Search the web
Welcome, Guest
[Sign Out, My Account]
EDGAR_Online

Quotes & Info
Enter Symbol(s):
e.g. YHOO, ^DJI
Symbol Lookup | Financial Search
EROC > SEC Filings for EROC > Form 10-Q on 4-Aug-2014All Recent SEC Filings

Show all filings for EAGLE ROCK ENERGY PARTNERS L P

Form 10-Q for EAGLE ROCK ENERGY PARTNERS L P


4-Aug-2014

Quarterly Report


Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
This report includes "forward-looking statements" as defined by the Securities and Exchange Commission (the "SEC"). All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These statements are based on certain assumptions made by us based on our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate under the circumstances. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control, which may cause our actual results to differ materially from those implied or expressed by the forward-looking statements. We do not assume any obligation to update such forward-looking statements following the date of this report. For a complete description of known material risks, please read our risk factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2013 and in "Part II. Item 1A. Risk Factors." These factors include but are not limited to:

Drilling and geological / exploration risks;

Assumptions regarding oil and natural gas reserve levels and costs to exploit and timing of development;

Volatility or declines (including sustained declines) in commodity prices;

Ability to make favorable acquisitions and integrate operations from such acquisitions;

Our existing indebtedness;

Hedging activities;

Ability to obtain credit and access capital markets;

Ability to remain in compliance with the covenants set forth in our revolving credit facility;

Conditions in the securities and/or capital markets;

Availability and cost of processing and transporting of natural gas liquids ("NGLs");

Competition in the oil and natural gas industry;

Relevant legislative or regulatory changes, including retroactive royalty or production tax regimes, changes in environmental, health and safety regulation, hydraulic fracturing regulation, environmental risks and liability under federal, state and foreign environmental laws and regulations;

Shortages of personnel and equipment;

Increases in interest rates;

Creditworthiness of our counterparties;

Weather, including the occurrence of any adverse weather conditions and/or natural disasters affecting our business;

Any other factors that impact or could impact the exploration of oil or natural gas resources, including but not limited to the geology of a resource, the total amount and costs to develop recoverable reserves, legal title, regulatory, natural gas administration, marketing and operations factors relating to the extraction of oil and natural gas;

Tax risk associated with pass-through investment, including potential reduction in tax shield or creation of phantom income in the event distributions are not enough to support the tax burden; and

Impact of cyber-security threats and related disruptions.


Table of Contents

OVERVIEW

The following discussion and analysis of financial condition and results of operations should be read in conjunction with our unaudited condensed consolidated financial statements, and the notes thereto, appearing elsewhere in this report, as well as our Annual Report on Form 10-K for the year ended December 31, 2013 filed with the Securities and Exchange Commission. For a description of oil and natural gas terms, see our Annual Report on Form 10-K for the year ended December 31, 2013.

Recent Developments

On December 23, 2013, we announced that we had entered into a definitive agreement to contribute our gathering, compressing, treating, processing, transporting, marketing and trading natural gas; fractionating, transporting and marketing NGLs; and crude oil and condensate logistics and marketing assets and businesses ("Midstream Business") to Regency Energy Partners LP ("Regency") (the "Midstream Business Contribution"). The Midstream Business Contribution was approved by the Partnership's common unitholders on April 29, 2014. On June 27, 2014, the Partnership announced that the Federal Trade Commission had voted to close its investigation into the contribution of its Midstream Business to Regency. As of that date, all significant closing conditions for the transaction had been satisfied and the Partnership has classified the assets and liabilities of its Midstream Business as held for sale and the operations as discontinued.

On July 1, 2014, we completed the contribution of our Midstream Business to Regency. The consideration received by us for the contribution of our Midstream Business included: (i) $576.2 million of cash; (ii) 8,245,859 Regency common units (valued at approximately $265 million based on the closing price of Regency common units on June 30, 2014) and (iii) the exchange of $498.9 million face amount of newly-issued Regency 8.375% Senior Notes due 2019 for $498.9 million face amount of our existing 8.375% Senior Notes.

Results Overview

As a result of the contribution of our Midstream Business, we are now a domestically-focused, growth-oriented, publicly-traded Delaware limited partnership engaged in developing and producing oil and natural gas property interests. Our interests include operated and non-operated wells located in the Mid-Continent (which includes areas in Oklahoma, Arkansas, and the Texas Panhandle); Permian (which includes areas in West Texas); East Texas / South Texas / Mississippi; and Southern Alabama (which also includes two treating facilities and one natural gas processing plant and related gathering systems).

