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 2-May-2014All Recent SEC Filings

Show all filings for EAGLE ROCK ENERGY PARTNERS L P

Form 10-Q for EAGLE ROCK ENERGY PARTNERS L P


2-May-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:
Risks related to the Midstream Business Contribution;

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;

Our significant existing indebtedness;

Hedging activities;

Ability to obtain credit and access capital markets;

Ability to remain in compliance with the covenants set forth in our credit facility and the indenture governing our Senior Notes;

Conditions in the securities and/or capital markets;

Future processing volumes and throughput;

Loss of significant customers;

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;

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

Shortages of personnel and equipment;

Potential losses associated with trading in derivative contracts;

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.

We are a domestically-focused, growth-oriented, publicly-traded Delaware limited partnership engaged in the following two businesses:

Upstream Business-developing and producing oil and natural gas property interests; and

Midstream Business-gathering, compressing, treating, processing, transporting, marketing and trading natural gas; fractionating, transporting and marketing NGLs; and crude oil and condensate logistics and marketing.

We conduct, evaluate and report on our Upstream Business as one segment, which includes 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). During the three months ended March 31, 2014, our Upstream Business had operating income of $20.2 million, compared to operating income of $12.3 million during the three months ended March 31, 2013.

We conduct, evaluate and report on our Midstream Business within three segments-the Texas Panhandle Segment, the East Texas and Other Midstream Segment and the Marketing and Trading Segment. On October 1, 2012, we completed our acquisition of BP America Production Company's ("BP") Texas Panhandle midstream assets (the "Panhandle Acquisition"), as discussed further below. Our Texas Panhandle Segment consists of gathering and processing assets in the Texas Panhandle. Our East Texas and Other Midstream Segment consists of gathering and processing assets in East Texas/Northern Louisiana, South Texas, Southern Louisiana, the Gulf of Mexico and Galveston Bay. Our Marketing and Trading Segment consists of crude oil and condensate logistics and marketing in the Texas Panhandle and Alabama and natural gas marketing and trading. During the three months ended March 31, 2014, our Midstream Business had operating income of $14.8 million, compared to an operating loss of $7.6 million during the three months ended March 31, 2013.

Our final reporting segment is our Corporate and Other Segment, which is where we account for our risk management activity (excluding any risk management activity associated with our natural gas marketing and trading activities), intersegment eliminations and our general and administrative expenses. During the three months ended March 31, 2014, our Corporate and Other Segment had an operating loss of $36.3 million, compared to an operating loss of $37.3 million during the three months ended March 31, 2013. Results reflected a net loss on our commodity derivatives of $14.9 million during the three months ended March 31, 2014, compared to a net loss on our commodity derivatives of $17.9 million during the three months ended March 31, 2013 . See "-Results of Operations - Corporate and Other Segment" for a further discussion of the impact of our commodity derivatives.

Recent Developments

On December 23, 2013, we announced that we had entered into a definitive agreement to contribute our Midstream Business to Regency for total consideration of up to $1.325 billion, consisting of $200 million of newly issued Regency common units (8,245,859 common units, calculated by taking the volume-weighted average price of a single Regency common unit for the ten trading days immediately preceding the announcement date) and a combination of cash and assumed debt, subject to certain closing conditions. As part of the transaction, Regency is conducting an offer to exchange our $550 million of outstanding senior unsecured notes into an equivalent amount of Regency senior unsecured notes with the same tenor, coupon and a comparable covenant package. The cash portion of the purchase price will be reduced by the amount of notes exchanged subject to a 10% adjustment factor, such that if all $550 million of bonds are exchanged, the total consideration will equal $1.27 billion ($1.325 billion less $55 million) consisting of $200 million in Regency units, $550 million of assumed debt and $520 million of cash proceeds.

