Eagle Rock Reports Third Quarter 2014 Financial Results

HOUSTON, Oct. 29, 2014 (GLOBE NEWSWIRE) -- Eagle Rock Energy Partners, L.P. ("Eagle Rock" or the "Partnership") (Nasdaq:EROC) today announced its unaudited financial results for the three months ended September 30, 2014.

Third Quarter 2014 Highlights

• Adjusted EBITDA increased 42% over second quarter 2014
• Distributable cash flow of $16.0 million, equivalent to $0.10/unit
• Announced a distribution of $0.07/unit for the third quarter, or $0.28/unit annualized
• Distribution coverage of 1.4x distributable cash flow
• Total daily production increased 5.3% over second quarter 2014
• Total liquidity of $374 million at quarter-end, including Regency (RGP) units
• Announced a common unit repurchase program of up to $100 million

Third Quarter 2014 Financial and Operating Results

Significant results from continuing operations for the third quarter of 2014:

• Adjusted EBITDA of $35.4 million, a 42% increase as compared to $24.9 million in second quarter 2014.
   
• Distributable Cash Flow of $16.0 million, compared to $3.9 million for second quarter 2014.
   
• Net Income of $266.3 million, driven largely by the $249.9 million gain recorded in the quarter related to the Midstream Business Contribution.
   
• Drilled and completed 3 gross (3 net) operated wells and participated in 4 gross (1.4 net) non-operated wells in the Mid-Continent region.  Additionally, conducted 6 gross (3.8 net) workovers and 1 gross (1 net) recompletion.
   
• Total production was 6.90 Bcfe compared to 6.48 Bcfe in second quarter 2014. Average daily production was 75.1 MMcfe/d compared to 71.2 MMcfe/d in second quarter 2014.
  
  • Oil production increased 13% quarter over quarter from 300 MBbl to 338 MBbl
     
  • NGL production increased 2% quarter over quarter from 290 MBbl to 297 MBbl
     
  • Natural gas production increased 5% quarter over quarter from 2.94 Bcf to 3.09 Bcf
     
  • The increase in production volumes was primarily due to:
    
    • Strong performance from three operated wells completed in the Golden Trend Field and four non-operated (Briar) wells completed in the prolific horizontal Woodford "SCOOP" play.
       
    • 98% average run-time at the Big Escambia Creek processing facility
       
• Product revenue of $53.6 million, up 3% compared to $52.0 million for second quarter 2014, due to higher production volumes offset by lower commodity prices.
   
• Cash Distributions of $4.0 million received from Regency Energy Partners, LP ("Regency") on the Regency units held by the Partnership.
   
• Operating expenses, including taxes, of $13.9 million, 4% lower than second quarter 2014, primarily due to lower estimated ad valorem taxes and other items.
   
• General and administrative expenses of $9.3 million (after excluding amortization of expenses pursuant to the Long-Term Incentive Plan), down 12% from second quarter 2014, primarily due to the elimination of shared services with the Partnership's former midstream business.
   
• Operating income, excluding an impairment charge of $17.3 million, increased to $32.8 million as compared to the operating loss of $12.8 million for second quarter 2014, primarily due to unrealized gains on commodity derivatives and higher production.
   
• Maintenance capital expenditures of $14.5 million, an increase of $0.2 million as compared to second quarter 2014.

Capitalization and Liquidity Update

As of September 30, 2014, the Partnership's borrowing base under its senior secured credit facility totaled approximately $330 million, and based on outstanding borrowings and letters of credit, the Partnership had approximately $104.3 million of availability under its senior secured credit facility. 

The Partnership announced on October 14, 2014 that it amended its five-year senior secured credit facility originally entered into on June 22, 2011 with a syndicate of banks led by Wells Fargo, N.A. as administrative agent, and Bank of America, N.A. and Royal Bank of Scotland plc as co-syndication agents.   Pursuant to the amendment, the Partnership's borrowing base was reduced to $320 million and the facility term was extended to October 2019 (five years from amendment). The amendment coincided with the semi-annual redetermination of the borrowing base, and the next redetermination will be April 2015.

The 8.2 million Regency units held by the Partnership were not collateralized under the credit facility agreement.

The amended credit agreement is a more traditional reserve-based facility for a pure-play upstream company, and includes revised covenants and improved fee pricing, as follows:

• Total Leverage Ratio of no greater than 4.0x LTM Adjusted EBITDA (increases to 4.5x LTM Adjusted EBITDA for the two periods following an acquisition above $50 million)
• Current Ratio of no less than 1.0x
• Removal of Senior Secured Leverage Ratio covenant
• Removal of Interest Coverage Ratio covenant
• Improved fee pricing by 25 basis points on all tranches except the Commitment Fee, which remains relatively the same

As of September 30, 2014 the value of the 8.2 million Regency units held by the Partnership was $269.0 million. The Partnership's cash balance at the end of the third quarter was $0.6 million.

