10-K 1 a2012form10-k.htm 10-K 2012 Form 10-K
 
 
 
 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-K
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the fiscal year ended December 31, 2012
 OR
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the transition period from ________ to ________
Commission File No. 001-33016
 EAGLE ROCK ENERGY PARTNERS, L.P.
(Exact Name of Registrant as Specified in Its Charter)
Delaware
 
68-0629883
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification Number)
 1415 Louisiana Street, Suite 2700
Houston, Texas 77002
(Address of principal executive offices, including zip code)

(281) 408-1200
(Registrant's telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
 
 
Name of Each Exchange on Which Registered
 
Common Units of Limited Partner Interests
 
NASDAQ Global Select Market
Warrants to Purchase Common Units of Limited Partner Interests
 
NASDAQ Global Select Market
 Securities registered pursuant to Section 12(g) of the Act:
None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.     Yes  x    No  o


Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.    Yes  o    No  x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 13(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes  x No  o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes  x    No  o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated Filer  x
Accelerated Filer  o
Non-accelerated Filer  o
Smaller reporting company  o
 (Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  o    No  x

As of June 30, 2012, the aggregate market value of the registrant's common units held by non-affiliates of the registrant was $721,713,198 based on the closing sale price as reported on NASDAQ Global Select Market.

The issuer had 147,345,997 common units outstanding as of February 25, 2013.

 DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the registrant's definitive proxy statement for its 2013 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2012, are incorporated by reference into Part III of this report for the year ended December 31, 2012.



TABLE OF CONTENTS
 
 
 
Page 
PART I
Item 1.
Business
Item 1A.
Risk Factors
Item 1B.
Unresolved Staff Comments
Item 2.
Properties
Item 3.
Legal Proceedings
Item 4.
Mine Safety Disclosures
PART II
Item 5.
Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
Item 6.
Selected Financial Data
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
Item 8.
Financial Statements and Supplementary Data
Item 9.
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
Item 9A.
Controls and Procedures
Item 9B.
Other Information
PART III
Item 10.
Directors, Executive Officers and Corporate Governance
Item 11.
Executive Compensation
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
Item 13.
Certain Relationships and Related Transactions, and Director Independence
Item 14.
Principal Accounting Fees and Services
PART IV
Item 15.
Exhibits and Financial Statement Schedules
 

 


1


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 under Item 1A of this Annual Report on Form 10-K. 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;
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 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 transportation 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, including our recent acquisition of the BP Texas Panhandle midstream assets;
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; and
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.


i


GLOSSARY OF OIL AND GAS TERMS
 
The following is a description of the meanings of some of the oil and gas industry terms that may be used in this report. The definitions of proved reserves, proved developed reserves, and proved undeveloped reserves have been abbreviated from the applicable definitions contained in Rule 4-10(a) (2-4) of Regulation S-X.
 
Bbl:    One stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons.
 
Bbl/d:    One stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons per day.
 
Bcf:    One billion cubic feet of natural gas.
 
Bcf/d:  One billion cubic feet of natural gas per day. 
 
Bcfe: One billion cubic feet of natural gas equivalent, using a ratio of six Mcf of natural gas to one Bbl of crude oil and NGLs.
 
Boe:    One barrel of oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil.
 
btu:    British thermal unit.
 
development well:    A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.
 
dry gas:    Natural gas that does not require plant processing prior to delivery to the interstate or intrastate pipeline systems.
 
equity liquids or gallons:    Natural gas liquid and condensate production that equates to an entity's contractual share of the production.
 
exploitation:    A drilling, recompletion, workover or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than with exploration projects.
 
exploratory well:    A well drilled to find and produce oil or natural gas reserves in an unproved area, to find new reservoir in a field previously found to be productive or oil or natural gas in another reservoir or to extend a known reservoir.
 
fee mineral or fee mineral interest:    A perpetual ownership of all or a portion of the oil, natural gas and other naturally-occurring substances that lie beneath the surface of the earth in a specific area.
 
field:    An area consisting of a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

frac spread:    The difference between the value of the NGLs produced and the cost of the processed gas used to replace the thermal equivalent value of those NGLs in a keep-whole arrangement.
 
gpm:    Gallons of natural gas liquids per million cubic feet of gas.
 
gross acres or gross wells:    The total acres or wells, as the case may be, in which a working interest is owned.
 
Hp:    Horsepower.
 
MBbls:    One thousand barrels of crude oil or other liquid hydrocarbons.
 
MBO/d:    One thousand barrels of crude oil or other liquid hydrocarbons per day.
 
Mcf:    One thousand cubic feet of natural gas.
 
Mcf/d:    One thousand cubic feet of natural gas per day.
 
Mcfe:    One thousand cubic feet of natural gas equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil and NGLs.
 
MMBbls:    One million barrels of crude oil or other liquid hydrocarbons.
 
MMBoe:    One million barrels of oil equivalent.
 
MMBtu:    One million British thermal units.
 
MMcf:    One million cubic feet of natural gas.
 
MMcf/d:    One million cubic feet of natural gas per day.

ii


 
natural gas liquids or NGLs:    The combination of ethane, propane, isobutane, normal butane and natural gasoline that may be removed from natural gas as a liquid under certain levels of pressure and temperature. Most NGLs are gases at room temperature and pressure.
 
net acres or net wells:    The sum of the fractional working interests owned in gross acres or wells, as the case may be.
 
NYMEX:    New York Mercantile Exchange.
 
oil:    Crude oil and condensate.
 
overriding royalty or overriding royalty interest:    A non-cost bearing interest in the production from a well that is carved out of the working interest. It expires when the underlying oil and/or natural gas lease expires.
 
probable locations:    Locations that are near proved undeveloped locations, but do not meet the definition of a proved location.
 
productive well:    A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.
 
proved developed reserves:    Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.
 
proved locations:    Locations that geological and engineering data demonstrate with reasonable certainty to recover reserves in future years from known reservoirs under existing economic and operating conditions.
 
proved reserves:    The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made.  Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based on future conditions.
 
proved undeveloped reserves or PUDs:    Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
 
recompletion:    The completion for production of an existing wellbore in another formation from that in which the well has been previously completed.
 
reserve life index:    The number of years required to produce the proved reserves at the current annual production rate.
 
reservoir:    A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.
 
royalty or royalty interest:    A non-cost bearing interest in the production from a well that is created from a mineral interest when the minerals are leased to an operator. The royalty interest generally is retained by the mineral interest owner as part of the compensation for leasing the minerals.
 
standardized measure:    The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Standardized measure does not give effect to derivative transactions.
 
undeveloped acreage:    Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas or oil regardless of whether or not such acreage contains proved reserves.
 
unit development cost (UDC):  The capital expenditures required to develop proved reserves per unit of reserves added or transferred from undeveloped acreage non-producing acreage to proved developed producing reserves, expressed in $/Mcfe or $/Boe.
 
West Texas Intermediate or WTI:    Light, sweet crude oil with high API gravity and low sulfur content used as the benchmark for U.S. crude oil refining and trading. NYMEX futures contracts for light, sweet crude oil specify the delivery of WTI at Cushing, Oklahoma.
 
wet gas:  Natural gas that requires plant processing in order to meet the interstate and intrastate gas quality specifications.
 
working interest:    The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property/lease and to receive a share of production.
 
workover:    Operations on a producing well to restore or increase production.


iii


In this Annual Report on Form 10-K, as the context requires, references to “Eagle Rock Energy Partners, L.P.,” “Eagle Rock,” the “Partnership,” “we,” “our,” “us,” or like terms, refer to Eagle Rock Energy Partners, L.P. and/or one or more of its subsidiaries. References to our “general partner” refer to Eagle Rock Energy GP, L.P., and the general partner of Eagle Rock Energy GP, L.P., Eagle Rock Energy G&P, LLC, both wholly-owned subsidiaries of the Partnership. References to “Natural Gas Partners” or “NGP” refer to Natural Gas Partners VII, L.P. and Natural Gas Partners VIII, L.P. in the context of any description of our investors, and in other contexts refer to NGP Energy Capital Management, which manages a series of energy investment funds, including Natural Gas Partners VII, L.P. and Natural Gas Partners VIII, L.P. References to the “NGP Investors” refer to Natural Gas Partners and some of our directors and current and former members of our management team. References to our “Board of Directors” or "Board" refer to the board of directors of Eagle Rock Energy G&P, LLC.
 
PART I


Item 1.
Business.

Overview
 
We are a domestically-focused, growth-oriented limited partnership engaged in the business of (i) gathering, compressing, treating, processing and transporting natural gas; fractionating and transporting natural gas liquids (“NGLs”); crude oil and condensate logistics and marketing; and natural gas marketing and trading, which collectively we call our “Midstream Business”; and (ii) developing and producing interests in oil and natural gas properties, which we call our “Upstream Business.”   
 
Our objective is to grow our business in a manner that enhances our ability to increase cash distributions to our unitholders. To do so, we focus on achieving operational excellence in our businesses and executing accretive low-risk acquisitions and organic growth opportunities, and we allocate a portion of our cash flows to fund growth-related capital expenditures.
 
We are uniquely positioned as a publicly-traded partnership, or master limited partnership (“MLP”), that is engaged in both the midstream and upstream sectors of the oil and natural gas value chain.  Our diversification broadens our spectrum of potential organic growth and acquisition opportunities, gives us a potential advantage in acquiring asset packages that involve both midstream and upstream assets, and enables us to exploit vertical integration synergies in selected regions of our operations.
 
Our Midstream Business is located in four significant natural gas producing regions: (i) the Texas Panhandle; (ii) East Texas/Louisiana; (iii) South Texas; and (iv) the Gulf of Mexico. These four regions are productive, mature, natural gas producing basins that have historically experienced significant drilling activity. On October 1, 2012, we completed our acquisition of two of BP America Production Company's ("BP") gas processing facilities, and the associated gathering systems, that are located in the Texas Panhandle (the "newly-acquired Panhandle System"). The newly-acquired Panhandle System included:

two natural gas processing plants — the Sunray Plant and the Hemphill Plant — with a total capacity of approximately 218 MMcf/d; and
an associated gathering system composed of approximately 2,551 miles of pipeline with approximately 1,935 connected wells.

As of December 31, 2012, our natural gas gathering systems across all our regions comprised approximately 8,134 miles of natural gas gathering pipelines with approximately 4,426 well connections, 19 natural gas processing plants with approximately 787 MMcf/d of plant processing capacity and 286,219 horsepower of compression.  Our Midstream Business averaged 590 MMcf/d of gathered volumes and 490 MMcf/d of processed volumes during the fourth quarter of 2012.
 
Our Upstream Business has long-lived, high working interest properties located in four significant oil and gas producing regions: (i) South Alabama (which includes the associated gathering, processing and treating assets); (ii) Mid-Continent (which includes areas in Oklahoma, Arkansas and the Texas Panhandle); (iii) Permian (which includes areas in West Texas); and (iv) East Texas/South Texas/Mississippi/Louisiana. As of December 31, 2012, these working interest properties included 559 gross operated productive wells and 1,249 gross non-operated wells with net production to us of approximately 82.7 MMcfe/d and proved reserves of approximately 194.4 Bcf of natural gas, 13.0 MMBbls of crude oil, and 12.9 MMBbls of natural gas liquids, of which 76% are proved developed.
 

2


We report on our businesses in five accounting segments, as outlined in Note 14 of our consolidated financial statements.   The Midstream Business's financial results are reported in the following segments: (i) Texas Panhandle, (ii) East Texas and Other Midstream and (iii) Marketing and Trading.  We report our Upstream Business as one segment. Our final reporting segment is our functional (Corporate) Segment, in which we account for our risk management, intersegment eliminations and other corporate activities including general and administrative expenses.

Ownership Structure
   
The diagram below depicts our ownership structure as of February 25, 2013.  The ownership percentages shown below are calculated on a fully-diluted basis:
________________________

(a)
"NGP" refers collectively to Natural Gas Partners VII, L.P., a Delaware limited partnership; Natural Gas Partners VIII, L.P., a Delaware limited partnership; and such other entities as set forth on that certain Schedule 13D/A filed with the Securities and Exchange Commission on March 15, 2012 including, without limitation, Montierra Minerals & Production, L.P., a Texas limited partnership and Montierra Management LLC, a Texas limited liability company. For a discussion of certain members of management's ownership in the Montierra entities, see Part III, Item 12 -Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters, incorporating by reference our to-be-filed proxy statement for our 2013 Annual Meeting of Unitholders. 

