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Eagle Rock Reports Fourth Quarter and Year End 2013 Financial Results

HOUSTON, Feb. 26, 2014 (GLOBE NEWSWIRE) -- 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.

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
Three Months Ended Twelve Months Ended Ended
December 31, December 31, September
2013 2012 2013 2012 30, 2013
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), net 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, December 31,
2013 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
Three Months Ended Ended
December 31, Year Ended December 31, September
2013 2012 2013 2012 30, 2013
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 cost of sales - 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
Three Months Ended Ended
December 31, Year Ended December 31, September
2013 2012 2013 2012 30, 2013
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
Intersegment cost of sales - natural gas
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 (loss) income $ 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
Three Months Ended Ended
December 31, Year Ended December 31, September
2013 2012 2013 2012 30, 2013
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
Three Months Ended Ended
December 31, Year Ended December 31, September
2013 2012 2013 2012 30, 2013
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 (loss) 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 31, 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
Three Months Ended Ended
December 31, Year Ended December 31, September 30,
2013 2012 2013 2012 2013
Net income (loss) 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 (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 income (loss) to Distributable Cash Flow
Net (loss) income, 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.

CONTACT: 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

Source:Eagle Rock Energy Partners, L.P.