The Midstream Business Contribution was approved by our common unitholders on April 29, 2014. As of that date, all significant closing conditions for the transaction had been satisfied other than the approval from the Federal Trade Commissions ("FTC") anti-trust review. On February 27, 2014, we and Regency received a Request for Additional Information and Documentary Materials ("Second Request") from the FTC in connection with the Midstream Business Contribution. On


Table of Contents

April 30, 2014, we and Regency certified our substantial compliance with the FTC's Second Request and entered into a timing agreement with the FTC agreeing to extend the FTC's review period until June 30, 2014, unless the FTC completes its investigation earlier.

Impairment

During the three months ended March 31, 2014, we recorded an impairment charge of $2.1 million in our East Texas and Other Segment due to the loss of two customers on our North System. We did not recorded any impairment charges in Midstream Business during the three months ended March 31, 2013 nor did we incur any impairment charges in our Upstream Business during the three months ended March 31, 2014 and 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.


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 months ended March 31, 2014 and 2013.

                                                                      Three Months Ended
                                                                           March 31,
                                                                      2014          2013
                                                                       ($ in thousands)
Revenues:
Natural gas, natural gas liquids, oil, condensate, sulfur and
helium sales                                                       $ 340,465     $ 254,200
Gathering, compression, processing and treating fees                  22,397        20,942
Commodity risk management gains (losses), net                        (14,944 )     (17,908 )
Other revenue                                                            156           497
Total revenue                                                        348,074       257,731
Cost of natural gas, natural gas liquids, condensate and helium      244,973       179,988
Costs and expenses:
Operations and maintenance                                            34,671        32,219
Taxes other than income                                                5,667         3,866
General and administrative                                            21,391        18,847
Impairment                                                             2,097             -
Depreciation, depletion and amortization                              40,508        40,237
Total costs and expenses                                             104,334        95,169
Operating loss                                                        (1,233 )     (17,426 )
Other income (expense):
Interest expense, net                                                (17,986 )     (17,084 )
Interest rate risk management losses, net                               (290 )        (156 )
Other expense, net                                                        (7 )          (8 )
Total other expense                                                  (18,283 )     (17,248 )
Loss before income taxes                                             (19,516 )     (34,674 )
Income tax benefit                                                      (953 )      (1,160 )
Net loss                                                           $ (18,563 )   $ (33,514 )
Adjusted EBITDA(a)                                                 $  57,589     $  53,617


________________________


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


Table of Contents

Upstream Segment
                                                                              Three Months Ended
                                                                                  March 31,
                                                                             2014              2013
                                                                  (Amounts in thousands, except volumes
                                                                          and realized prices)
Revenues:
Oil and condensate                                                    $         27,134     $    12,313
Intersegment sales - condensate                                                      -          11,286
Natural gas                                                                     11,651           8,181
Intersegment sales - natural gas                                                 2,948           1,814
NGLs                                                                            11,466          10,276
Sulfur                                                                           1,885           2,935
Other                                                                              152             497
Total revenue                                                                   55,236          47,302
Operating Costs and expenses:
Operations and maintenance                                                      15,289          14,116
Depletion, depreciation and amortization                                        19,725          20,929
Total operating costs and expenses                                              35,014          35,045
Operating income                                                      $         20,222     $    12,257

Capital expenditures                                                  $         39,258     $    34,050

Realized average prices:
Oil and condensate (per Bbl)                                          $          85.56     $     84.56
Natural gas (per Mcf)                                                 $           4.95     $      3.19
NGLs (per Bbl)                                                        $          41.90     $     35.45
Sulfur (per Long ton)                                                 $          77.05     $    110.34
Production volumes:
Oil and condensate (Bbl)                                                       317,126         279,069
Natural gas (Mcf)                                                            2,952,149       3,129,052
NGLs (Bbl)                                                                     273,673         289,866
Total (Mcfe)                                                                 6,496,943       6,542,662
Sulfur (Long ton)                                                               24,461          26,598

Revenues. For the three months ended March 31, 2014, Upstream Segment revenues increased by $7.9 million, as compared to the three months ended March 31, 2013. The increase in revenues for the three months ended March 31, 2014 compared to the three months ended March 31, 2013 was due to to higher realized oil, NGL and natural gas prices and higher oil volumes, partially offset by lower natural gas, NGL and sulfur volumes and lower sulfur prices.