3



Our Business Strategy
Our primary business objective is to manage our diversified midstream and upstream properties to generate cash flow and grow distributions over time. To meet this objective, we intend to execute the following business strategies:
Maximizing the profitability of our existing assets. In our Midstream Business, we intend to maximize the profitability of our existing assets by adding new volumes of natural gas to our gathering and processing assets under economically favorable terms. We strive to provide superior customer service, enhance utilization, and improve operating margins and efficiencies. In our Upstream Business, we strive to improve the recoveries of oil and natural gas from our existing wellbores, as well as focus on reducing our per unit operating expenses to maximize the amount of hydrocarbons and valuable by-products we can profitably extract.
Maintaining a disciplined financial policy. We intend to continue to pursue a disciplined financial policy by maintaining a prudent capital structure and managing our exposure to interest rate and commodity price risk. We target a total leverage ratio (outstanding debt to Adjusted EBITDA) of 3.5:1.0 or less on a sustained basis. Since our initial public offering in October 2006, we have financed 58% of our approximately $1.85 billion in acquisitions with the issuance of our common units. We plan to continue with our historical pattern of financing our growth with a balanced combination of equity and debt. Maintaining a balanced capital structure allows us to use our available capital to selectively pursue attractive investments or acquisition opportunities.
Expanding our operations through organic growth projects. In our Midstream Business, we intend to leverage our existing infrastructure and customer relationships by expanding our asset base to meet new or increased demand for midstream services. We also look for opportunities to invest in attractive projects in areas outside our existing asset base. In our Upstream Business, we intend to exploit our substantial inventory of attractive, lower-risk drilling opportunities as the primary source of organic growth. We measure the success of organic growth projects based on internal rate of return targets.
Continuing to reduce our exposure to commodity price risk. We intend to continue to operate our business in a manner that reduces our exposure to commodity price risk in the near term and on an opportunistic basis over the long term. Where commercially practical, we strive to reduce commodity exposure in our Midstream Business by entering into fee-based gathering and processing agreements with our producer customers. In addition, we use a variety of hedging instruments to reduce our exposure to commodity price risk and enhance the stability of our cash flows in both our businesses. Our commodity derivatives are primarily in the form of swaps and collars that are designed to provide a fixed price (swaps) or defined range of prices (collars) that we will receive. We generally hedge a substantial portion of our expected midstream and upstream equity volumes for forward periods of up to four years. We actively monitor our hedge portfolio for opportunities to enter into additional hedges to support our cash flow objectives.
Pursuing acquisitions. We pursue acquisitions which we believe will result in long-term accretion to our distributable cash flow per common unit. We believe that our capital structure, which no longer includes incentive distribution rights, positions us to compete more effectively for future acquisitions. In our Midstream Business, we generally seek to acquire assets that serve producing areas with high levels of drilling activity. In our Upstream Business, we generally seek to acquire operated assets that contain a mix of oil and natural gas reserves, have shallow decline rates, and offer an appropriate balance of current production with meaningful, lower-risk development opportunities. We will pursue acquisition opportunities that we believe will provide the highest risk-adjusted returns available to us and are complementary to our existing asset base across the midstream and upstream sectors.

Competitive Strengths
We believe that we are well positioned to execute our business strategies successfully because of the following competitive strengths:
Geographically and operationally diverse asset base focused on mature, prolific oil and natural gas basins. Our portfolio of assets is diversified both from a geographic and operational perspective. Our midstream assets are strategically located in active, mature regions including the Tonkawa, Cleveland and Granite Wash plays in the Texas Panhandle and the Austin Chalk and Haynesville Shale plays in East Texas and Louisiana. Our Midstream Business provides us with the potential to grow throughput volumes and cash flows based, among other things, on our existing and potential customers' drilling plans and the expected performance of their wells. In addition, we have recently

4


added businesses related to natural gas marketing and trading and crude oil and condensate logistics and marketing in the Texas Panhandle and Alabama. Our upstream assets are diversified among numerous established, lower-cost producing basins in Alabama, Texas, Oklahoma and Arkansas with a balanced mix of crude oil, NGL and natural gas production.
Significant inventory of lower-risk organic growth opportunities. In our Midstream Business, we had identified approximately $68 million of opportunities to build additional infrastructure in our core areas of the Texas Panhandle and East Texas/Louisiana as of December 31, 2012. In our Upstream Business, we have a significant inventory of lower-risk drilling opportunities and other development projects in our core areas of operation. As of December 31, 2012, we had approximately 600 gross drilling locations, 135 of which were associated with proved reserves; we expect this inventory will allow us to maintain and grow production and proved reserves for several years. In our Upstream Business we have a high degree of operational control that allows us to manage our drilling plans to increase or stabilize our cash flow. We currently intend to drill or complete 32 gross (12.5 net) wells during 2013, for which we have budgeted approximately $78 million of drilling and completion capital expenditures.
Strong financial profile. We have strong liquidity and sufficient financial flexibility to fund our anticipated capital needs and future growth opportunities. As of December 31, 2012 we had approximately $192.5 million of unused capacity under our credit facility, based on our outstanding debt and expected total commitments (before taking into account covenant‑based capacity limitations). Our financial profile also is strengthened by our extensive commodity hedge portfolio, which serves to reduce our cash flow volatility in response to changes in oil, natural gas liquids and natural gas prices.
Experienced, knowledgeable management team with a proven record of performance. Our management team has a proven record of enhancing value through investing in, acquiring and integrating midstream and upstream assets. Our senior management team has an average of approximately 20 years of industry‑related experience and a substantial economic interest in us through direct and indirect ownership of our common units.
Affiliation with Natural Gas Partners. Founded in 1988, Natural Gas Partners manages a $10.8 billion family of investment funds organized to make direct equity investments in private energy enterprises. Natural Gas Partners owns a significant equity position in us. Natural Gas Partners historically has provided us with increased exposure to acquisition opportunities. We expect that our relationship with Natural Gas Partners may continue to provide us with several significant benefits, including on-going exposure to acquisition opportunities and access to a significant group of transactional and financial professionals with a successful track record of investing in energy assets. We have agreements with Natural Gas Partners that restrict its control of our board of directors and its voting rights with respect to our common units.

History 

Our Partnership, formed in May 2006, is the legal successor to Eagle Rock Pipeline, L.P. as a result of our initial public offering in October 2006. We have historically grown through acquisitions and organic growth projects.
    
    
The following is a table that depicts our significant acquisitions/dispositions by date, transaction type, cost, financing sources and business over the past five years:


5


Table of Significant Acquisitions/Dispositions in the Past Five Years

Closing
Date
 
Transactions
 
Amount  ($ in Millions)
 
Financing Sources ($ in Millions)
 
Business
 
 
 
Cash
 
Debt
 
Equity to Sellers
 
Cash from equity offerings
 
Acquisitions:
 
 
 
 
 
 
 
 
 
 
 
 
4/30/2008
 
Stanolind Acquisition
 
$
81.9

 
$
5.9

 
$
76.0

 
$

 
$

 
Upstream
10/1/2008
 
Millennium Acquisition
 
$
212.9

 
$
7.2

 
$
176.4

 
$
29.3

 
$

 
Midstream
10/19/2010
 
Centerpoint Acquisition
 
$
27.0

 
$
27.0

 
$

 
$

 
$

 
Midstream
5/3/2011
 
Mid-Continent Acquisition
 
$
563.7

 
$
15.0

 
$
212.6

 
$
336.1

 
$

 
Upstream
10/1/2012
 
Panhandle Acquisition
 
$
230.6

 
$

 
$
146.3

 
$

 
$
84.3

 
Midstream
Dispositions:
 
 
 
 
 
 
 
 
 
 
 
 
5/24/2010
 
Minerals Business Disposition (a)
 
$
174.5

 
$
174.5

 
$

 
$

 
$

 
Minerals
12/20/2012
 
Barnett Shale Properties
 
$
14.8

 
$
14.8

 
$

 
$

 
$

 
Upstream
_______________________________

(a)
Amount includes approximately $2.9 million of cash received from the Minerals Business after the effective date of the sale.

The following is a chart that depicts the costs of our organic growth projects by year and reportable segment over the past five years:
  
 Table of Organic Growth Project Costs in the Past Five Years


The following graph depicts our historical trends in Adjusted EBITDA and quarterly distribution rate per common unit over the past three years:


6


______________________________

Note: "Hedge resets" (in which we paid our hedge counterparties to increase the strike price of existing swaps) contributed $2.2 million to Adjusted EBITDA for the first quarter of 2010.
 
For a definition of Adjusted EBITDA and reconciliation to GAAP, see Part II, Item 6. Selected Financial Data-Non-GAAP Financial Measures.
 
  Due to our enhanced liquidity position resulting from the Recapitalization and Related Transactions described below, our debt reduction efforts and improved economic conditions, we increased our distribution rate for the fourth quarter of 2010 and throughout 2011. In the first quarter of 2012, natural gas and NGL prices experienced a substantial and extended decline. As a result, we held the distribution rate flat throughout 2012.
 
Recapitalization and Related Transactions

In 2010, we completed a series of transactions (the "Recapitalization and Related Transactions") which simplified our capital structure and provided us with added financial liquidity. This series of transactions included:

the contribution, and resulting cancellation, of our incentive distribution rights and 20,691,495 subordinated units held by Eagle Rock Holdings, L.P. ("Holdings") which occurred on May 24, 2010;
the sale of all of our fee mineral and royalty interests, as well as our equity investment in Ivory Working Interests, L.P., (collectively "the Minerals Business") to Black Stone Minerals Company, L.P. for total consideration of $174.5 million which sale was completed on May 24, 2010;
a rights offering, which was launched on June 1, 2010 and expired on June 30, 2010, and for which we received gross proceeds of $53.9 million and issued 21,557,164 common units and 21,557,164 warrants and;
an option, which was exercised on July 30, 2010 by the issuance to Holdings of 1,000,000 newly-issued common units, to capture the value of the controlling interest in us through (a) acquiring our general partner entities from Holdings and immediately thereafter eliminating our 844,551 outstanding general partner units owned by Holdings and (b) reconstituting our Board to allow our common unitholders not affiliated with NGP to elect the majority of our directors.

7


An investment in our common units involves risks associated with our business, regulatory and legal matters, our limited partnership structure and the tax characteristics of our common units. Please read carefully the risks described under Part I, Item 1A. Risk Factors. 

Our Two Lines of Business and Our Five Reporting Segments

Midstream Business
 
Midstream Industry Overview
 
General. Raw natural gas produced from the wellhead is gathered and delivered to a processing plant or markets located near the production field, where it is treated, dehydrated, and/or processed, while condensate is collected and sold upstream of processing. Processing natural gas involves the separation and treating of raw natural gas resulting in a pipeline quality natural gas, primarily methane and mixed NGLs. Natural gas treating entails the removal of impurities, such as water, sulfur compounds, carbon dioxide and nitrogen. Interstate and intrastate pipelines deliver the processed natural gas to markets. Mixed NGLs are typically transported via NGL pipelines or by truck to a fractionator which separates the NGLs into its components such as ethane, propane, normal butane, isobutane and natural gasoline. The component NGLs are then sold to end users. In many cases condensate is stabilized to further reduce its vapor pressure in order to meet truck transport requirements. Blending of light and heavy gravity condensate is also done to improve the quality, market optionality and associated sales price.
 
The following diagram shows the process of gathering, processing, marketing and transporting natural gas, NGLs and condensate.

_________________________

Note: The shaded area above represents processes in which we are directly involved in our Midstream Business and for which we own the underlying assets.

Gathering. A gathering system typically consists of a network of small diameter pipelines and a compression system which together collect natural gas from producing wells and delivers it to larger pipelines for further transportation. We own and operate large gathering systems in four geographic regions of the United States.
 
Compression. Gathering systems are operated at design pressures that seek to maximize the total throughput volumes from all connected wells. Since wells produce at progressively lower field pressures as they age, the raw natural gas must be compressed to deliver the remaining production against higher pressure that exists in the connected gathering system or transport pipelines. Natural gas compression is a mechanical process in which a volume of natural gas at a lower pressure is increased, or compressed, to a desired higher pressure, allowing natural gas that no longer naturally flows into a higher pressure downstream pipeline to be brought to market. Field compression is used to lower the wellhead pressure while maintaining the

8


exit pressure of a gathering system to deliver natural gas into higher pressure downstream pipelines and plants. We own or lease, and operate, all compression on our systems.
 
Treating and Processing. Raw natural gas produced at the wellhead is often unsuitable for pipeline transportation or commercial use and must be processed and/or treated to remove the heavier hydrocarbon components and/or contaminants. The principal components of pipeline-quality natural gas are methane and ethane, but most raw natural gas also contains varying amounts of heavier hydrocarbon components (such as propane, normal butane, isobutane, and natural gasoline) and impurities (such as water, sulfur compounds, carbon dioxide, oxygen and nitrogen). We own and operate natural gas processing and/or treating plants in four geographic regions.
 
Fractionation. NGL fractionation facilities separate mixed NGL streams into discrete NGL products: ethane, propane, normal butane, isobutane and natural gasoline. Ethane is primarily used in the petrochemical industry as feedstock for ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. Propane is used both as a petrochemical feedstock and as a heating fuel, an engine fuel and an industrial fuel. Normal butane is used as a petrochemical, and as a blend stock for motor gasoline. Isobutane is typically fractionated from mixed butane (a stream of normal butane and isobutane in solution), principally for use in enhancing the octane content of motor gasoline. Natural gasoline, a mixture of pentanes and heavier hydrocarbons, is used primarily as motor gasoline blend stock or petrochemical feedstock. We operate a fractionation facility to produce propane at one of our facilities in the Texas Panhandle Segment.  In our East Texas and Other Midstream Segment we own a 4.50% interest, which was updated to 3.07% interest in January 2013, in the Tebone Fractionator, a fractionation facility operated by Enterprise Products Partners L.P. in southern Louisiana.
 