Results for the three and six months ended June 30, 2014, included the following:

         revenues, excluding the impact of commodity risk management gains
          (losses) were $52.1 million and $107.4 million, respectively, for the
          three and six months ended June 30, 2014, compared to $49.3 million and
          $96.6 million for the three and six months ended June 30, 2013;


         commodity risk management losses were $18.1 million and $28.1 million,
          respectively, for the three and six months ended June 30, 2014,
          compared to commodity risk management gains of $17.3 million and $10.5
          million, respectively, for the three and six months ended June 30,
          2013;


         operating losses were $12.8 million and $16.5 million, respectively,
          for the three and six months ended June 30, 2014, compared to operating
          gains of $16.3 million and $8.0 million, respectively, for the three
          and six months ended June 30, 2013;


         average daily production was 72 MMcfe/d for the six months ended
          June 30, 2014, compared to 73 MMcfe/d for the six months ended June 30,
          2013; and


         capital expenditures were $35.7 million and $75.0 million,
          respectively, for the three and six months ended June 30, 2014,
          compared to $35.1 million and $69.2 million, respectively, for the
          three and six months ended June 30, 2013.

Impairment

During the three and six months ended June 30, 2013, we recorded an impairment charge of $1.8 million in our Upstream Business related to certain proved properties in our Permian region due to lower commodity prices and continued higher operating costs. We did not recorded any impairment charges in our Upstream Business during the three and six months ended June 30, 2014. During the six months ended June 30, 2014, we recorded an impairment charge of $2.1 million in our Midstream Business due to the loss of two customers on our North System. This charge is included within discontinued


Table of Contents

operations. We did not record any impairment charges in Midstream Business during the three months ended June 30, 2014 or the three and six months ended June 30, 2013.

Pursuant to accounting principles generally accepted in the United States of America ("GAAP"), our impairment analysis does not take into account the value of our commodity derivative instruments, which generally increase as the estimates of future prices decline. Further declines in commodity prices and other factors could result in additional impairment charges and changes to the fair value of our derivative instruments.

Subsequent Events

On July 1, 2014, we used the cash received from Regency for the Midstream Business Contribution (see above) to paydown $570.4 million outstanding under the Credit Agreement. Accordingly, as of July 1, 2014, the amount outstanding under the Credit Agreement was $198.6 million.
In addition, $51.1 million of our Senior Notes did not exchange in connection with the Midstream Business Contribution and remain outstanding. However, having secured a sufficient number of consents as part of the exchange offer, we amended the indenture governing our Senior Notes to eliminate substantially all of the restrictive covenants and certain events of default pertaining to its Senior Notes.


Table of Contents

RESULTS OF OPERATIONS

Summary of Consolidated Operating Results

Below is a table of a summary of our consolidated operating results for the
three and six months ended June 30, 2014 and 2013.

                                                    Three Months Ended          Six Months Ended
                                                         June 30,                   June 30,
                                                    2014          2013         2014          2013
                                                                    ($ in thousands)
Revenues:
Oil and condensate                                  26,493       24,976        53,627        48,575
Natural gas                                         12,899       12,729        27,498        22,724
NGLs                                                10,247        8,596        21,713        18,872
Sulfur                                               2,328        2,951         4,213         5,886
Commodity risk management gains (losses), net      (18,081 )     17,338       (28,114 )      10,502
Other revenue                                          158           76           310           573
Total revenue                                       34,044       66,666        79,247       107,132
Costs and expenses:
Operations and maintenance                          10,907        9,579        22,405        21,279
Taxes other than income                              3,596        3,583         7,387         5,999
General and administrative                          12,005       13,341        25,295        26,651
Impairment                                               -        1,839             -         1,839
Depreciation, depletion and amortization            20,299       22,060        40,705        43,356
Total costs and expenses                            46,807       50,402        95,792        99,124
Operating (loss) income                            (12,763 )     16,264       (16,545 )       8,008
Other income (expense):
Interest expense, net                               (4,948 )     (4,499 )      (9,702 )      (9,564 )
Interest rate risk management losses, net             (571 )       (151 )        (861 )        (307 )
Other income (expense), net                              2          (27 )           3           (35 )
Total other expense                                 (5,517 )     (4,677 )     (10,560 )      (9,906 )
(Loss) income before income taxes                  (18,280 )     11,587       (27,105 )      (1,898 )
Income tax benefit                                    (885 )       (544 )      (1,750 )      (2,105 )
(Loss) income from continuing operations           (17,395 )     12,131       (25,355 )         207
Discontinued operations, net of tax                (25,646 )      3,901       (36,249 )     (17,689 )
Net (loss) income                                $ (43,041 )   $ 16,032     $ (61,604 )   $ (17,482 )
Adjusted EBITDA(a)                               $  24,899     $ 29,372     $  50,995     $  56,720


