | $ | 8,515 | $ | 4,754 | $ | 1,768 | |||||||||
Eagle Rock Energy Partners, L.P.
Midstream Operations Information
(unaudited)
Three Months Ended December 31, | Year Ended December 31, | Three Months Ended September 30, 2013 | |||||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||||||
Gas gathering volumes - (Average Mcf/d) | |||||||||||||||||||
Texas Panhandle | 395,956 | 372,124 | 370,606 | 212,617 | 393,226 | ||||||||||||||
East Texas and Other Midstream | 195,999 | 217,496 | 195,235 | 255,752 | 190,674 | ||||||||||||||
Total | 591,955 | 589,620 | 565,841 | 468,369 | 583,900 | ||||||||||||||
NGLs - (Net equity Bbls) | |||||||||||||||||||
Texas Panhandle | 233,588 | 415,103 | 805,190 | 1,270,601 | 245,548 | ||||||||||||||
East Texas and Other Midstream | (28,428 | ) | 80,315 | 160,235 | 338,636 | 61,180 | |||||||||||||
Total | 205,160 | 495,418 | 965,425 | 1,609,237 | 306,728 | ||||||||||||||
Condensate - (Net equity Bbls) | |||||||||||||||||||
Texas Panhandle | 295,320 | 302,168 | 1,155,590 | 801,828 | 289,524 | ||||||||||||||
East Texas and Other Midstream | 8,280 | 9,613 | 31,025 | 38,350 | 8,372 | ||||||||||||||
Total | 303,600 | 311,781 | 1,186,615 | 840,178 | 297,896 | ||||||||||||||
Natural gas position - (Average MMbtu/d) | |||||||||||||||||||
Texas Panhandle | 7,352 | 16,114 | 7,747 | 547 | 7,985 | ||||||||||||||
East Texas and Other Midstream | 1,199 | 1,676 | 296 | 1,530 | (51 | ) | |||||||||||||
Total | 8,551 | 17,790 | 8,043 | 2,077 | 7,934 | ||||||||||||||
Average realized NGL price - per Bbl | |||||||||||||||||||
Texas Panhandle | $ | 39.30 | $ | 31.39 | $ | 36.31 | $ | 36.00 | $ | 36.31 | |||||||||
East Texas and Other Midstream | $ | 32.15 | $ | 32.04 | $ | 30.03 | $ | 37.83 | $ | 30.08 | |||||||||
Weighted Average | $ | 38.19 | $ | 31.51 | $ | 35.23 | $ | 36.56 | $ | 35.30 | |||||||||
Average realized condensate price - per Bbl | |||||||||||||||||||
Texas Panhandle | $ | 84.89 | $ | 74.32 | $ | 84.41 | $ | 82.64 | $ | 92.64 | |||||||||
East Texas and Other Midstream | $ | 100.61 | $ | 87.20 | $ | 99.36 | $ | 96.91 | $ | 106.70 | |||||||||
Weighted Average | $ | 85.99 | $ | 75.20 | $ | 85.33 | $ | 83.78 | $ | 93.59 | |||||||||
Average realized natural gas price - per MMbtu | |||||||||||||||||||
Texas Panhandle | $ | 3.41 | $ | 3.23 | $ | 3.45 | $ | 2.63 | $ | 3.34 | |||||||||
East Texas and Other Midstream | $ | 3.49 | $ | 3.37 | $ | 3.58 | $ | 2.85 | $ | 3.53 | |||||||||
Weighted Average | $ | 3.43 | $ | 3.26 | $ | 3.48 | $ | 2.79 | $ | 3.38 | |||||||||
____________________
Eagle Rock Energy Partners, L.P.
Upstream Operations Information
(unaudited)
Three Months Ended December 31, | Year Ended December 31, | Three Months Ended September 30, 2013 | |||||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||||||
Upstream | |||||||||||||||||||
Production: | |||||||||||||||||||
Oil and condensate (Bbl) | 327,679 | 283,326 | 1,222,270 | 1,184,200 | 321,170 | ||||||||||||||
Gas (Mcf) | 3,239,438 | 3,828,320 | 12,804,475 | 16,442,579 | 3,254,722 | ||||||||||||||
NGLs (Bbl) | 289,584 | 272,476 | 1,155,639 | 1,120,522 | 298,031 | ||||||||||||||
Total Mcfe | 6,943,016 | 7,163,132 | 27,071,929 | 30,270,911 | 6,969,928 | ||||||||||||||
Sulfur (long ton) | 25,365 | 22,892 | 105,394 | 102,002 | 26,788 | ||||||||||||||
Realized prices, excluding derivatives: | |||||||||||||||||||
Oil and condensate (per Bbl) | $ | 85.67 | $ | 81.57 | $ | 87.34 | $ | 85.65 | $ | 93.74 | |||||||||
Gas (per Mcf) | $ | 3.53 | $ | 3.18 | $ | 3.53 | $ | 2.58 | $ | 3.40 | |||||||||
NGLs (per Bbl) | $ | 37.73 | $ | 35.86 | $ | 35.12 | $ | 39.12 | $ | 36.19 | |||||||||
Sulfur (per long ton) | $ | 31.53 | $ | 124.30 | $ | 76.38 | $ | 137.46 | $ | 50.95 | |||||||||
Operating statistics: | |||||||||||||||||||
Operating costs per Mcfe (incl production taxes) (1) | $ | 1.94 | $ | 1.72 | $ | 1.84 | $ | 1.69 | $ | 1.64 | |||||||||
Operating costs per Mcfe (excl production taxes) (1) | $ | 1.48 | $ | 1.22 | $ | 1.36 | $ | 1.19 | $ | 1.11 | |||||||||
Operating income per Mcfe | $ | (19.78 | ) | $ | (1.62 | ) | $ | (5.72 | ) | $ | 0.41 | $ | (6.11 | ) | |||||
Drilling program (gross wells): | |||||||||||||||||||
Development wells | 8 | 8 | 45 | 33 | 16 | ||||||||||||||
Completions | 8 | 8 | 45 | 33 | 16 | ||||||||||||||
Workovers | 8 | 2 | 24 | 21 | 6 | ||||||||||||||
Recompletions | 2 | 4 | 10 | 11 | 1 | ||||||||||||||
______________________
(1) | Excludes post-production costs of $1,109, $4,572, $1,410 and $5,478 for the three months and year ended December 31, 2013 and 2012, respectively, and $1,069 for the three months ended September 30, 2013. |
Non-GAAP Financial Measures
The following tables present a reconciliation of the non-GAAP financial measures of Adjusted EBITDA and Distributable Cash Flow to the GAAP financial measure of net income for each of the periods indicated (in thousands).