Condensate Stabilization. Natural gas condensate is a low-density mixture of hydrocarbon liquids found in the raw natural gas stream. Condensate stabilization is a process by which the vapor pressure of the condensate is reduced. As a result, the condensate is better positioned to meet truck transportation limitations and end-user specifications. We own and operate condensate stabilization facilities in our Texas Panhandle Segment.

Marketing and Trading. Natural gas marketing and trading involves the sale of natural gas either produced by processing plants or purchased from gathering systems or other pipelines. NGL marketing involves the sale of the unfractionated (or "y-grade") products or fractionated products recovered at the processing plants. We market and trade natural gas, and market NGLs and condensate for our own account and for the benefit of most of our producer customers in our Midstream Business and for certain working interest owners in our Upstream Business. In the fourth quarter of 2010, we created a marketing subsidiary to develop, implement, and launch marketing uplift strategies surrounding crude oil and condensate in Alabama and in the Texas Panhandle. Strategies include marketing and transportation, including the use of rail, barge, and storage facilities, and product blending to enhance product net-back prices. Currently, our crude marketing subsidiary does not own marketing-related natural gas or natural gas liquid pipelines, storage or other transportation assets, nor does it utilize financial derivatives in the marketing of our products. In 2011, we created a natural gas marketing and trading subsidiary to capitalize on the physical and financial opportunities that naturally extend from our upstream and midstream assets. Where in the past we generally sold to wholesale buyers at the tailgates and wellheads of our assets, now this subsidiary holds transportation agreements and moves our product to many locations and types of buyers. This strategy diversifies our credit and performance risk and allows us to capitalize on daily, monthly and seasonal changes in market conditions. With these transportation and marketing options in place, our gas marketing and trading subsidiary has been successful in buying and marketing third party gas in various operating areas.

Transportation. Natural gas transportation consists of moving pipeline-quality natural gas from gathering systems, processing plants and other pipelines and delivering it to wholesalers, utilities and other pipelines. Other than our North and Central systems in Texas, we do not own any natural gas transportation assets. Condensate is typically transported locally by truck and aggregated into storage tanks before being delivered to end markets via a range of transportation alternatives, including truck, rail, barge or pipeline.
    
Natural gas is gathered and processed pursuant to a variety of industry-standard arrangements generally categorized as fee-based, percent-of-proceeds, fixed recovery, percent-of-index and keep-whole, described in greater detail as follows:
 
Fee-Based Arrangements. Under these arrangements, we are paid a fixed cash fee per unit volume for performing the gathering and processing service. This fee is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. A sustained decline, however, in commodity prices could result in a decline in volumes and, thus, a decrease in fee revenues. These arrangements provide stable cash flows, but minimal, if any, upside in higher commodity price environments.
 

9


Percent-of-Proceeds Arrangements. Under these arrangements, raw natural gas is gathered from producers at the wellhead, moved through the gathering system, processed and sold at prices based on published index prices. Producers are paid an agreed-upon percentage of the proceeds. The value paid to producers is based on an agreed percentage of the products produced multiplied by the actual sale price or an index price. Contracts in which the gatherer/processor shares only in specified percentages of the proceeds from the sale of NGLs and in which the producer receives 100% of the proceeds from natural gas sales, are referred to as “percent-of-liquids” arrangements but are still generally categorized as percent-of-proceeds arrangements. Under percent-of-proceeds arrangements, the margin correlates directly with the prices of natural gas and NGLs, as applicable; under percent-of-liquids arrangements, the margin correlates directly with the price of NGLs. Percentage-of-Proceeds arrangements provide upside in high commodity price environments, but result in lower margins in low commodity price environments.
 
Fixed Recovery Arrangements. Under these arrangements, raw natural gas is gathered from producers at the wellhead, transported through our gathering system and processed. We sell the processed natural gas and NGLs at prices based on published index prices. The value paid to the producers for NGLs is calculated as the product of agreed-upon theoretical product recovery factors multiplied by the theoretical wellhead gallons for each NGL component. Each resulting component volume is then multiplied by a contractual percentage and an index price or the actual sales price. The value paid for the remaining share of natural gas is multiplied by a contractual percentage and an index price or the actual sales price. These arrangements provide upside in high commodity price environments, but result in lower margins in low commodity price environments. These arrangements also provide greater upside to us for greater efficiency and better actual recoveries and tend to penalize us when efficiency and recoveries turn-out not to be as expected.

Percent-of-Index Arrangements.  Under percent-of-index arrangements, we purchase either liquids-rich or dry wellhead natural gas at either (i) a percentage discount to a specified index price, (ii) a specified index price less a fixed amount or (iii) a weighted average sales price based on natural gas sales.  We generally then gather and deliver the dry natural gas to third-party pipelines and gather and process the liquids-rich natural gas and sell the resulting NGLs and residue gas to third parties.  Generally, when we gather dry natural gas and deliver it directly into a third-party pipeline, we are able to resell the natural gas at the index price or at a different percentage discount to the index price which reduces commodity price exposure.  Generally, when we gather and process liquids-rich natural gas, our revenues and net operating margins increase as the price of NGLs and condensate increases relative to the price of natural gas and decrease as the price of NGLs and condensate decrease relative to the price of natural gas, resulting in commodity exposure to us that is similar to that of a keep-whole arrangement. 
 
Keep-Whole Arrangements. Under these arrangements, raw natural gas is processed to extract NGLs, and the processor pays the producer the full thermal equivalent volume of raw natural gas received from the producer in the form of either processed natural gas or its cash equivalent. Processors are generally entitled to retain the processed NGLs and to sell them for their account. Margin is a function of the difference between the value of the NGLs produced and the cost of the natural gas needed to replace the thermal equivalent volume of natural gas used in processing (i.e. the frac spread). The profitability of these arrangements is subject not only to the commodity price risk of natural gas and NGLs, but also to the price of natural gas relative to NGL prices. These arrangements can provide improved profit margins in favorable commodity price environments, but also can be subject to losses if the cost of natural gas exceeds the value of its thermal equivalent of NGLs. Many keep-whole arrangements include provisions that reduce commodity price exposure, including (i) conditioning floors that require the keep-whole arrangements to convert to a fee-based arrangement if the NGLs have a lower value than their thermal equivalent in natural gas, (ii) discounts to the applicable natural gas index price used to reimburse the producer an amount in cash for the thermal equivalent volume of raw natural gas acquired from the producer, or (iii) fixed cash fees for ancillary services, such as gathering, treating and compressing.
 
Midstream Business Overview
 
We own natural gas gathering and processing assets in four significant natural gas producing regions: the Texas Panhandle, East Texas/Louisiana, South Texas and the Gulf of Mexico. During 2012, we remained focused on contracting new gas to our systems and initiating organic growth projects to meet the increasing demand for processing services by our producer customers.  The majority of our growth projects are designed to enhance and expand our processing capacity in the Granite Wash and surrounding plays in the Texas Panhandle. In 2012, we completed the installation of our 60 MMcf/d Woodall plant and began construction on our 60 MMcf/d Wheeler plant, which is expected to be in service in the first half of 2013. In October 2012, we acquired from BP the Sunray and Hemphill processing plants (with a total combined capacity of approximately 218 MMcf/d) and the associated 2,551 mile gathering system ("Panhandle Acquisition"). Concurrent with the acquisition, we entered into a 20-year, fixed-fee Gas Gathering and Processing Agreement with BP under which we will gather and process BP's natural

10


gas production from the existing wells connected to the newly-acquired Panhandle System. Furthermore, BP has committed itself to us under the same agreement and committed its farmees to us under substantially the same terms, with respect to all future natural gas production from new wells drilled within an initial two-year period from closing, subject to mutually-agreed extensions, and within a two-mile radius of any portion of our gathering system serving such BP connected wells. As of December 30, 2012, we have increased our high-efficiency processing capacity servicing Texas Panhandle production to 488 from approximately 157 MMcf/d at the beginning of 2010. We expect this processing capacity to increase to approximately 548 MMcf/d in 2013.
 
Within our geographic areas of operation, we strive to be a competitive and low cost natural gas gatherer and processor. To achieve this end, we coordinate the operations and commercial activities of our gathering and processing assets to provide better customer service.  From an operations perspective, our key strategy is to provide our customers safe and reliable service at reasonable costs and to improve our competitiveness in securing new customers through more efficient operations.  From a commercial perspective, our focus is to assist our customers in maximizing the value of their production by providing options and capacity for the movement and marketing of their natural gas and NGLs.  We are well positioned to take advantage of continued growth opportunities in the Texas Panhandle Granite Wash play and in the Austin Chalk play in East Texas.  In an effort to comply with the competitive environment of our operating areas, we often provide a combination of “Fixed Recovery Agreements” with a “Fee-Based Agreement” component.  These are typically structured to comply with producer preference and also to help alleviate the level of commodity exposure that we have on any single agreement. As of December 31, 2012, the percentage of natural gas wellhead volumes under various contractual arrangements were 26% fixed recovery, 27% fee-based, 39% percent-of-proceeds (which includes percent-of-liquids) and 8% percent-of-index (blended/combination contracts are categorized based upon which arrangement within the contract generates the majority of the margin).
  


11


As of December 31, 2012, our Midstream Business consisted of the following:  
 
Asset
 
Length
(miles)
 
Available Compression
(Horsepower)
 
Processing Plant Through-put Volume Capacity (MMcf/d)
Texas Panhandle Segment
 
6,514

 
211,500

 
488

Canadian cryogenic plant and gathering system
 
359

 
 

 
25

Phoenix Arrington Ranch cryogenic plant and gathering system
 
757

 
 

 
80

Woodall plant (b)
 
n/a

 
 
 
60

Hemphill plant and gathering system
 
1,766

 
 
 
50

Sunray plant and gathering system
 
785

 
 
 
168

Red Deer cryogenic plant (a)(c)
 
n/a

 
 

 
24

Roberts County refrigeration plant and gathering system (a)(d)
 
14

 
 

 
20

System 97 gathering system (e)
 
77

 
 

 
n/a

Buffalo Wallow gathering system (e)
 
113

 
 

 
n/a

Cargray cryogenic plant and gathering system
 
905

 
 

 
30

Gray cryogenic plant and gathering system (a)
 
615

 
 

 
20

Lefors cryogenic plant and gathering system
 
663

 
 

 
11

Stinnett gathering system
 
451

 
 

 
n/a

Turkey Creek gathering system
 
9

 
 

 
n/a

East Texas and Other Midstream Segment
 
1,620

 
74,719

 
299

Brookeland cryogenic plant and gathering system
 
633

 
 

 
100

Indian Springs cryogenic plant (25% non-operated) and Camp Ruby gathering system (20% non-operated) (f)
 
n/a

 
 

 
36

Tyler County gathering system
 
73

 
 

 
n/a

Panola gathering system
 
33

 
 

 
n/a

Quitman gathering system
 
51

 
 

 
n/a

Rosewood mechanical refrigeration plant and gathering system (a)
 
42

 
 

 
10

Vixen gathering system (e)
 
7

 
 

 
n/a

Belle Bower JT plant and gathering system (a)
 
68

 
 

 
20

Simsboro gathering system (e)
 
30

 
 

 
n/a

Sligo gathering system (e)
 
10

 
 

 
n/a

ETML gathering system and JT Plant (e)
 
221

 
 

 
15

Douglas East gathering system (e)
 
14

 
 

 
n/a

BGS gathering system (e)
 
24

 
 

 
n/a

Robertson County gathering system (e)
 
36

 
 

 
n/a

North gathering system (h)
 
85

 
 

 
n/a

Central mechanical refrigeration plant and gathering system (i)
 
102

 
 

 
2

New Ulm gathering system
 
15

 
 

 
n/a

Phase 1 gathering system
 
70

 
 

 
n/a

Raymondville gathering system
 
31

 
 

 
n/a

Raymondville JT plant (a)
 
n/a

 
 

 
40

San Ignacio gathering system
 
6

 
 

 
n/a

TGP McAllen JT plant and gathering system
 
13

 
 

 
40

Sweeny gathering system (50% non-operated)
 
16

 
 

 
n/a

North Terrebonne refrigerated lean oil plant (4.50% non-operated) (g)
 
n/a

 
 

 
36

Tebone Fractionator (2.63% non-operated) (h)
 
n/a

 
 

 
n/a

Galveston Bay gathering (50% non-operated)
 
12

 
 

 
n/a

CMA Pipeline segments (non-operated)
 
28

 
 

 
n/a

TOTAL Midstream Businesses
 
8,134

 
286,219

 
787

_______________________________
(a)
The plant is owned by us, but we lease the plant site.
(b)
The plant processes gas from the Phoenix Arrington Ranch gathering system.
(c)
The plant processes gas from the Canadian gathering system.
(d)
The Roberts County Plant has 21 MMcf/d of capacity but currently only has installed compression to process 20 MMcf/d.
(e)
The systems gather dry natural gas that does not require processing to meet pipeline hydrocarbon dew point quality specifications.
(f)
Our net plant capacity is based on the plant expansion to 145 MMcf/d total capacity in February 2008.
(g)
The available capacity shown is net to our ownership share. Available capacity is based on the previous year's allocated throughput volume for each owner and to existing owners and potential new owners who are adding new production volumes. Our ownership in North Terrebonne changed in January 2013 to 3.07% from 4.50%.
(h)
The Tebone Fractionator has 30,000 Bbl/d of capacity. Our ownership share is tied to our ownership percentage in the North Terrebonne Plant which changed to 3.07% from 4.50% in January 2013.
(i)
Sections of the system are subject to FERC jurisdiction under Section 311 of the NGPA.