Production volumes during the three months ended March 31, 2014 were negatively impacted by cold weather. We estimate that the lost revenues were approximately $1.5 million, excluding the impact of severance tax, as a result of the severe winter weather. Volumes returned to normal production in the latter part of the quarter.

On February 7, 2013, we suspended operations at our Flomaton treating facility in Escambia County, Alabama due to the failure of certain plant equipment and inlet volumes that were insufficient to operate the facility's sulfur recovery unit. To increase inlet volumes of the field to operate the treating facility we attempted to restore production from two wells connected to the facility, but these operations were unsuccessful. We resumed facility operations on April 18, 2013, after repairing the equipment and increasing inlet volumes by diverting production from a nearby operated well; however, on May 24, 2013, we again suspended operations due to equipment failure at the treating facility. On July 31, 2013, we received approval from the required percentage of owners of the Big Escambia Creek and Flomaton plants to resume operations by re-routing gas from the Flomaton facility to our Big Escambia Creek facility for treating and processing, while continuing to stabilize and sell the


Table of Contents

Flomaton field condensate at the Flomaton facility. We have currently spent $2.9 million on the project to re-route full well stream gas from the Flomaton facility to our Big Escambia Creek facility for treating and processing. We anticipate this project being completed by the end of the second quarter 2014.

Operating Expenses. Operating expenses, including severance and ad valorem taxes, increased $1.2 million for the three months ended March 31, 2014, as compared to the three months ended March 31, 2013. The increase was primarily due to higher severance tax due to higher sales value, a 2013 severance tax credit, weather related costs, and higher lease operating costs due to additional wells partially offset by lower workover costs.

Depletion, Depreciation and Amortization. Depletion, depreciation and amortization expense decreased by $1.2 million for the three months ended March 31, 2014, as compared to the same period in the prior year. The decrease for the three months ended March 31, 2014 was primarily a result of the impairment charges recorded during 2013.

Capital Expenditures. Capital expenditures increased by $5.2 million for the three months ended March 31, 2014, as compared to the three months ended March 31, 2013, primarily due to increased drilling activity.

During the three months ended March 31, 2014, we drilled and completed 4 gross (3.9 net) operated wells in the Mid-Continent region. Additionally, during the three months ended March 31, 2014, we conducted 5 gross (4.2 net) capital workovers and one gross (0.1 net) recompletion across our operations.


Table of Contents

Midstream Business (Three Segments)

Texas Panhandle Segment

                                                                                  Three Months Ended
                                                                                       March 31,
                                                                               2014                  2013
                                                                    (Amounts in thousands, except volumes and
                                                                                 realized prices)
Revenues:
Natural gas, natural gas liquids, condensate and helium sales            $    145,868           $    106,394
Intersegment sales - natural gas and condensate                                72,959                 49,135
Gathering, compression, processing and treating fees                           13,963                 12,521
Other revenue                                                                       4                      -
Total revenue                                                                 232,794                168,050
Cost of natural gas, natural gas liquids, condensate and helium (a)           189,904                132,226
Intersegment cost of sales - natural gas                                           63                     19
Operating costs and expenses:
Operations and maintenance                                                     20,317                 17,134
Depreciation and amortization                                                  15,626                 13,845
Total operating costs and expenses                                             35,943                 30,979
Operating income                                                         $      6,884           $      4,826

Capital expenditures                                                     $      8,363           $     18,303

Realized prices (b):
Condensate (per Bbl)                                                     $      83.15           $      80.34
Natural gas (per MMbtu)                                                  $       5.31           $       3.27
NGLs (per Bbl)                                                           $      44.20           $      35.53
Production volumes:
Gathering volumes (Mcf/d)(c)                                                  376,784                342,346
NGLs (net equity Bbls)                                                        263,340                 64,551
Condensate (net equity Bbls)                                                  288,360                275,692
Natural gas (MMbtu/d)(c)                                                         (613 )                3,379


_______________________


(a) Includes the cost of gathering, compression, processing and treating fees of $0.7 million and $0.3 million, respectively, for the three months ended March 31, 2014 and 2013.

