Eagle Rock Reports Fourth Quarter and Year End 2014 Financial Results

HOUSTON, Feb. 25, 2015 (GLOBE NEWSWIRE) -- Eagle Rock Energy Partners, L.P. ("Eagle Rock" or the "Partnership") EROC today announced its unaudited financial results for the full year 2014 and three months ended December 31, 2014.

Fourth Quarter 2014 Highlights

• Distributable cash flow per unit increased 17% over third quarter 2014 to $0.12/unit, equivalent to $17.9 million
• Announced a distribution of $0.07/unit for the fourth quarter, or $0.28/unit annualized 
• Distribution coverage of 1.7x distributable cash flow for the fourth quarter
• Average daily production of 75.4 MMcfe/d in the fourth quarter compared to 75.1 MMcfe/d in the third quarter 2014
• Adjusted EBITDA of $34.5 million for the fourth quarter compared to $35.4 million for the third quarter 2014, as lower realized prices were partially offset by higher production volumes, lower operating costs and lower G&A
• Total liquidity of $268 million at year-end, including the market value of the Regency Energy Partners, L.P. ("Regency") common units owned by the Partnership
• Leverage ratio of 2.2x as of December 31, 2014

Joseph A. Mills, the Partnership's Chairman and Chief Executive Officer, stated, "2014 was a transformational year for Eagle Rock. We successfully closed the sale of our Midstream business to Regency and embarked on our new path as a pure-play upstream master limited partnership.  The current low commodity price environment presents opportunities for Eagle Rock as we look to grow the Partnership.  Our strong hedge portfolio, coupled with our ample liquidity and low leverage ratio, positions the Partnership in 2015 to make accretive acquisitions, reduce the overall production decline rate and grow distributable cash flow."

Fourth Quarter 2014 Financial and Operating Results

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

• Adjusted EBITDA of $34.5 million, compared to $35.4 million for third quarter 2014, as lower commodity prices were partially offset by higher production, lower operating costs and lower G&A.
• Distributable Cash Flow of $17.9 million or $0.12/unit, a 17% increase as compared to third quarter 2014 distributable cash flow per unit.
• Net Loss of $344.6 million, driven largely by impairment charges primarily related to the impact of lower commodity prices on the Partnership's oil and gas reserves, mainly in the Golden Trend, Anadarko and Big Escambia Creek areas.
• Participated in 7 gross (0.2 net) non-operated wells in the Mid-Continent region and drilled and completed 1 gross (0.6 net) operated well in the Alabama region.  Additionally, conducted 1 gross (1.0 net) workover and 1 gross (0.04 net) recompletion.
• Total production was 6.94 Bcfe, compared to 6.90 Bcfe in third quarter 2014. Average daily production was 75.4 MMcfe/d, compared to 75.1 MMcfe/d in third quarter 2014.
  • Oil production increased 5% quarter over quarter from 338 MBbl to 357 MBbl
  • NGL production increased quarter over quarter from 297 MBbl to 298 MBbl
  • Natural gas production decreased 3% quarter over quarter from 3.09 Bcf to 3.01 Bcf
  • The overall increase in production volumes was primarily due to strong performance from four non-operated (Briar Unit) wells in the prolific horizontal Woodford "SCOOP" play, and one operated well completed in the Alabama region
• Product revenue of $43.1 million, down 20% compared to $53.6 million for third quarter 2014, due to lower commodity prices partially offset by higher production volumes.
• Realized commodity derivative gains of $8.7 million, compared to $1.3 million for third quarter 2014, due to lower commodity prices.
• Cash Distributions of $4.0 million received on the Regency common units held by the Partnership.
• Operating expenses, including taxes, of $12.9 million, 7% lower than third quarter 2014, primarily due to lower estimated severance taxes resulting from decreased sales revenue.
• General and administrative expenses of $8.5 million (excluding amortization of expenses pursuant to the Long-Term Incentive Plan), down 9% from third quarter 2014.
• Operating income, excluding an impairment charge of $378.6 million, increased to $92.5 million as compared to operating income, excluding an impairment charge of $17.3 million, of $32.8 million for third quarter 2014, primarily due to unrealized gains on commodity derivatives.
• Maintenance capital expenditures of $14.6 million as compared to $14.5 million spent in the third quarter 2014.