12


The following graph depicts plant processing capacity and utilization by month.  The volumes shown include only the gas volumes that we gathered that were processed before entering the interstate or intrastate pipeline systems (we refer to such natural gas as wet gas) and excludes the gas volumes that we gathered that were not processed prior to delivery to the interstate or intrastate pipeline systems (we refer to such natural gas as dry gas).

_______________________________
Note.  Reflects the installation of the Phoenix-Arrington Ranch plant in 2010 and its expansion in October of 2011, the installation of the Woodall plant in June 2012 and the acquisition of the Sunray and Hemphill plants in October 2012.  Other changes are attributable to adjustments of plant ownership percentages at North Terrebonne and Yscloskey, the shut-down of the Yscloskey plant in September 2012 and the abandonment of two small JT plants.

Texas Panhandle Segment
 
Our Texas Panhandle Segment covers 14 counties in Texas and two counties in Oklahoma. On October 1, 2012, we completed the acquisition of the Sunray and Hemphill processing plants and associated 2,500 mile gathering system. Through the systems within this segment we offer midstream wellhead-to-market services, including gathering, compressing, treating, processing and selling of natural gas, and fractionating and selling of NGLs. As of December 31, 2012, approximately 338 producers and 3,822 wells and central delivery points were connected to the systems in our Texas Panhandle Segment. The Texas Panhandle Segment averaged gathered volumes for the fourth quarter of 2012 of approximately 372 MMcf/d. As of December 31, 2012, BP and Mewbourne Oil Company represented 26.5% and 6.5%, respectively, of the total volumes of our Texas Panhandle Segment. The following is a map of our Texas Panhandle Segment:

13


 

14


As of December 31, 2012, the Texas Panhandle Segment consisted of approximately 6,514 miles of natural gas gathering pipelines, ranging from two inches to 24 inches in diameter; ten active natural gas processing plants with an aggregate capacity of 488 MMcf/d; a propane fractionation facility with capacity of 1.0 MBbls/d; and four condensate collection and stabilization facilities.

Natural Gas Supply. Our systems in the East Panhandle (defined as northern Wheeler, Hemphill, Lipscomb, Ochiltree, Hansford and Roberts Counties, Texas) gather and process natural gas produced from multiple geological reservoirs, including the Cottage Grove, Tonkawa, Cleveland, Hogshooter, Granite Wash and Morrow formations of the Anadarko basin. Approximately 96% of the natural gas gathered from these areas is processed to recover the NGL content, which generally ranges from 4.0 to 5.0 gpm, with the remaining volume not processed but treated for removal of carbon dioxide and hydrogen sulfide to make the natural gas marketable. This natural gas can be isolated and sent to treating facilities while the remaining system is used to gather the natural gas into the processing plants. This area has experienced substantial drilling and reserve growth since 2002.  Producers are increasing their use of horizontal drilling in the Tonkawa, Cleveland, Hogshooter and Granite Wash plays.  The enhanced economics associated with horizontally drilled wells and the relatively high levels of liquids found in the reservoir has led to an overall increase in the number of wells permitted for the greater these plays. In response to increased demand for processing capacity by our producer customers operating in the Granite Wash and surrounding plays, we completed construction on one new cryogenic processing plant, our 60 MMcf/d Woodall plant, which was placed into service in 2012, and initiated construction on another, our 60 MMcf/d Wheeler Plant, which we expect to place into service during the first half of 2013. In addition, during 2012 we substantially expanded our presence in the area due to the Panhandle Acquisition.

Our systems in the West Panhandle (defined as Moore, Potter, Gray, Hutchinson, Carson, Sherman, Hartley, Collingsworth and southern Wheeler Counties, Texas) gather and process natural gas produced from the Brown Dolomite formations in the Anadarko basin. These areas are fully developed, and as a result there is limited new drilling activity in the area served by our West Panhandle systems. Natural gas production from wells located within the West Panhandle area generally are low volume wells being gathered at very low pressure. Natural gas from wells located in this area generally have an annual rate of decline of 6% to 9%.  This natural gas is processed to recover the NGL content which generally ranges from 8.0 to 18.0 gpm.

In the Panhandle Segment, natural gas is contracted at the wellhead primarily under (i) percent-of proceeds (which includes percent-of-liquids), (ii) fixed recovery, (iii) percent-of-index and (iv) fee-based arrangements that range from one to five years in term. As of December 31, 2012, approximately 37%, 31%, 7% and 25% of our total throughput was under percent-of-proceeds, fixed recovery, percent-of-index, and fee-based arrangements, respectively.

In addition, we produced approximately 3,340 equity barrels per day of condensate in the Texas Panhandle Segment during the fourth quarter of 2012. We stabilized approximately 2,530 barrels per day at our Superdrip, Cargray, Woodall and Sunray stabilizers during the fourth quarter of 2012.   
 
Competition. With the production growth in the Granite Wash, Cleveland, Tonkawa and Hogshooter plays, a number of midstream companies have built plants in the area. Our primary competitors in this area are DCP Midstream, LLC and Enbridge Energy Partners, L.P. The key drivers in this high growth area, in order to continue to connect producer wells, are the ability to provide low pressure gathering services, to provide outlet capacity for the natural gas as it is brought into producing status and to provide high value efficient plant processing. We have extensive gathering systems that are situated in the Granite Wash and surrounding plays, and in response to the increased need for processing capacity in this play, we placed into service our Woodall plant and completed the Panhandle Acquisition during 2012. In addition, we expect to place our Wheeler Plant into service during the first half of 2013. During 2012, we expanded the Phoenix gathering system by over 33.3 miles of 8 inch to 12 inch pipeline at a cost of $20.9 million.

Texas Panhandle Markets. Our residue gas is marketed primarily by our natural gas marketing subsidiary. Our NGLs are marketed primarily to ONEOK Hydrocarbons ("ONEOK") and ConocoPhillips Company.  During 2011, NGL takeaway capacity from the Texas Panhandle became constrained, driven by the increase in liquids-focused drilling activity in areas such as the Granite Wash and surrounding plays. Several new pipeline projects are currently under development to increase NGL takeaway capacity from the Texas Panhandle, but these projects are not expected to be in service until mid- to late-2013. Until that time, we believe NGL takeaway capacity will continue to be constrained. Under our existing contractual relationship with ONEOK, we believe we have secured sufficient takeaway capacity for our existing operations and for the increased takeaway requirements associated with the installation of our Woodall Plant in 2012 and our Wheeler Plant in 2013. Our condensate is sold under contract terms of one year or less. In addition, condensate produced and stabilized is sold to regional markets on a multi-month basis through various supply, trading and logistics companies.


15


East Texas and Other Midstream Segment
 
Our East Texas and Other Midstream Segment operates within the following natural gas producing regions: East Texas/Louisiana, South Texas and the Gulf of Mexico.

Through our East Texas/Louisiana region, we offer producers natural gas gathering, treating, processing and transportation and NGL transportation across 21 counties in East Texas and seven parishes in West Louisiana. Our systems in the East Texas/Louisiana region which serve liquids-rich basins have experienced consistent drilling activity in recent years, whereas our systems in this region serving dry-gas basins have experienced reduced drilling activity.

Our operations in the South Texas region primarily gather natural gas and recover NGLs and condensate from natural gas produced in the Frio, Vicksburg, Miocene, Canyon Sands and Wilcox formations in South Texas.

Our operations in the Gulf of Mexico region are non-operated ownership interests in pipelines and onshore plants which are all located in southern Louisiana. In August 2012, the Yscloskey processing plant in Louisiana suffered significant damage due to Hurricane Isaac and has been shut-down indefinitely. The Gulf of Mexico region also provides producer services by arranging for the processing of producers’ natural gas into third-party processing plants, which we describe as our Mezzanine Processing Services.  The following is a map of our East Texas and Other Midstream Segment:


16




17


Natural Gas Supply. As of December 31, 2012, approximately 604 wells and central delivery points were connected to our systems in the East Texas and Other Midstream Segment. As of December 31, 2012, the East Texas and Other Midstream Segment provides gathering and/or marketing services to approximately 125 producers. The East Texas and Other Midstream Segment averaged gathered volumes of approximately 217 MMcf/d during the fourth quarter of 2012.

The supply of natural gas into our East Texas and Other Midstream Segment is highly dependent upon drilling activity over which we have no ownership or control. We have experienced throughput declines in this segment since 2008, primarily due to decreased drilling activity by our producer customers driven by low natural gas prices. As of December 31, 2012, Anadarko E&P Company LP ("Anadarko") and BBX Operating, LLC represented 15% and 13%, respectively, of the total volumes of our East Texas and Other Midstream Segment. The natural gas supplied to us in this region is generally dedicated to us under individually negotiated long-term and life-of-lease contracts. Contracts associated with this production are primarily percent-of-proceeds (which includes percent-of-liquids) and fee-based arrangements, with some percent-of-index and fixed recovery. As of December 31, 2012, the percentage of natural gas under the contract structures were 42% percent-of-proceeds, 33% fee-based, 10% percent-of-index, and 15% fixed recovery.

In October 2012, we announced that we entered into an Amendment (the "Amendment") to our existing Gas Gathering and Processing Agreement (the "Agreement") with Anadarko to support Anadarko's drilling program in western Louisiana. The Amendment, among other things, (i) obligates Anadarko to deliver to us for gathering and processing the total volume of natural gas produced from wells drilled in an additional approximately 800,000 acre 10-year dedication in Allen, Beauregard, Evangeline, Rapides and Vernon Parishes, Louisiana, (ii) changes the fee structure for all new wells spud on or after April 1, 2012 by Anadarko on the dedicated lands (inclusive of both the lands dedicated under the Base Agreement and the Amendment) to provide for a fixed gathering fee arrangement (rather than a commodity-price sensitive processing fee), and (iii) revises the mechanism that provides for our recovery of capital expenditures for connecting our pipelines to Anadarko-operated wells spud on or after April 1, 2012.

Markets. In the East Texas/Louisiana region approximately 43% of the residue gas remaining after processing is sold by our natural gas marketing subsidiary and the balance is taken in kind by the producer customers into the markets available at the tailgates of the plants or pipeline interconnects.  Residue gas pipelines include Houston Pipeline Company, Natural Gas Pipeline Company, Tennessee Gas Pipeline, Crosstex Energy L.P. and Southern Natural Pipeline. Our NGLs are sold to various companies including Williams NGL Marketing, LLC.

In the South Texas region natural gas is processed primarily for hydrocarbon dewpoint control to satisfy the gas quality requirements of the receiving interstate pipelines such as Tennessee Gas Pipeline Company and Enterprise Texas Pipeline. Our systems in the Gulf of Mexico region primarily process natural gas from interstate pipelines including Transco and Tennessee Gas Pipeline and recover NGLs and condensate from natural gas produced in the Outer Continental Shelf of the Gulf of Mexico.  The majority of NGLs produced from the Gulf of Mexico region are transported by pipelines for fractionation at the Norco, Toca and Tebone fractionators.  Once fractionated, the NGLs are sold to Enterprise Products Partners L.P. under a year-to-year contract.

Many of the interstate pipelines in our area are constrained from time to time. Offering multiple market outlets is important to our customers to ensure that they can produce their natural gas.

Competition. Our primary competition in the East Texas/Louisiana and South Texas regions includes Crosstex Energy, L.P., DCP Midstream, LLC, Energy Transfer Partners, LP and Enterprise Products Partners, L.P. Producers in the East Texas / Louisiana area value high run-time rates of the processing assets, connections to premium markets and low pressure gathering services. During 2012, we continued to expand the Brookeland Gathering System and Tyler County gathering system by over 10.4 miles of 6 inch to 8 inch pipeline at a cost of $6.1 million.

The key drivers in the South Texas region are low pressure gathering and multiple market outlets for natural gas. Much of the natural gas drilled within the vicinity of our gathering systems is of sufficient wellhead pressure to deliver directly to the high pressure interstate pipelines; however, the wells quickly decline in pressure. We operate our systems at lower pressures which offers the producers an alternative to installing their own compression.
 
Our competition in the Gulf of Mexico region at the North Terrebonne Plant is primarily from other owners in those plants as well as the plant operators who are attempting to contract with the producers on behalf of all the plant owners.  In our Mezzanine Processing Services, the primary competition comes from the plant operators at the various third party plants in which we have contracts.