________________________


(a) See "-Liquidity and Capital Resources - Non-GAAP Financial Measures" for a definition and reconciliation to GAAP.


Table of Contents

                                   Three Months Ended              Six Months Ended
                                        June 30,                       June 30,
                                  2014             2013           2014           2013

Realized average prices:
Oil and condensate (per Bbl) $    88.21        $     84.85    $     86.85    $     84.71
Natural gas (per Mcf)        $     4.38        $      4.00    $      4.66    $      3.60
NGLs (per Bbl)               $    35.38        $     30.90    $     38.55    $     33.22
Sulfur (per Long ton)        $    91.09        $    110.75    $     84.22    $    110.54
Production volumes:
Oil and condensate (Bbl)        300,330            294,353        617,456        573,421
Natural gas (Mcf)             2,943,718          3,181,264      5,895,866      6,310,316
NGLs (Bbl)                      289,639            278,158        563,312        568,024
Total (Mcfe)                  6,483,532          6,616,330     12,980,474     13,158,986
Sulfur (Long ton)                25,554             26,641         50,015         53,240

Capital expenditures             36,106             36,740         76,941         72,458

Commodity Revenues. For the three and six months ended June 30, 2014, commodity revenues increased by $2.8 million and $10.7 million, respectively, as compared to the three and six months ended June 30, 2013. The increase in revenues for the three months ended June 30, 2014 compared to the three months ended June 30, 2013 was due to to higher realized oil, NGL and natural gas prices and higher oil and NGL volumes, partially offset by lower natural gas and sulfur volumes and lower sulfur prices. The increase in revenues for the six months ended June 30, 2014, as compared to the six months ended June 30, 2013, was due to higher oil, NGL and natural gas prices and higher oil volumes, offset by decreases in sulfur prices and lower natural gas, NGL and sulfur volumes.

Production volumes during the three and six months ended June 30, 2014 were negatively impacted by performance on our Alabama wells due to unexpected increases in completion times as well as equipment delays and significant declines in production on our Mid-Continent wells due to offsetting fracing on other wells, delay in completions and poorer performance of certain wells.

Commodity Risk Management Gains (Losses), net. During the three and six months ended June 30, 2014, losses in our commodity derivative portfolio decreased by $35.4 million and $38.6 million, respectively, as compared to the three and six months ended June 30, 2013. During the three and six months ended June 30, 2014, losses in our mark-to-market commodity derivative portfolio increased by $29.4 million and $24.1 million as compared to the three and six months ended June 30, 2013, respectively, primarily due to increases in the natural gas, NGL and crude oil forward curves. Our gains from derivative contracts that settled during the three and six months ended June 30, 2014 decreased by $6.0 million and $14.6 million, respectively, compared to the three and six months ended June 30, 2013. The decrease was due to higher natural gas and crude oil index prices, partially offset by lower NGL index prices, in relation to the strike prices of our settled contracts, as compared to the same period in the prior year. In addition, the decrease in realized gains is due to the higher level of direct NGL product contracts that settled during the three and six months ended June 30, 2013, as compared to the same period in 2014.

Given the uncertainty surrounding future commodity prices, and the general inability to predict future commodity prices as they relate to the strike prices at which we have hedged our exposure, it is difficult to predict the magnitude and impact that marking our hedges to market will have on our income from operations in future periods.

Operating Expenses. Operating expenses, including severance and ad valorem taxes, increased $1.3 million and $2.5 million for the three and six months ended June 30, 2014, respectively, as compared to the three and six months ended June 30, 2013. The increase was primarily due to higher severance tax due to higher sales value, a 2013 severance tax credit, increased plant operating expense, and higher lease operating costs due to additional wells drilled.