(b) Excludes the impact of adjustments related to prior periods, including true-ups of estimates.

(c) Gathering volumes (Mcf/d) and natural gas positions (MMbtu/d) are calculated by taking the total volume and then dividing by the number of days in the respective period.

Revenues and Cost of Natural Gas, NGLs, Condensate and Helium. For the three months ended March 31, 2014, revenues minus cost of natural gas, NGLs, condensate and helium for our Texas Panhandle Segment operations totaled $42.8 million, compared to $35.8 million for the three months ended March 31, 2013. The increase for the three months ended March 31, 2014 was primarily due to increased realized commodity prices and increased volumes. Severe winter weather negatively impacted our results for the three months ended March 31, 2014 and the same period in the prior year by $2.4 million and $2.8 million, respectively. In addition, our results for the three months ended March 31, 2013 were negatively impacted by adjustments related to amounts recorded during the three months ended December 31, 2012. During the three months ended March 31, 2013, we received new information from BP, the operator of the assets acquired in the Panhandle Acquisition during the three months ended December 31, 2012, that the cost of natural gas, NGLs and condensate on the assets was higher than previously communicated.

Operating Expenses. Operating expenses, including taxes other than income, for the three months ended March 31, 2014, increased by $3.2 million, as compared to the three months ended March 31, 2013. The increase was primarily driven by by adjustments related to amounts recorded during the three months ended December 31, 2012. During the three months ended March 31, 2013, we received new information from BP that the costs of operating the plants and gathering systems,


Table of Contents

acquired as part of the Panhandle acquisition, during the three months ended December 31, 2012 were lower than previously communicated. Excluding these adjustments, operating expenses increased primarily due to higher chemical and utility costs and increased ad valorem taxes due to the addition of our new Woodall and Wheeler plants.

Depreciation and Amortization. Depreciation and amortization expenses for the three months ended March 31, 2014 increased $1.8 million, from the three months ended March 31, 2013. The increase was due to increased depreciation expense primarily associated with the new Wheeler Plant and other capital projects placed into service during the period.

Capital Expenditures. Capital expenditures for the three months ended March 31, 2014, decreased by $9.9 million, compared to the three months ended March 31, 2013. The decrease was primarily attributable to costs associated with the construction of our Wheeler Plant and the integration of the Panhandle Acquisition during the three months ended March 31, 2013, partially offset by increased spending on new well connections during the three months ended March 31, 2014.

East Texas and Other Midstream Segment
                                                                            Three Months Ended
                                                                                March 31,
                                                                         2014               2013
                                                                (Amounts in thousands, except volumes
                                                                        and realized prices)
Revenues:
Natural gas, natural gas liquids and condensate sales                $ 38,081           $    27,388
Intersegment sales - natural gas                                       17,861                 8,538
Gathering, compression, processing and treating fees (a)                8,392                 8,358
Total revenue                                                          64,334                44,284
Cost of natural gas, natural gas liquids, condensate and helium        55,069                33,234
Operating costs and expenses:
Operations and maintenance                                              4,724                 4,829
Impairment                                                              2,097                     -
Depreciation and amortization                                           4,334                 5,002
Total operating costs and expenses                                     11,155                 9,831
Operating (loss) income                                              $ (1,890 )         $     1,219

Capital expenditures                                                 $  1,851           $     1,776

Realized prices (b):
Condensate (per Bbl)                                                 $  97.53           $     94.25
Natural gas (per MMbtu)                                              $   4.84           $      3.36
NGLs (per Bbl)                                                       $  39.21           $     29.98
Production volumes:
Gathering volumes (Mcf/d)(c)                                          204,701               200,700
NGLs (net equity Bbls)                                                 16,200                53,204
Condensate (net equity Bbls)                                           11,610                 5,226
Natural gas (MMbtu/d)(c)                                                 (459 )                 344


_________________________

(a) Includes the cost of gathering, compression, processing and treating fees of $0.8 million and $0.5 million, for the three months ended March 31, 2014 and 2013, respectively.

. . .

  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.