18


Marketing and Trading Segment

We formed our marketing subsidiary during the fourth quarter of 2010 to develop and implement marketing uplift strategies surrounding crude oil and condensate production in Alabama and in the Texas Panhandle. In Alabama, we purchase product from our Upstream Segment and certain other working interest owners in the Big Escambia Creek, Fanny Church and Flomaton fields, and seek to increase the value of the product through: (i) blending and treating to lower the gravity and reduce the contaminants, respectively, of the purchased condensate; and (ii) transporting the higher quality condensate to premium market locations. In this regard, neither our Upstream Segment nor the other participating working interest owners bear increased risk in the relocating and treating of the condensate.

We also conduct natural gas marketing and trading activities, which began during the third quarter of 2011. We seek to capitalize on the physical and financial arbitrage opportunities that naturally extend from our upstream and midstream assets. Where in the past we generally sold to wholesale buyers at the tailgates and wellheads of our assets, now, through our natural gas marketing and trading subsidiary, we hold transportation agreements and move our product to many locations and types of buyers. This strategy diversifies our credit and performance risk and allows us to capitalize on daily, monthly, and seasonal changes in market conditions.

Markets. Our Alabama and Texas Panhandle crude and condensate is sold to various customers, typically on a multi-month basis.
 
For natural gas, we sell to wholesale and retail markets at various market hubs and specific facility locations, depending on market conditions. These sales are typically priced based upon a published daily or monthly price index. We lease third-party pipeline capacity downstream of our natural gas assets under firm transportation contracts, which capacity is dependent on the volumes of natural gas from our natural gas assets. This capacity is leased for various lengths of times and at rates that allow us to diversify our customer base by expanding our service territory.

Competition. Our Marketing and Trading Segment has numerous competitors, including large natural gas marketing companies, marketing affiliates of pipelines, major oil and natural gas producers, independent aggregators and regional marketing companies.

Upstream Business
 
Upstream Business Overview
 
Our Upstream Business has long-lived, high working interest properties with extensive production histories and development opportunities located in four regions within the United States:

South Alabama, which includes the associated gathering, processing and treating assets;
Mid-Continent, which includes areas in Oklahoma, Arkansas and the Texas Panhandle acquired in conjunction with our CC Energy II L.L.C. acquisition ("Mid-Continent Acquisition") in May 2011;
Permian, which includes areas in West Texas; and
East Texas/South Texas/Mississippi/Louisiana.

As of December 31, 2012, these working interest properties included 559 gross operated productive wells and 1,249 gross non-operated wells with net production of approximately 82.7 MMcfe/d and proved reserves of approximately 194.4 Bcf of natural gas, 13.0 MMBbls of crude oil, and 12.9 MMBbls of natural gas liquids, of which 76% were proved developed. The reserve life index is approximately 12 years based on our average daily production for the fourth quarter of 2012.


19


The following table summarizes our producing properties by region as of December 31, 2012:
 
Region
 
Average net daily
sales in 2012
 
Gross productive
wells in
December 2012
 
Oil,
Bbl/d
 
Natural
gas,
Mcf/d
 
Natural
gas
liquids,
Bbl/d
 
Operated
 
Non-
Operated
South Alabama Region
 
1,406

 
3,651

 
644

 
26

 
3

Mid-Continent Region
 
1,086

 
35,537

 
1,714

 
286

 
1,078

Permian Region
 
472

 
1,450

 
190

 
207

 
55

East Texas/South Texas/Mississippi/Louisiana Region
 
271

 
4,288

 
513

 
40

 
113

Total
 
3,235

 
44,926

 
3,061

 
559

 
1,249

 
South Alabama Region. The South Alabama region includes the Big Escambia Creek, Flomaton and Fanny Church fields located in Escambia County, Alabama. These fields produce from either the Smackover or Norphlet formations at depths ranging from approximately 15,000 to 16,000 feet.  The Big Escambia Creek field was discovered in 1971 and encompasses approximately 11,568 gross and 7,334 net Eagle Rock operated acres.  We operate eighteen productive wells with an average ownership of 63% working interest and 54% net revenue interest in the Big Escambia Creek field.  The Fanny Church field is located two miles east of Big Escambia Creek. Our ownership includes approximately 1,284 gross and 949 net operated acres that include two productive operated wells with an ownership of 85% working interest and 66% net revenue interest.  The Flomaton field is adjacent to and partially underlies the Big Escambia Creek field.   The field encompasses approximately 1,280 gross and 1,256 net Eagle Rock operated acres and produces from the Norphlet formation at depths from approximately 15,000 to 16,000 feet.  We operate three productive wells with an approximate average 91% working interest and 78% net revenue interest.  The Smackover and Norphlet reservoirs are sour, gas condensate reservoirs which produce gas and fluids containing a high percentage of hydrogen sulfide and carbon dioxide. These impurities are extracted at the Eagle Rock-operated Big Escambia Creek Treating Facility or Flomaton Treating Facility, and the effluent gas is further processed for the removal of natural gas liquids in our Big Escambia Creek Gas Processing Facility. The operation of the wells and the facilities is closely connected, and we are the largest owner and operator of the combined assets. In addition to selling condensate, natural gas, and NGLs, we also market elemental sulfur.

 Mid-Continent Region. The Mid-Continent region consists of operated and non-operated properties in the Golden Trend Field, Cana Shale play, Verden Field, and other fields located in the Anadarko Basin of western Oklahoma; the Mansfield Field and other fields in the Arkoma Basin of Arkansas and Oklahoma; and various fields in the Texas Panhandle. Within the Mid-Continent region, the fields can generally be characterized as mature fields that produce from multiple reservoirs. Productive depths range from approximately 2,500 feet in the Arkoma fields of western Arkansas to greater than 18,000 feet in the Springer formation in certain western Oklahoma fields.

Our largest producing field in the region is the Golden Trend field which extends across Grady, McClain and Garvin Counties in Oklahoma. The field is a large structural trap, discovered in 1947, that produces from the shallow Pennsylvanian Deese formation to the deep Ordovician Arbuckle formation. Most of our current production is from the Bromide formation and the "Big Four" interval consisting of the Viola, Hunton, Woodford and Sycamore formations. We typically drill through all these formations and perform multi-stage fracture stimulation completions in the Bromides and "Big Four" intervals.

We have a significant ownership position in the new and expanding Cana (Woodford) Shale and Southeast Cana Shale plays in western Oklahoma. We have approximately 15,200 net acres in these plays extending across Canadian, Blaine, Dewey, Grady, Garvin and Stephens Counties in Oklahoma. The Cana and Southeast Cana Shale produce from horizontal wells drilled to vertical depths of 11,000 - 13,000 feet and extended with horizontal lateral lengths of approximately 5,000 feet. The horizontal laterals are fracture stimulated in multiple stages to optimize productivity from the shale reservoir.

In the Mid-Continent region, we operate 286 productive wells and own a working interest in an additional 1,078 non-operated productive wells. The average working interest in these productive operated and non-operated wells is 83% and 9%, respectively. The net production averaged approximately 50.2 MMcfe/d in the fourth quarter of 2012, of which approximately 73% was produced from wells we operated. Most of the non-operated production comes from the properties within the Cana Shale play, Verden Field, and various other fields located in the Arkoma and Anadarko Basin. The majority of the interests in the Cana Shale are operated by large upstream companies with significant experience and expertise in developing shale gas reserves.

20


 
Permian Region. The Permian region contains numerous fields including Ward South, and Ward-Estes North located mainly in Ward, Pecos, and Crane Counties, Texas.  These fields are located on the Central Basin Platform which extends from central Lea County in New Mexico to central Pecos County in Texas and encompasses hundreds of fields with multiple productive intervals from the Yates-Seven Rivers-Queen group through the Ellenburger formations. In Ward County, we have approximately 10,285 gross and 10,215 net acres of leasehold and we operate fields with multiple productive horizons which produce from depths of 2,300 feet (Yates) to 9,100 feet (Pennsylvanian).   Two of our major properties in the region, the Louis Richter lease and the American National Life lease, are located in Ward County. In Crane County, the Southern Unit is located in the Running “W” Waddell field which was discovered in the mid-1930s and produces predominantly oil at depths from approximately 5,750 to 5,900 feet.  We operate approximately 5,875 net acres in this area.   Our ownership in the Permian region wells averages 95% net working interest and 75% net revenue interest. 

East Texas/South Texas/Mississippi/Louisiana Region. The East Texas and Louisiana fields produce primarily from the Smackover Trend at depths from 12,000 to 12,700 feet and encompass approximately 18,991 gross and 15,872 net Eagle Rock acres. We operate 32 productive wells which produce gas that contains between approximately 25% to 65% of impurities (hydrogen sulfide, nitrogen, and carbon dioxide). The Edgewood field also contains two productive gas wells in the Cotton Valley at depths of 11,500 to 11,600 feet which produce "sweet" natural gas. The East Texas production, with the exception of a single well, is gathered by Tristream Energy, LLC and processed at its Eustace Plant for separation of condensate, removal of impurities, and extraction of natural gas liquids and sulfur for a combination of fees and percentage of proceeds.    

In South Texas, we operate six productive wells with 100% working interest and 88% net revenue interest in the Jourdanton field in Atascosa County, Texas, which was discovered in 1945 by Humble Oil Company.  Our net leasehold ownership in the field is 926 acres.  Our production from the field is primarily from the Edwards carbonates (7,300 to 7,400 feet); however, production has been established in multiple reservoirs above the Edwards interval, predominately the Georgetown, Austin Chalk, and Buda formations.  In addition, the Eagle Ford shale is productive in the southern portion of Atascosa County, but it has not been widely tested in the immediate vicinity of our wells.

The Mississippi properties produce from the Smackover formation at depths of 16,500 feet to 17,200 feet, and our interests encompass approximately 800 gross and 790 net acres. We operate one productive oil well and one productive gas well.

Productive Wells
 
On December 31, 2012, we had under operation 288 gross (259 net) productive oil wells and 271 gross (225 net) productive natural gas wells. On December 31, 2012, we owned non-operated working interests in an additional 179 gross (27 net) productive oil wells and 1,070 gross (76 net) productive natural gas wells.

Developed and Undeveloped Acreage
 
The following table describes the leasehold acreage we owned as of December 31, 2012:
 
Developed
Acreage(a)
 
Undeveloped
Acreage(b)
 
Total
Acreage
 
Gross(c)
 
Net(d)
 
Gross(c)
 
Net(d)
 
Gross
 
Net
Total
450,531

 
196,976

 
17,685

 
10,495

 
468,216

 
207,471

____________________________
(a)
Developed acres are acres pooled or assigned to productive wells.
(b)
Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas or oil, regardless of whether such acreage contains proved reserves.
(c)
A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.
(d)
A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres.
Drilling and Recompletion Activity
 
During 2012, we drilled and completed eleven operated wells in our Mid-Continent region, which included four wells in the Cana and Cana Southeast Shale plays and seven wells in the Golden Trend Field. In addition, we participated with a working interest in twenty non-operated wells drilled and completed in the region. In our remaining operated regions, we drilled and completed one operated well in the Permian Basin, and one non-operated well in East Texas. During 2012, recompletion and workover projects were conducted on thirty-one operated wells and one non-operated well across our

21


Upstream segment. Overall, the capital program generated a unit development cost of $22.08/Boe. As of December 31, 2012, we were in the process of drilling eight gross wells (2.7 net).

From the close of our Mid-Continent Acquisition in May 2011 through December 31, 2011, we drilled and completed eleven operated wells in our Mid-Continent region which included two wells in the Cana Shale play, four wells in the Golden Trend Field, and three wells in the Texas Panhandle. Additionally we participated with a working interest in thirty-one non-operated wells drilled and completed in the region. In our remaining operated regions, we drilled and completed one well in our Edgewood field in East Texas, and one well in our Big Escambia Creek field. Our success rate in 2011 was approximately 81% for the forty-two well drilling program with a total program unit development cost of $13.86/Boe.

During 2011, recompletion and capital workover projects were conducted on thirteen operated wells across our Upstream segment. Eight of the thirteen recompletion and capital workovers were successful. The program unit development cost for these operations was $7.44/Boe.

In 2010, we drilled and completed five successful operated wells in the Upstream Segment. All five wells were drilled and successfully completed in our Ward Estes field in the Permian basin from the Penn and Wolfcamp formations. A sixth operated well was drilled in our Southern Unit Field in the Permian Basin but was unsuccessful. The total program development cost of these six wells was $17.23/Boe.

Recompletions, capital workovers or pipeline projects were conducted on fourteen operated wells across our Upstream Segment during 2010. Eight of the fourteen capital workovers were successful. The program unit development cost for these fourteen operations was $6.27/Boe.

Oil and Natural Gas Reserves
     
Estimates of proved reserves as of December 31, 2012 were based on estimates made by our independent engineers, Cawley, Gillespie & Associates, Inc (“CGA”). CGA has conducted the annual estimate of proved reserves for us since 2007. In 2012, CGA was engaged by and provided its reports to our senior management team.  The Audit Committee has the authority to engage and terminate the independent reserve engineer.  Management continues, however, to have direct oversight of the independent reserve engineer's activities.  
 