General and Administrative Expenses. General and administrative expenses decreased by $1.3 million and $1.4 million for the three and six months ended June 30, 2014, respectively, as compared to the same period in 2013. This decrease was primarily due to lower equity based compensation expense due to increase made to the estimated forfeiture rate made during the three months ended June 30, 2014. The forfeiture rate is used to calculate the amount of equity based compensation expense.


Table of Contents

Depletion, Depreciation and Amortization. Depletion, depreciation and amortization expense decreased by $2.1 million and $3.3 million for the three and six months ended June 30, 2014, respectively, as compared to the same period in the prior year. The decrease for the three and six months ended June 30, 2014 was primarily a result of the impairment charges recorded during 2013 and overall decrease in production for the three and six months ended June 30, 2014 compared to the same periods in 2013.

Total Other Expense. Total other expense primarily consists of gains and losses from our interest rate swaps and interest expense related to our Credit Agreement and our senior unsecured notes. During the three and six months ended June 30, 2014, our interest rate risk management losses increased by $0.4 million and $0.6 million, respectively. as compared to the three and six months ended June 30, 2013. These increases were primarily due to decreases in the forward interest rate curve. These unrealized mark-to-market gains did not have any impact on cash activities for the period, and are excluded by definition from our calculation of Adjusted EBITDA.

Interest expense increased by $0.4 million for the three months ended June 30, 2014, as compared to the three months ended June 30, 2013 and decreased by $0.1 million during the three and six months ended June 30, 2014, respectively, as compared to the three and six months ended June 30, 2013. Interest expense is shown before the impact of our interest rate derivatives, which convert a portion of our outstanding debt from variable-rate interest obligations to fixed-rate interest obligations. The increase in interest expense is primarily due to increased borrowings on the Credit Agreement, offset by amounts allocated to discontinued operations.

Income Tax (Benefit) Provision. Income tax provision for 2014 and 2013 relates to (i) state taxes due by us and (ii) federal taxes due by Eagle Rock Energy Acquisition Co., Inc. and Eagle Rock Energy Acquisition Co. II, Inc. and their wholly-owned subsidiary corporations, Eagle Rock Upstream Development Company, Inc. and Eagle Rock Upstream Development Company II, Inc., all of which are subject to federal income taxes.

Discontinued Operations. On June 27, 2014, we announced that the Federal Trade Commission had voted to close its investigation into the contribution of our Midstream Business to Regency. As of that date, all significant closing conditions for the transaction had been satisfied and we have classified the assets of our Midstream Business as assets-held-for-sale or the operations as discontinued. The transaction was completed on July 1, 2014. Discontinued operations decreased by $29.5 million and $18.6 million, respectively, for the three and six months ended June 30, 2014, as compared to the three and six months ended June 30, 2013. The decrease in discontinued operations is primarily due to commodity risk management losses incurred during the three and six months ended June 30, 2014 and increased interest expense allocated to discontinued operations. In addition, included within discontinued operations for the three and six months ended June 30, 2014 are professional fees of $3.5 million and $6.2 million, respectively, and one-time termination benefits of $3.2 million. We expect to incur an additional $2.4 million of one-time termination benefits during the remainder of 2014. See Note 16 to the unaudited condensed consolidated financial statements for the major line items that comprise discontinued operations.

Capital Expenditures. Capital expenditures increased by $0.6 million and $5.8 million for the three and six months ended June 30, 2014, respectively, as compared to the three and six months ended June 30, 2013, primarily due to increased drilling activity.

During the three months ended June 30, 2014, we drilled and completed three gross (1.95 net) operated wells and participated in three gross (0.01 net) non-operated wells in the Mid-Continent region. Additionally, during the three months ended June 30, 2014, we conducted seven gross (5.66 net) capital workovers and three gross (3.00 net) recompletions across our operations.