As of October 27, 2014, the Partnership had 159.8 million common units outstanding eligible to receive the distribution, including 2.3 million unvested restricted common units eligible to receive the distribution, issued under its Amended and Restated Long-Term Incentive Plan. The Partnership had 160.1 million total common units outstanding as of October 27, 2014, including 2.7 million unvested restricted common units issued under its Amended and Restated Long-Term Incentive Plan.

Guidance

During the fourth quarter of 2014, the Partnership plans to spend approximately $28 million on capital expenditures and expects $14 million to be categorized as maintenance capital expenditures and $14 million to be categorized as growth capital expenditures. Subject to results from the Partnership's drilling program, the Partnership expects to average between 76 and 78 MMcfe/d during fourth quarter 2014. Eagle Rock currently expects its quarterly General & Administrative expenses, excluding amortization of expenses related to its Long Term Incentive Plan, to decrease over the next six months to a run rate between $8.5 and $8.7 million per quarter.

Hedging Update

The Partnership employs risk mitigation strategies to protect cash flow such that the Partnership may maintain a steady rate of quarterly cash distributions to our investors. One important risk mitigation strategy is the use of commodity price hedging to lock in stable cash flow during commodity price fluctuations. Eagle Rock's estimated hedge profile is as follows:

The Partnership has not entered into any additional commodity hedges since its last hedging update on September 10, 2014. The latest presentation, which now excludes the midstream hedges that were conveyed as part of the Midstream Business Contribution, can be accessed by going to www.eaglerockenergy.com: select Investor Relations, then select Presentations.

Third Quarter 2014 Conference Call Information

Eagle Rock will hold a conference call to discuss its third quarter 2014 financial and operating results on Thursday, October 30, 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 22777390. 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 22777390. In addition, a replay of the audio webcast will be available by accessing the Partnership's web site after the call is concluded.

About the Partnership

Eagle Rock is a growth-oriented master limited partnership engaged in (a) the exploitation, development, and production of oil and natural gas properties and (b) ancillary gathering, compressing, treating, processing and marketing services with respect to its production of natural gas, natural gas liquids, condensate and crude oil.

Contact:

Eagle Rock Energy Partners, L.P.

Bob Haines, 281-408-1303
Vice President and Interim Chief Financial Officer

Chad Knips, 281-408-1203
Director, Corporate Finance and Investor Relations

Use of Non-GAAP Financial Measures

This news release and the accompanying schedules include the non-generally accepted accounting principles, or non-GAAP, financial measures of Adjusted EBITDA and Distributable Cash Flow. The accompanying non-GAAP financial measures schedules (after the financial schedules) provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measures calculated and presented in accordance with accounting principles generally accepted in the United States, or GAAP. Non-GAAP financial measures should not be considered alternatives to GAAP measures such as net income (loss), operating income (loss), cash flows from operating activities or any other GAAP measure of liquidity or financial performance.

Eagle Rock defines Adjusted EBITDA as net income (loss) plus or (minus) income tax provision (benefit); interest-net, including 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.

Adjusted EBITDA does not include interest expense, income taxes or depreciation and amortization expense. Because we have borrowed money to finance our operations, interest expense is a necessary element of our costs and our ability to generate net income. Because we use capital assets, depreciation and amortization are also necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net income (loss) and net cash flows provided by operating activities determined under GAAP, as well as Adjusted EBITDA, to evaluate our performance and liquidity.

Distributable Cash Flow is defined as Adjusted EBITDA minus: (i) maintenance capital expenditures; (ii) cash interest expense; (iii) cash income taxes; and (iv) the addition of losses or subtraction of gains relating to other miscellaneous non-cash amounts affecting net income (loss) for the period. Maintenance capital expenditures represent capital expenditures necessary to maintain the Partnership's natural gas, NGL, crude or sulfur production. We estimate these amounts based on current projections and expectations, and do not undertake to adjust any historical amounts based on the actual impact of such expenditures on production. As a result, the included amount of maintenance capital expenditures could fail to maintain production if actual performance does not meet the Partnership's projections and expectations, including, without limitation, on account of: (i) unanticipated mechanical issues; (ii) unanticipated delays; (iii) poorer than expected production performance of the Partnership's new wells and recompletions; and/or (iv) unanticipated loss of, or higher than anticipated decline in, existing production.

Distributable Cash Flow is a 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.

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 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, 2013 and the Partnership's Forms 10-Q filed with the SEC for subsequent quarters, including the Form 10-Q filed for the quarter ended September 30, 2014, as well as any other public filings and press releases.