We make representations to CGA that we have provided all relevant operating data and documents, and in turn, we review the reserve reports provided by CGA to ensure completeness and accuracy. Our review entails a comparison of the forecasts and other parameters in the reserve report to our internal estimates and our historical results.  If discrepancies are identified, we discuss these issues with CGA and provide them with additional information.  This process may or may not result in changes to their estimates, but the final report will represent their estimates, based on the data we provided and their engineering judgment.  

Qualifications of Reserve Estimators
   
Our reserves reporting process involves two major steps: (i) the population of a reserves database by our Technical Evaluations staff, and (ii) the preparation of an independent reserves report which uses the database as its starting point.  The independent reserves report is prepared by CGA, which is a Texas Registered Engineering Firm (F-693).  The primary engineer on our account is Ms. Kellie Jordan who works under the supervision of Mr. Robert Ravnaas, Executive Vice President.  Mr. Ravnaas is a State of Texas Licensed Professional Engineer (License #61304). CGA's report is attached as Exhibit 99.1 to this Annual Report on Form 10-K.
 
In the preparation of its report, CGA relies on engineering and other data provided by our staff and overseen by our Senior Vice President - Technical Evaluations, Mr. Steven Hendrickson.  Mr. Hendrickson is a State of Texas Licensed Professional Engineer (License #65951) with over 29 years of experience in petroleum engineering, operations, economics, finance, acquisitions and risk management.  He earned a bachelors of science degree in chemical engineering from the University of Texas and a masters of science degree in finance from the University of Houston.  He is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.
 
Internal Controls Over Reserve Estimation
 
One of our primary controls with respect to reserve reporting is the independent reserve report; however, we also have various internal controls to ensure that the data we supply to CGA is accurate.  Among other things, our internal controls include the following items:

22



A process to identify all of the newly-drilled producing wells and add them to our database.
A process to retrieve production data from our IHS Software Application to use as the basis of our decline curve forecasts.
A process to estimate various economic parameters, such as operating costs; price differentials; gas shrinkages; and condensate, NGL and sulfur yields.  This process relies on historical data provided by our accounting department and our operations engineers.
A process to check the working and net revenue interests in our reserves database to ensure they are consistent with our land and revenue accounting records.
A process to identify and document the engineering and geological support for our developed non-producing and undeveloped reserves.
Processes to estimate future capital expenditures and abandonment costs that are based on our prior experiences and engineering judgment.
 
We use the data gathered and estimated in the processes above to populate our reserves database.  Our Technical Evaluations staff prepares a reserves estimate for each well in which we own an interest (including non-producing and undeveloped locations).  This database is then provided to CGA, along with any additional supporting information they request, and forms the primary basis for their reserve estimates.
 
After CGA has made their preliminary reserves estimate, the Senior Vice President – Technical Evaluations reviews their results and compares them to our historic production rates, operating costs, price differentials, severance tax rates and ad valorem tax rates.  If they are not consistent with our historical results, the database is scrutinized to identify and correct possible sources of error.  The Senior Vice President – Technical Evaluations and his staff also review the production forecasts prepared by CGA for possible errors, omissions or significant differences in engineering judgment.  In those instances, the issue is discussed with CGA and additional supporting data is provided, if needed.  Capital costs and investment timing are also reviewed to ensure that they are consistent with our five year development plan and our approved budget.
 
After CGA has completed their report, our Technical Evaluations group prepares the reserves reconciliation.  During this process, we occasionally identify small discrepancies that we believe should be corrected and these discrepancies  are discussed and resolved with CGA.
 
General Reserve Estimation Methods
   
Because the majority of our proved reserves are classified as proved developed producing reserves, we use production performance methods (decline curve analysis) extensively in the preparation of our proved reserves estimates.  Our estimates of proved undeveloped and proved developed non-producing reserves are based on volumetric methods and analogy to offset producers.  Where applicable, we occasionally use material balance methods to estimate reserve quantities.  We have not used reservoir simulation or proprietary methods to prepare our reserves estimates.
   
Proved Reserves
 
The following table presents our estimated net proved natural gas and oil reserves in the Upstream Business on December 31, 2012. These values are based on independent reserve reports prepared by Cawley, Gillespie & Associates, Inc.
 

23


 
As of
December 31, 2012
Reserve Data: Upstream Business
 
Estimated net proved reserves:
 
Natural gas (Bcf)
194.4

Oil (MMBbls)
13.0

Natural Gas Liquids (MMBbls)
12.9

Total (Bcfe)
349.6

Proved developed (Bcfe)
265.2

Proved developed reserves as % of total proved reserves
76
%
 
 

Estimated net undeveloped reserves:
 

Natural gas (Bcf)
57.9

Oil (MMBbls)
2.0

Natural Gas Liquids (MMBbls)
2.4

Total (Bcfe)
84.4

Proved undeveloped (Bcfe)
84.4

 
Proved Undeveloped Reserves
 
As a master limited partnership, we grow primarily through acquisitions of producing properties and subsequently conduct development activities on those properties to maintain our production rates.  The acquisition candidates that meet our investment criteria often have a high ratio of developed to undeveloped reserves, and we conduct limited exploration activities. As of December 31, 2012, we had 135 drilling locations associated with proved undeveloped reserves, most of which were acquired in the Mid-Continent acquisition.
 
We approach the development of our undeveloped reserves in a measured pace, in order to hold our production rate fairly constant or slightly inclining.  The development plan in our proved reserves report contemplates the drilling of all of our undeveloped locations within five years.
 
Our undeveloped drilling locations are concentrated in the Mid-Continent region, primarily in the Golden Trend Field of Grady County, Oklahoma and the Cana Shale and Southeast Cana Shale plays in western Oklahoma.

Of the thirty-three wells drilled during the year ended December 31, 2012, eight of the operated wells and three of the non-operated wells were proved undeveloped locations. In 2011, of the forty-two wells drilled, six of the operated wells and two of the non-operated wells were proved undeveloped locations. In 2010, of the six wells we drilled, five were proved undeveloped locations.

Oil and Natural Gas Production

For detail and discussion of our net production and realized prices by product for the years ended December 31, 2012, 2011 and 2010, see our discussion of the results of operations for our Upstream Business within Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Year Ended December 31, 2012 Compared with Year Ended December 31, 2011 and Year Ended December 31, 2011 Compared with Year Ended December 31, 2010.  Production costs, excluding ad valorem and severance taxes for our Upstream Business for the years ended December 31, 2012, 2011 and 2010 were $7.14/Boe, $7.44/Boe and $12.72/Boe, respectively.  

Regulation of Our Operations
 
Safety and Maintenance Regulation
 
Midstream Business
 
Our Midstream Business is subject to several federal and state laws and regulations, including federal safety standards developed under the Occupational Safety and Health Act of 1970, as amended (“OSHA”), and comparable state statutes, the purpose of which are to protect the safety and health of workers.  We incur costs related to compliance (including training) with

24


all of these laws and regulations and for monitoring and maintaining our facilities in safe operating conditions.  Consequences of non-compliance with these laws and regulations are potential fines from the federal or state government agencies and disruption of operations due to injuries or equipment failure.
 
The OSHA process safety management (“PSM”) standard is designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. This standard applies to most processes that involve a chemical at or above the specified thresholds and certain processes which handle more than 10,000 lbs. of flammable liquids or gas, as defined in the regulation, excluding such flammable materials or processes specifically exempted within the regulation. Some of our facilities are covered by the PSM standard. Among other things, the PSM standard requires us to conduct compliance audits every three years. We are on schedule to timely complete these audits.

We are also subject to the EPA’s Risk Management Plan (“RMP”) regulations at certain facilities. These regulations are intended to work with the OSHA Process Safety Management regulations to minimize the offsite consequences of catastrophic releases. The regulations require companies to develop and implement a risk management program that includes a five-year accident history, an offsite consequence analysis process, a prevention program and an emergency response program.

Safety matters associated with our pipelines are regulated at the federal level by the Pipeline and Hazardous Materials Safety Administration ("PHMSA") of the U.S. Department of Transportation ("DOT") Office of Pipeline Safety ("OPS"). The safety of our pipelines is also regulated by the states in which we operate. States are largely preempted by federal law from regulating pipeline safety for interstate lines but most are certified by the DOT to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. Because states can adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines, states vary considerably in their authority and capacity to address pipeline safety. For more information regarding the regulations that may impact us, see "Item 1A.Risk Factors - We may incur significant costs and liabilities resulting from safety and compliance-related regulations."

Upstream Business
 
Our Upstream Business implicates safety matters with respect to the drilling and production of hydrocarbons and carries consequences of non-compliance consistent with those discussed above under the safety matters for the Midstream Business.  This segment of our business is subject to OSHA, EPA Risk Management Plan and DOT standards.  For more information regarding the regulations that may impact us, see "Item 1A.Risk Factors - We may incur significant costs and liabilities resulting from safety and compliance-related regulations."
 
Our Upstream Business is also subject to safety rules and regulations promulgated by state agencies. While these agencies have established some regulations designed to protect worker and community health and safety, their primary focus is on environmentally sound drilling, servicing, and production operations. See "Item 1A. Risk Factors - We may incur significant costs and liabilities resulting from safety and compliance-related regulations."
 
FERC and Similar State Regulations
 
Under the Natural Gas Act of 1938, or NGA, as amended by the Energy Policy Act of 2005, or EPAct 2005, the Federal Energy Regulatory Commission (“FERC”) has jurisdiction over the transportation of natural gas in interstate commerce and the sale of natural gas for resale in interstate commerce, and entities engaged in such activities.  FERC also possesses regulatory oversight over natural gas markets, including the purchase, sale and transportation activities of non-interstate pipelines and other natural gas market participants. FERC possesses substantial enforcement authority for violations of the NGA, including the ability to assess civil penalties, order disgorgement of profits and recommend criminal penalties.  

EPAct 2005 amended the NGA to grant FERC new authority to facilitate price transparency in markets for the sale or transportation of physical natural gas in interstate commerce, and to prohibit market manipulation.  FERC's anti-manipulation regulations apply to FERC jurisdictional activities, which has been broadly construed by the FERC. Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial civil and criminal penalties, including civil penalties of up to $1.0 million per day, per violation.
 
In 2008, FERC took additional steps to enhance its market oversight and monitoring of the natural gas industry.  Order No. 704, as clarified in orders on rehearing, requires buyers and sellers of natural gas above a de minimis level, including entities not otherwise subject to FERC jurisdiction, to submit an annual report to FERC describing their wholesale physical natural gas transactions that use an index or that contribute to or may contribute to the formation of a gas index.  The FERC is currently contemplating expanding the industry's reporting requirements. On November 15, 2012, the FERC issued a Notice of Inquiry seeking comments whether requiring quarterly reporting of every gas transaction within the FERC's jurisdiction that

25


entails physical delivery for the next day or the next month would provide useful information for improving natural gas market transparency. Comments on the Notice of Inquiry were due by February 12, 2013.

Our natural gas gathering operations are generally exempt from direct FERC regulation under the NGA; however, FERC has enforcement authority over certain aspects of our business through its jurisdiction over natural gas markets and intrastate pipelines that engage in interstate transportation services.

Our Eagle Rock DeSoto Pipeline, L.P., operations are subject to FERC regulation of the rates, terms and conditions of service to the extent that the DeSoto Pipeline transports gas in interstate commerce under Section 311 of the Natural Gas Policy Act, or NGPA. Rates for Section 311 transportation service must be fair and equitable, and amounts collected in excess of fair and equitable rates are subject to refund with interest. For additional information regarding the applicability of Section 311 to us, see "Item 1A. Risk Factors - Our Eagle Rock DeSoto Pipeline, L.P. (“DeSoto Pipeline”) transports gas in interstate commerce on its Central and North Texas Systems and is therefore subject to FERC regulation under Section 311 of the NGPA."
    
In 2010, the FERC issued Order No. 735, to be effective April 1, 2011 (further clarified by Order No. 735-A on December 16, 2010), which requires intrastate pipelines providing transportation services under Section 311 of the NGPA to report on a quarterly basis more detailed transportation and storage transaction information, including: rates charged by the pipeline under each contract; receipt and delivery points and zones or segments covered by each contract; the quantity of natural gas the shipper is entitled to transport, store, or deliver; the duration of the contract; and whether there is an affiliate relationship between the pipeline and the shipper. Order No. 735 further requires that such information be supplied through a new electronic reporting system and will be posted on FERC's website, and that such quarterly reports may not contain information redacted as privileged. Order No. 735 also extends the Commission's periodic review of the rates charged by the subject pipelines from three years to five years. On October 18, 2012, the FERC issued a Notice of Proposed Rulemaking, proposing to provide streamlined procedures for processing uncontested NGPA Section 311 rate filings. Under such procedures, the filing would be deemed approved without issuance of a FERC order if no protest is filed within a specified period of time, or if any protests are resolved within a reconciliation period. Comments on the Notice of Proposed Rulemaking were filed in December 2012, and FERC action is pending.