Table of Contents

Adjusted EBITDA

Adjusted EBITDA, as defined under "-Liquidity and Capital Resources - Non-GAAP
Financial Measures," from continuing operations decreased by $4.5 million from
$29.4 million for the three months ended June 30, 2013 to $24.9 million for the
three months ended June 30, 2014. Adjusted EBITDA from continuing operations
decreased by $5.6 million for the six months ended June 30, 2014 as compared to
the same period in 2013. The following table presents the changes in operations
impacting Adjusted EBITDA:
                                                 Three Months Ended                      Six Months Ended
                                                      June 30,                               June 30,
                                           2014         2013        Change        2014          2013        Change

Revenues (a)                            $ 52,124     $ 49,323     $  2,801     $ 107,354     $ 96,625     $ 10,729
Commodity derivative settlements          (2,176 )      3,858       (6,034 )      (5,314 )      9,236      (14,550 )
Operating expenses                        14,503       13,162        1,341        29,792       27,278        2,514
General and administrative expenses (b)   10,546       10,647         (101 )      21,253       21,946         (693 )
Adjusted EBITDA (c)                     $ 24,899     $ 29,372     $ (4,473 )   $  50,995     $ 56,637     $ (5,642 )


_________________________

(a) Excludes the impact of imbalances.

(b) Excludes non-cash compensation charges related to our long-term incentive program.

(c) See "-Liquidity and Capital Resources - Non-GAAP Financial Measures" for a definition and reconciliation to GAAP.


Table of Contents

LIQUIDITY AND CAPITAL RESOURCES

Historically, our sources of liquidity have included cash generated from operations, issuances of equity and debt securities, asset sales and borrowings under our revolving Credit Agreement Our primary cash requirements have included general and administrative expenses, operating expenses, maintenance and growth capital expenditures, short-term working capital needs, interest payments on our outstanding debt, distributions to our unitholders and acquisitions of new assets or businesses.

In connection with the consummation of the Midstream Business Contribution, we were able to improve our liquidity position by paying down our borrowings under our Credit Agreement, resulting in increased borrowing availability, and exchanging $498.9 million of our Senior Notes, resulting in significantly decreased debt levels. In addition, we received 8,245,859 Regency common units (valued at approximately $265 million based on the closing price of Regency common units on June 30, 2014), which could be a potential source of future liquidity.

We believe that our improved liquidity position as a result of the Midstream Business Contribution and our historical sources of liquidity will be sufficient to satisfy our short-term liquidity needs and to fund our committed capital expenditures for at least the next twelve months. Our growth strategy entails pursuing attractive upstream acquisitions and organic drilling opportunities. We may utilize any of various available financing sources, including liquidity from the consummation of the Midstream Business Contribution, proceeds from the issuance of equity or debt securities, or borrowings from our Credit Agreement to fund all or a portion of our potential acquisitions and organic growth expenditures. Our ability to complete future offerings of equity or debt securities and the timing of these offerings will depend upon various factors including prevailing market conditions and our financial condition.

Equity Offerings

On May 31, 2012, we announced a program through which we may issue common units, from time to time, with an aggregate market value of up to $100 million. We are under no obligation to issue equity under the program. We intend to use the net proceeds from any sales under the program for general partnership purposes, which may include, among other things, repayment of indebtedness, acquisitions, capital expenditures and additions to working capital. As of June 30, 2014, a total of 1,521,086 units had been issued under this program for net proceeds of approximately $12.9 million. No sales were made under the program during the three and six months ended June 30, 2014.

Capital Expenditures

The energy business can be capital intensive, requiring significant investment for the acquisition or development of new facilities. Due to the completion of the contribution of our Midstream Business to Regency on July, 1, 2014, we now categorize our capital expenditures as (and, as necessary, allocate the attributable portion of our capital expenditures between) either:

growth capital expenditures, defined as expenditures to grow our natural gas, NGL, crude or sulfur production; or

maintenance capital expenditures, defined as expenditures necessary to maintain our natural gas, NGL, crude or sulfur production. With respect to maintenance capital expenditures intended to maintain our 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 our projections and expectations, including, without limitation, on account of: (i) unanticipated mechanical issues; (ii) unanticipated . . .

  Add EROC to Portfolio     Set Alert         Email to a Friend  
Get SEC Filings for Another Symbol: Symbol Lookup
Quotes & Info for EROC - All Recent SEC Filings
Copyright © 2014 Yahoo! Inc. All rights reserved. Privacy Policy - Terms of Service
SEC Filing data and information provided by EDGAR Online, Inc. (1-800-416-6651). All information provided "as is" for informational purposes only, not intended for trading purposes or advice. Neither Yahoo! nor any of independent providers is liable for any informational errors, incompleteness, or delays, or for any actions taken in reliance on information contained herein. By accessing the Yahoo! site, you agree not to redistribute the information found therein.