Full Year 2014 Financial and Operating Results

Significant results from continuing operations for full year 2014:

• Adjusted EBITDA of $120.9 million, compared to $119.8 million attributable to the Upstream business for full year 2013.
• Distributable Cash Flow of $42.4 million, compared to $47.8 million attributable to the Upstream business for full year 2013.
• Net Loss of $139.9 million, driven largely by impairment charges primarily related to the impact of lower commodity prices on the Partnership's oil and gas reserves, mainly in the Golden Trend, Anadarko and Big Escambia Creek areas.
• Drilled and completed 10 gross (8.6 net) operated wells and participated in 15 gross (1.7 net) non-operated wells in the Mid-Continent region, and drilled and completed 2 gross (1.3 net) operated wells in the Alabama region. Additionally, conducted 15 gross (12.6 net) workovers and 7 gross (4.7 net) recompletions.
• Total production was 26.8 Bcfe, compared to 27.1 Bcfe for full year 2013. Average daily production was 73.5 MMcfe/d, compared to 74.2 MMcfe/d for full year 2013.
  • Oil production increased 7% year over year from 1.2 MMBbl to 1.3 MMBbl
  • NGL production was flat year over year at 1.2 MMBbl
  • Natural gas production decreased 6% year over year from 12.8 Bcf to 12.0 Bcf
  • Overall production was impacted by severe weather in early 2014 and third party plant and pipeline curtailments in our Permian and Mid-Continent operations in Q2 and Q4.
    • NGL and gas production were impacted by third party operational interference on two wells in the Mid-Continent region and delays in timing of well completions in Alabama and the Mid-Continent.
    • Oil production increased primarily due to strong results from four non-operated (Briar Unit) wells completed in the prolific horizontal Woodford "SCOOP" play in Q3.
• Product revenue of $203.8 million, compared to $200.6 million for full year 2013, due to higher gas prices partially offset by lower gas production volumes, and lower crude prices partially offset by higher crude production volumes.
• Realized commodity derivative gains of $4.7 million, compared to $15.6 million for full year 2013.
• Cash Distributions of $8.0 million received on the Regency units held by the Partnership.
• Operating expenses, including taxes, of $56.6 million, 4% higher than full year 2013, primarily due to higher operations and maintenance costs.
• General and administrative expenses of $39.0 million (excluding amortization of expenses pursuant to the Long-Term Incentive Plan), down 9% from full year 2013, primarily due to the divestment of the Partnership's former midstream business.
• Operating income, excluding an impairment charge of $395.9 million, increased to $108.8 million as compared to the operating income, excluding an impairment charge of $214.3 million, of $0.4 million for full year 2013, primarily due to unrealized gains on commodity derivatives.
• Maintenance capital expenditures of $58.5 million, an increase of $12.3 million as compared to $46.2 million spent for the full year 2013, due primarily to the addition of more properties, higher decline rates from the SCOOP drilling program and specific maintenance projects at the Partnership's Big Escambia Creek facility.

Year-End Proved Reserves

Based on SEC pricing, proved reserves at year-end 2014 were estimated to be 318.2 Bcfe, a decrease of 8% from year-end 2013. Total production for 2014 was 26.8 Bcfe, or 73.5 MMcfe/d, a decrease of 0.9% from total production in 2013. The Partnership's extensions and discoveries in 2014 were 42.8 Bcfe, which represents a production replacement rate of 160%. Total 2014 year-end reserves were lower as compared to 2013 due to, among other things, downward adjustments to the future projections on certain developed and undeveloped proved reserve cases primarily associated with our Golden Trend field and higher operating cost assumptions in certain areas. As of December 31, 2014, approximately 79% of the Partnership's total proved reserves were classified as proved developed.

Regency Unit Sale and Eagle Rock Common Unit Repurchase Program

As of February 23, 2015, the Partnership had sold approximately 4.1 million Regency units received as part of the consideration for the Midstream Business Contribution, and proceeds were approximately $104 million. These proceeds were used to fund the Partnership's common unit repurchase program, pay down debt and for general corporate purposes. Eagle Rock may continue to sell the approximately 4.1 million remaining Regency common units in order to further strengthen liquidity. 

Pursuant to its previously announced common unit repurchase program, as of February 23, 2015 the Partnership had repurchased approximately 8.6 million common units for a total consideration of approximately $22 million. These repurchase amounts are not indicative of the Partnership's go-forward repurchasing plan, and any future repurchases will be at management's discretion. The repurchase program does not obligate the Partnership to acquire any, or any specific number of, units and may be discontinued at any time.    