FERC issued a Notice of Inquiry on October 21, 2010, requesting comments on whether and how holders of firm capacity on intrastate pipelines providing transportation services under Section 311 of the NGPA should be permitted to allow others to make use of their firm intrastate capacity. Comments were filed in January 2011, and FERC action is pending. The Notice of Inquiry may lead to regulations that impact our DeSoto Pipeline operations.

Midstream Business
 
Regulation of pipeline gathering and transportation services, natural gas sales and transportation of NGLs may affect certain aspects of our business and the market for our products and services.

Gathering Pipeline Regulation. Section 1(b) of the NGA exempts natural gas gathering facilities from direct regulation by the FERC, but does not define or provide any guidance as to what constitutes “gathering.” For more information regarding the applicability of Section 1(b) of the NGA, see "Item 1A. Risk Factors- A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase."
 
Our purchasing and gathering operations are subject to ratable take and common purchaser statutes. Texas and Louisiana have adopted a complaint-based form of regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints to resolve grievances relating to natural gas gathering access and rate discrimination.  The TRRC has authority to enforce its statutory duty to prevent discrimination in natural gas gathering and transportation, to enforce the requirement that parties participate in an informal complaint process, and to punish purchasers, transporters, and gatherers for taking discriminatory actions against shippers and sellers through the imposition of administrative, civil and criminal penalties. For more information on the applicability of the common purchaser and like statutes on us, see "Risk Factors Item 1.A- We may incur significant costs and liabilities resulting from safety and compliance-related regulations."

The TRRC is subject to a sunset condition and a sunset review occurred during the 2011 legislation session. The sunset legislation did not pass, and the Texas Legislature approved continuation of the TRRC for an additional two-year period to September 1, 2013. If the Texas Legislature does not continue the TRRC in the 2013 legislative session, the TRRC will be abolished effective September 1, 2013, and will begin a one-year wind-down process. The Sunset Advisory Commission has recommended certain organizational and other changes be made to the TRRC. We expect the Texas legislature to consider the

26


Sunset Advisory Commission recommendations and take action during the 2013 legislative session to continue the TRRC beyond September 1, 2013. We cannot, however, tell what, if any, changes will be made to the TRRC during the 2013 legislative session, but we do not believe that any such changes would affect our business in a way that would be materially different from the way such changes would affect our competition. For more discussion regarding common purchaser statutes and the TRRC's authority over us, see "Risk Factors Item 1.A- We may incur significant costs and liabilities resulting from safety and compliance-related regulations."

The DOT regulates the design, installation, testing, construction, operation, replacement, and management of our pipeline facilities. In addition, we must permit access to and copying of records, and must make certain reports and provide information, as required by the Secretary of Transportation. The states in which we have pipelines have comparable regulations.
 
We are subject to regulation by the DOT under the Accountable Pipeline and Safety Partnership Act of 1996, sometimes referred to as the Hazardous Liquid Pipeline Safety Act (“HLPSA”), and comparable state statutes relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. The HLPSA covers petroleum and petroleum products and requires any entity that owns or operates pipeline facilities to (i) comply with such regulations, (ii) permit access to and copying of records, (iii) file certain reports and (iv) provide information as required by the Secretary of Transportation.
 
We are subject to the DOT regulation requiring qualification of pipeline personnel. The regulation requires pipeline operators to develop and maintain a written qualification program for individuals performing covered tasks on pipeline facilities. The intent of this regulation is to ensure a qualified work force and to reduce the probability and consequence of incidents caused by human error. The regulation establishes qualification requirements for individuals performing covered tasks.
   
We are also subject to the DOT Integrity Management regulations, which specify how companies should assess, evaluate, validate and maintain the integrity of pipeline segments that, in the event of a release, could impact High Consequence Areas (“HCAs”). HCAs are defined to include populated areas, unusually sensitive environmental areas and commercially navigable waterways. We are required to develop and implement an Integrity Management Program (“IMP”) that utilizes internal pipeline inspection, pressure testing, or other equally effective means to assess the integrity of HCA pipeline segments. We are also required to periodically review HCA pipeline segments to ensure adequate preventative and mitigative measures exist and take prompt action to address integrity issues raised by the assessment and analysis.

Intrastate Natural Gas Pipeline Regulation. The TRRC has authority over the rates, terms and conditions of service for our DeSoto Pipeline's intrastate transportation activities.
 
Intrastate NGL Pipeline Regulation. We do not own any NGL pipelines subject to FERC regulation. We do own and operate an intrastate common carrier NGL pipeline subject to the regulation of the TRRC. The TRRC requires that intrastate NGL pipelines file tariff publications that contain all the rules and regulations governing the rates and charges for service performed. The applicable Texas statutes require that NGL pipeline rates provide no more than a fair return on the aggregate value of the pipeline property used to render services. State commissions have generally not been aggressive in regulating common carrier pipelines and have generally not investigated the rates or practices of NGL pipelines in the absence of shipper complaints. Complaints to state agencies have been infrequent and are usually resolved informally. Although we cannot assure that our intrastate rates would ultimately be upheld if challenged, we believe that, given this history, the tariffs now in effect are not likely to be challenged or, if challenged, are not likely to be ordered to be reduced.  
 
Sales of Natural Gas. Our sales of natural gas for resale in interstate commerce are conducted pursuant to a blanket marketing certificate issued by the FERC. The price at which we buy and sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The FERC is continually proposing and implementing new rules and regulations affecting the natural gas industry. These initiatives may affect the intrastate transportation of natural gas under certain circumstances.  FERC has imposed an annual reporting requirement on all industry participants, including otherwise non-jurisdictional entities, engaged in wholesale physical natural gas sales and purchases in excess of a de minimis level, and is currently considering imposing quarterly reporting requirements for certain gas sales.  Further, our physical purchases and sales of natural gas, our gathering and/or transportation of natural gas, and any related hedging activities that we undertake are subject to anti-market manipulation regulation by FERC and/or the Commodity Futures Trading Commission.  These agencies hold substantial enforcement authority, including the ability to assess substantial civil penalties, to order disgorgement of profits, and to recommend criminal penalties for violations of anti-market manipulation laws and related regulations.  Violation

27


of the anti-market manipulation laws and regulations could also subject us to related third-party damage claims.  We do not believe that we will be affected by these anti-market manipulation requirements materially differently than other natural gas marketers with whom we compete.
 
Upstream Business
 
The natural gas and oil industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the natural gas and oil industry is constantly evolving, frequently increasing the regulatory burden. Numerous departments and agencies, both federal and state, are authorized by statute to issue new and revised rules and regulations, some of which carry substantial penalties for failure to comply, which could be applicable to our business. Although the regulatory burden on the natural gas and oil industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

  Drilling and Production. The activities conducted by us and by the operators on our properties are subject to significant regulation at the federal, state and local levels. These regulations include requiring permits for the drilling of wells, posting of drilling bonds and filing reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:
 
the location of wells; 
the method of drilling and casing wells; 
the surface use and restoration of properties upon which wells are drilled; 
the disposal of fluids and solids used in connection with our operations; 
air emissions associated with our operations; 
the plugging and abandoning of wells; and 
notice to surface owners and other third parties.
 
State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of natural gas and oil properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production from natural gas and oil wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of natural gas and oil we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. Additionally, some municipalities also impose property taxes on oil and natural gas interests, production equipment, and our production revenues. For more information regarding the regulations that govern us, see "Item 1A.Risk Factors - We may incur significant costs and liabilities resulting from safety and compliance-related regulations." and "Item 1A.Risk Factors - Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays."

Federal Regulation. Although natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural gas prices or market participants might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties. Sales of condensate and natural gas liquids are not currently regulated and are made at market prices.
 
State Regulation. The various states regulate the drilling for, and the production, gathering and sale of, natural gas, including imposing severance taxes and requirements for obtaining drilling permits. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. For more information regarding the impact of state regulation on us and our operations, see "Item 1A.Risk Factors - We are subject to compliance with stringent environmental and safety laws and regulations that may expose us to significant costs and liabilities, and future regulations may be more stringent" and "Item 1A. Risk Factors - We may incur significant costs and liabilities resulting from safety and compliance-related regulations."
 
The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal employment opportunity.

28



Environmental Matters
 
Midstream Business
 
We operate pipelines, plants, and other facilities for gathering, compressing, treating, processing, fractionating, or transporting natural gas, NGLs, and other products that are subject to stringent and complex federal, state, and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection or safety. We have programs and policies designed to keep our pipelines, plants, and other facilities in compliance with existing environmental laws and regulations. For more information regarding the impact of environmental regulations on us, see "Item 1A.Risk Factors - We are subject to compliance with stringent environmental and safety laws and regulations that may expose us to significant costs and liabilities, and future regulations may be more stringent."

The following is a summary of the more significant existing environmental laws and regulations to which our business operations are subject:
 The Federal Clean Air Act, as amended, and comparable state laws restrict the emission of air pollutants from many sources, including our processing plants and compressor stations. These laws and regulations require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to emit new pollutants or increase emissions, obtain and comply with air permits containing various emission and operational limitations, and utilize specific equipment or technologies to control emissions. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. For instance, in 2010, the United States Environmental Protection Agency ("EPA") adopted final rules making more stringent the National Ambient Air Quality Standards (“NAAQS”) for sulfur dioxide and nitrogen dioxide. Further, EPA periodically reviews and may lower the NAAQS for various pollutants in the future. Attainment of these new NAAQS will likely require us to install more stringent controls at our facilities, which would result in increased capital expenditures. In addition, on August 16, 2012, the EPA published a final New Source Performance Standards (“NSPS”) and National Emissions Standards for Hazardous Air Pollutants (“NESHAP”) that establish new air emission control requirements for natural gas and NGL production, gathering and processing and transportation activities.

We could also be impacted by federal regulations limiting greenhouse gas emissions or imposing reporting obligations with respect to such emissions which have been proposed or finalized.  For a discussion of the effects of greenhouse gas regulation, see “Item 1A. Risk Factors- Climate change laws or regulations restricting emissions of 'greenhouse gases' could result in increased operating costs and a decreased demand for oil and natural gas that we produce or process.”

The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” and analogous state laws impose restrictions and controls on the discharge of pollutants into federal and state waters. Pursuant to these laws and regulations, we are required to obtain and maintain approvals or permits for certain wastewater and stormwater discharges and discharges of dredged or fill material in wetlands and other waters of the United States, as well as develop and to implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of greater than threshold quantities of oil.
 
The primary federal law for oil spill liability is the Oil Pollution Act of 1990 (“OPA”), which addresses three principal areas of oil pollution—(a) prevention, (b) containment and cleanup, and (c) liability. OPA applies to vessels, offshore platforms and onshore facilities, including terminals, pipelines and transfer facilities, and subjects owners of such facilities to strict liability for containment and removal costs, natural resource damages and certain other consequences of an oil spill, where such spill is into waters of the U.S. Any unpermitted release of petroleum or other pollutants from our operations could result in potential liability. Some states maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.  These programs may also require remedial activities or capital expenditures to mitigate groundwater contamination along our pipeline systems as a result of past or current operations.  Contamination of groundwater resulting from spills or releases of oil or gas is an inherent risk within our industry.

The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as “CERCLA” or “Superfund,” and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. Under CERCLA, these “responsible persons” may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. We also generate materials in the course of our operations that may be regulated as hazardous substances and we may incur liability under the Resource Conservation and Recovery Act, as amended, also known

29


as “RCRA,” which imposes requirements related to the handling and disposal of solid and hazardous wastes, as well as similar state laws. In the course of our operations we may generate petroleum product wastes and ordinary industrial wastes that may be regulated as solid and hazardous wastes under RCRA.

We currently own or lease, and have in the past owned or leased, properties that for many years have been used for midstream natural gas and NGL activities. Although we used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where such wastes have been taken for disposal. In addition, some of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons and wastes were not under our control. These properties and the materials disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of by prior owners or operators) or contaminated property (including ground water contamination), or to perform activities to prevent future contamination.

The federal Endangered Species Act, as amended, or “ESA,” restricts activities that may affect endangered or threatened species or their habitats. While some of our facilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.
In addition to claims arising under state and federal statutes, where a release or spill of hazardous substances, oil and gas, or oil and gas wastes have occurred, private parties or landowners may bring lawsuits under state law. The plaintiffs in such lawsuits may seek property damages, personal injury damages, remediation costs or injunctions to require remediation or restoration of contaminated environmental media, including soil, sediment, groundwater or surface water. Some of our oil and gas operations are located near populated areas and routine emissions or accidental releases could affect the surrounding properties and population.
 
Upstream Business
 
Our Upstream Business involves acquiring, developing and producing oil and natural gas working interests.  
 
Our operations and those of our lease operators are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection or safety. Our Upstream Business is subject to the same environmental laws and regulations that are discussed in our Midstream Business section above. Like our Midstream Business, our Upstream Business could be impacted by any legislation or regulations that are adopted to address greenhouse gas emissions in the United States. For further discussion of these environmental laws and regulations, see “Midstream Business” above and “Item 1A. Risk Factors-We are subject to compliance with stringent environmental laws and regulations that may expose us to significant costs and liabilities, and future regulations may be more stringent.”