Eagle Rock Energy Partners, L.P.
GAAP to Non-GAAP Reconciliations
($ in thousands)
(unaudited)
Three Months Ended December 31, | Year Ended December 31, | Three Months Ended September 30, 2013 | |||||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||||||
Net (loss) income to Adjusted EBITDA | |||||||||||||||||||
Net loss, as reported | $ | (168,932 | ) | $ | (55,163 | ) | $ | (277,979 | ) | $ | (150,602 | ) | $ | (91,565 | ) | ||||
Depreciation, depletion and amortization | 43,135 | 43,002 | 167,170 | 161,045 | 42,641 | ||||||||||||||
Impairment | 151,058 | 54,179 | 214,286 | 177,003 | 61,389 | ||||||||||||||
Loss (gain) from risk management activities, net | 4,077 | (6,080 | ) | 19,322 | (53,389 | ) | 27,507 | ||||||||||||
Total derivative settlements | 2,559 | 11,626 | 19,288 | 41,517 | 1,812 | ||||||||||||||
Non-cash mark-to-market of Upstream product imbalances | — | (20 | ) | (1 | ) | 317 | 3 | ||||||||||||
Restricted units non-cash amortization expense | 3,278 | 1,790 | 13,384 | 9,882 | 3,939 | ||||||||||||||
Income tax (benefit) provision | (1,059 | ) | (1,147 | ) | (5,114 | ) | (1,703 | ) | (2,033 | ) | |||||||||
Interest - net including realized risk management instruments and other expense | 19,248 | 18,034 | 75,261 | 61,705 | 19,089 | ||||||||||||||
Other income | — | — | — | 40 | — | ||||||||||||||
Other (1) | 4,030 | — | 4,731 | — | 701 | ||||||||||||||
Adjusted EBITDA | $ | 57,394 | $ | 66,221 | $ | 230,348 | $ | 245,815 | $ | 63,483 | |||||||||
Net (loss) income to Distributable Cash Flow | |||||||||||||||||||
Net loss, as reported | $ | (168,932 | ) | $ | (55,163 | ) | $ | (277,979 | ) | $ | (150,602 | ) | $ | (91,565 | ) | ||||
Depreciation, depletion and amortization expense | 43,135 | 43,002 | 167,170 | 161,045 | 42,641 | ||||||||||||||
Impairment | 151,058 | 54,179 | 214,286 | 177,003 | 61,389 | ||||||||||||||
Loss (gain) from risk management activities, net | 4,077 | (6,080 | ) | 19,322 | (53,389 | ) | 27,507 | ||||||||||||
Total derivative settlements | 2,559 | 11,626 | 19,288 | 41,517 | 1,812 | ||||||||||||||
Capital expenditures-maintenance related | (19,466 | ) | (18,593 | ) | (65,831 | ) | (54,417 | ) | (18,751 | ) | |||||||||
Non-cash mark-to-market of Upstream product imbalances | — | (20 | ) | (1 | ) | 317 | 3 | ||||||||||||
Restricted units non-cash amortization expense | 3,278 | 1,790 | 13,384 | 9,882 | 3,939 | ||||||||||||||
Income tax benefit | (1,059 | ) | (1,147 | ) | (5,114 | ) | (1,703 | ) | (2,033 | ) | |||||||||
Other income | — | (6 | ) | — | 40 | — | |||||||||||||
Other (1) | 4,030 | — | 4,731 | — | 701 | ||||||||||||||
Cash income taxes | (201 | ) | (75 | ) | (201 | ) | (737 | ) | — | ||||||||||
Distributable Cash Flow | $ | 18,479 | $ | 29,513 | $ | 89,055 | $ | 128,956 | $ | 25,643 | |||||||||
(1) | Amount includes general and administrative expenses incurred in connection with the Partnership's strategic review and the contribution of the Midstream Business to Regency. |
###