Capitalization and Liquidity Update

As of December 31, 2014, the Partnership's total liquidity was $268.5 million.  The Partnership's borrowing base under its senior secured credit facility totaled $320 million, and based on outstanding borrowings, the Partnership had approximately $107 million of availability under its senior secured credit facility. As of December 31, 2014 the market value of the 6.7 million remaining Regency units held by the Partnership was $159.7 million. The Partnership's cash balance at the end of the fourth quarter was $1.3 million. As of February 23, 2015, the Partnership's total liquidity was approximately $233 million, comprised of approximately $134 million of availability under its senior secured credit facility and approximately 4.1 million Regency units valued at $99 million.

As of December 31, 2014, the Partnership had 152.2 million common units outstanding eligible to receive the distribution, including 2.1 million unvested restricted common units issued under the Partnership's Amended and Restated Long-Term Incentive Plan. The Partnership had 150.9 million total common units outstanding eligible to receive the distribution as of February 23, 2015, including 1.9 million unvested restricted common units issued under its Amended and Restated Long-Term Incentive Plan.

First Quarter and Full Year 2015 Guidance

During the first quarter of 2015, the Partnership plans to spend approximately $27 million on capital expenditures and expects $14 million to be categorized as maintenance capital expenditures and $13 million to be categorized as growth capital expenditures. Subject to results from the Partnership's drilling program, the Partnership expects to average between 73 and 75 MMcfe/d during first quarter 2015.

For full year 2015, the Partnership plans to spend approximately $72 million on capital expenditures, and expects $54 million to be categorized as maintenance capital expenditures and $18 million to be categorized as growth capital expenditures. This is a reduction of 46% as compared to 2014 total capital expenditures of $134 million. Subject to results from the Partnership's drilling program, the Partnership expects to average between 74 and 76 MMcfe/d for full year 2015.  The Partnership currently expects its quarterly General & Administrative expenses, excluding amortization of expenses related to its Long Term Incentive Plan, to average a run rate between $7.3 and $7.7 million per quarter during 2015.

Hedging Update

The Partnership employs risk mitigation strategies to protect its cash flows and reduce volatility in the Partnership's cash flows from commodity price fluctuations. One important risk mitigation strategy is the use of commodity price hedging to lock in stable cash flows. As of February 25, 2015, the Partnership's hedge portfolio had an estimated mark-to-market value of approximately $100 million. The Partnership's estimated hedge profile is as follows:

Note: Percent-hedged depicted against midpoint of 2015 production guidance (i.e., 75 MMcfe/d) held flat for 2015 and (for ease of modeling but not as guidance) for 2016 through 2019.

The Partnership has not entered into any additional commodity hedges since its last hedging update on February 25, 2015. The latest presentation can be accessed by going to www.eaglerockenergy.com: select Investor Relations, then select Presentations.

2014 K-1 Tax Information

2014 tax packages, including Schedule K-1, are expected to be available online through Eagle Rock's website and mailed in mid-March.

Fourth Quarter and Full Year 2014 Conference Call Information

Eagle Rock will hold a conference call to discuss its fourth quarter 2014 financial and operating results on Thursday, February 26, 2015 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 72079318. 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 72079318. 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.

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 gains and losses arising from interest rate risk management instruments that settled during the period 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; mark-to-market (gains) losses on commodity and interest rate risk management related instruments; (gains) losses on discontinued operations; and other (income) expense.

Eagle Rock uses Adjusted EBITDA as a measure of its core profitability to assess the financial performance of its assets. Adjusted EBITDA also is used as a supplemental financial measure by external users of Eagle Rock's financial statements such as investors, commercial banks and research analysts. For example, the Partnership's lenders under its revolving credit facility use a variant of its Adjusted EBITDA in a compliance covenant designed to measure the viability of Eagle Rock and its ability to perform under the terms of the revolving credit facility; Eagle Rock, therefore, uses Adjusted EBITDA to measure its compliance with its revolving credit facility. Eagle Rock believes that investors benefit from having access to the same financial measures that its management uses in evaluating performance. Adjusted EBITDA is useful in determining Eagle Rock's ability to sustain or increase distributions. By excluding unrealized derivative gains (losses), a non-cash, mark-to-market benefit (charge) which represents the change in fair market value of the Partnership's executed derivative instruments and is independent of its assets' performance or cash flow generating ability, Eagle Rock believes Adjusted EBITDA reflects 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. Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flows provided by operating activities or any other measure of financial performance presented in accordance with GAAP.

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 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; drilling and geological / exploration risks; market demand for crude oil, natural gas and natural gas liquids; our ability to make favorable acquisitions; 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, 2014 and the Partnership's Forms 10-Q filed with the SEC for subsequent quarters as well as any other public filings and press releases.