On our working interest properties, and particularly our operated properties, we are responsible for conducting operations in a manner that complies with applicable environmental laws and regulations.  These laws and regulations can adversely affect our capital expenditures, earnings and competitive position in many ways, such as:
requiring the acquisition of various permits before drilling commences;
requiring the installation of pollution control equipment;
restricting the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;
limiting or prohibiting drilling activities on lands lying within wilderness, wetlands and other protected areas;
requiring remedial measures to prevent pollution from former operations, such as pit closure and plugging of abandoned wells;
imposing substantial liabilities for pollution resulting from our operations;
with respect to operations affecting federal lands or leases, requiring preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement; and
restricting the rate of natural gas and oil production below the rate that would otherwise be possible.

Consistent with normal industry practices, substantially all of our oil and gas leases require that, upon termination of economic production, the working interest owners plug and abandon non-producing wellbores, remove tanks, production equipment and flow lines and restore the wellsite.  We have recorded liabilities for these asset retirement obligations in

30


accordance with authoritative guidance which applies to obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. The guidance requires that we record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset.

Hydraulic fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly from tight formations. For additional information about hydraulic fracturing and related environmental matters, see “Item 1A. Risk Factors-Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.”

Title to Properties and Rights-of-Way
   
Midstream Business
 
Our midstream real property falls into two categories: (i) parcels that we own in fee simple and (ii) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for our operations. Portions of the land on which our plants and other major facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our plant sites and major facilities are located are held by us pursuant to ground leases between us, as lessee, and the fee owner of the lands, as lessors. We, or our predecessors, have leased these lands for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates to such lands. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or lease, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses.
 
Upstream Business
 
As is customary in the natural gas and oil industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to completing an acquisition of producing natural gas and/or oil properties, we perform title reviews on the most significant leases and, depending on the materiality of properties or irregularities we may observe in the title chain, we may obtain a title opinion or review previously obtained title opinions. As a result, we have obtained or reviewed title opinions on a significant portion of our natural gas and/or oil properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the natural gas and oil industry. Our natural gas and/or oil properties are subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.

Employees
 
To carry out our operations, as of December 31, 2012, Eagle Rock Energy G&P, LLC or its affiliates employed approximately 510 people who provide direct support for our operations. In addition, on January 1, 2013, an additional 78 employees were added due to the Panhandle Acquisition. None of these employees are covered by collective bargaining agreements. Eagle Rock Energy G&P, LLC considers its employee relations to be good.

Available Information
 
We provide access free of charge to all of our SEC filings, as soon as reasonably practicable after filing or furnishing it, on our internet site located at www.eaglerockenergy.com. We will also make available to any unitholder, without charge, copies of our Annual Report on Form 10-K as filed with the SEC. For copies of this, or any other filing, please contact: Eagle Rock Energy Partners, L.P., General Counsel or Chief Financial Officer, 1415 Louisiana Street, Suite 2700, Houston, TX 77002, or call 281-408-1200. Unless explicitly stated otherwise herein, the information on our website is not incorporated by reference into this Annual Report on Form 10-K.
 
In addition, the public may read and copy any materials Eagle Rock files with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains a website (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.

31



Item 1A.
Risk Factors.

Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses.
   
If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay a distribution on our common units, the trading price of our common units could decline and you could lose all or part of your investment.

Risks Related to Our Business
 
We may not have sufficient cash from operations following the establishment of cash reserves to enable us to make cash distributions at any particular level or at all.
 
The amount of cash available to us to distribute on our units may fluctuate from quarter to quarter based on, among other things:
 
the level of production of oil and natural gas we gather, treat, compress, process, transport and sell; and the volume of NGLs we capture, transport and sell in our Midstream Business;
the level of oil, natural gas, NGLs and condensate that we produce in our Upstream Business;
volatility in the realized prices for oil, natural gas, NGLs and condensate that we and others produce;
the effectiveness of our hedging program and the creditworthiness of our hedging counterparties;
our level of indebtedness, debt service requirements and need to reduce outstanding indebtedness;
our ability to borrow funds and access capital markets; 
the level of our operating and general and administrative costs;
our decisions regarding the level and use of available cash for growth versus maintenance capital expenditures;
our operators’ and other producers’ drilling activities and success of such programs; and
the level of competition from other upstream and midstream energy companies.

As a result of these factors, the amount of cash we distribute to our unitholders may be significantly less than the current distribution level, or the distribution may be suspended. In addition, under our partnership agreement, our General Partner may determine to establish any cash reserve necessary for the proper conduct of our business including reserves for future capital expenditures, future credit needs and to better ensure continued compliance with our credit facility and the indenture governing our 8.375% Senior Notes Due 2019 (the "senior notes") before making distributions to our unitholders.

Our general partner also determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, and issuances of additional partnership securities, which, together with establishing reserves, can affect the amount of cash available for distribution to our unitholders. As a result, we may make distributions during periods when we record losses and may not make distributions during periods when we record net income.

Because of the natural decline in production from existing wells, our success depends on our ability to obtain new sources of production and supplies of oil, natural gas and NGLs, which are dependent on certain factors, many of which are beyond our control. Our success is also dependent on developing current reserves. Any decrease in production or supplies of oil, natural gas or NGLs could adversely affect our business and operating results.
 
The volume of gas that we gather, process and/or produce is dependent on the level of production from hydrocarbon-producing wells.  The production rate of these wells naturally will decline over time, and as a result, our cash flows associated with them will also decline over time. In order to maintain or increase the throughput levels of our assets we must continually obtain new supplies of natural gas to offset these declines.
 
In our Midstream Business, the primary factors affecting our ability to obtain new supplies of natural gas and NGLs and attract new customers to our assets include: (i) the level of successful drilling activity by producers near our systems and (ii) our ability to compete for volumes from successful new wells.  The level of drilling activity is dependent on economic and business factors that are beyond our control. The primary factor that impacts producers’ drilling decisions is natural gas prices. A sustained decline in natural gas prices could result in a decrease in exploration and development activities in the fields served by our gathering systems and our natural gas treating and processing plants, which would lead to reduced utilization of these assets. Other factors that impact production decisions include producers’ capital budgets, the ability of producers to obtain capital and necessary drilling and other governmental permits and regulatory changes. Because of these factors, even if new

32


natural gas reserves are discovered in areas served by our assets, we and other producers may choose not to develop those reserves.
 
In our Upstream Business, we also have risks inherent with declining reserves. Our producing reservoirs experience production rate declines that vary depending upon reservoir characteristics and other factors. The overall production decline rate of our upstream business may change when additional wells are drilled, when we make acquisitions and under other circumstances. Our future cash flows and income, and our ability to maintain and to increase distributions to unitholders, are partly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition and results of operations. Factors that may hinder our ability to acquire additional reserves or develop current reserves include competition, access to capital, prevailing oil and natural gas prices, the costs incurred by us to develop and exploit current and future oil and natural gas reserves, and the number and attractiveness of properties for sale.
 
Natural gas, NGLs, crude oil and other commodity prices are volatile, and an adverse movement in these prices could adversely affect our cash flow and our ability to make distributions.
 
We are subject to risks related to frequent and often substantial fluctuations in commodity prices. In the past, the prices of natural gas, NGLs and crude oil have been extremely volatile, and we expect this volatility to continue. A drop in prices can significantly affect our financial results and impede our growth, including our ability to maintain or increase our borrowing capacity, to repay current or future indebtedness and to obtain additional capital on attractive terms, all of which can affect our ability to pay distributions.
 
Changes in natural gas, NGL and crude oil prices have a significant impact on the value of our reserves and on our cash flows. In 2012, the settlement price of the prompt month NYMEX natural gas contract ranged from $1.91 per MMBtu to $3.90 per MMBtu, and the settlement price of prompt month NYMEX crude oil contract ranged from $77.69 per barrel to $109.77 per barrel.
 
The prices for natural gas, NGLs and crude oil depend upon the supply and demand for these products, which in turn depend on a large number of complex, interrelated factors that are beyond our control. These factors include:
 
the overall level of economic activity in the United States and the world; 
the impact of weather or other force majeure events; 
political and economic conditions and events in, as well as actions taken by, foreign oil and natural gas producing nations; 
significant crude oil or natural gas discoveries;
application of new technologies that make the development of large resource plays economically attractive; 
the availability of local, intrastate and interstate transportation systems for natural gas, NGLs and crude oil; 
the availability and marketing of competitive fuels; 
delays or cancellations of crude oil and natural gas drilling and production activities; 
the impact of energy conservation efforts, including technological advances affecting energy consumption; and 
the extent of governmental regulation and taxation.
 
Lower natural gas, NGL or crude oil prices may not only decrease our revenues and net proceeds, but may also reduce the amount of natural gas, NGLs or crude oil that our Upstream Business and our Midstream Business's producer-customers can economically produce. As a result, especially during periods of low commodity prices, we or our producer customers may decide to shut in or curtail production, or to plug and abandon marginal wells, which could have a material adverse effect on our future cash flows.
 
Low commodity prices may result in additional write-downs of our asset carrying values.
 
In our Upstream Business, low oil and natural gas prices may result in substantial downward adjustments to our estimated proved reserves.  Furthermore, if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties.  Low oil and natural gas prices also may result in reduced drilling activity and declines in future cash flows within our Midstream Business.

We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated future cash flows of

33


our assets, the carrying value may not be recoverable and therefore may require a write-down. During the year ended December 31, 2012, we incurred total impairment and other charges of $177.0 million, primarily as a result of (i) reduced throughput volumes as our producer customers curtailed their drilling activity in response to the continued depressed natural gas price environment, (ii) the loss of significant gathering contracts on various systems, (iii) the substantial damage incurred at our Yscloskey processing plant as a result of Hurricane Isaac in August 2012, (iv) certain leaseholds in our unproved properties that we expect to expire undrilled in 2013 and (v) our proved properties in certain regions that are expected to have reduced operating income resulting from natural production declines, lower future natural gas prices and ongoing relatively high operating costs associated with gas compression.. See Note 5 and Note 12 to our consolidated financial statements for further discussion. During the year ended December 31, 2011, we incurred total impairment charges of $16.3 million, primarily as a result of contract terminations notifications by significant producers in our East Texas and Other Midstream Segment.   We may incur additional impairment charges in the future, which could have a material adverse effect on our results of operations and financial position in the period incurred.

Our hedging activities may have a material adverse effect on our earnings, profitability, cash flows and financial condition.
 
Because we are exposed to risks associated with fluctuating commodity prices, we utilize various financial instruments (swaps, collars, and puts) to mitigate these risks within our overall hedge portfolio. Separate from our hedge portfolio, we capitalize on financial arbitrage opportunities and diversify our credit and performance risk for discrete products on a limited basis through our newly-formed gas marketing and trading subsidiary. It is possible that our various hedging activities may not be effective in reducing our exposure to commodity price risk. For instance, we may not produce or process sufficient volumes to cover our hedges, we may fail to hedge a sufficient portion of our future production or the instruments we use may not adequately correlate with changes in the prices we receive. Our current hedging portfolio is presented in Part II, Item 7A. Qualitative and Quantitative Disclosure About Market Risk. For more information about the activities of our trading and marketing subsidiary, which are not listed within our hedging portfolio, see "Part I, Item 1. Our Two Lines of Business - Midstream Business - Marketing and Trading Segment.
 
To the extent we hedge our commodity price and interest rate risk, we may forego the benefits we would otherwise experience when commodity prices or interest rates improve. Furthermore, because we have entered into derivative transactions related to only a portion of the commodity volumes and outstanding debt to which we have price and interest rate exposure, we will continue to have direct commodity price and interest rate risk on the unhedged portion. Our actual future supply and production may be significantly higher or lower than we estimated at the time we entered into the commodity derivative transactions for that period. If the actual amount is higher than we estimated, we will have more commodity price risk than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of a corresponding settlement of the underlying physical commodity, which could, in certain circumstances, result in a reduction of our liquidity.
 
As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain extreme circumstances might actually increase the volatility of our cash flows. In addition, hedging activities may result in substantial losses. Such losses could occur under various circumstances, such as when a counterparty fails to perform its obligations under the applicable hedging arrangement, the hedging arrangement is imperfect or ineffective, or our hedging policies and procedures are not properly followed or otherwise do not work as planned. The steps we take to monitor our hedging activities may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.
 
Due to the enactment of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank), the hedges we execute are undertaken in a highly regulated market. At this time, significant components of the Dodd-Frank regulatory regime are subject to rulemaking by the Commodity Futures Trading Commission and other regulators. Issues such as our continued ability to pledge non-cash collateral could affect the cost and structure of our hedging program. While we expect these issues to be resolved during the first two quarters of 2013, we cannot be certain when final rules will be issued. Until final rules are issued, we cannot predict the impact to our hedging activities. For related discussion, see the risk factor below regarding Dodd-Frank.
 
We have significant indebtedness under our revolving credit facility and our senior notes, which may limit our flexibility in obtaining additional financing and in pursuing other business opportunities. In addition, we may incur substantial debt in the future to enable us to maintain or increase our reserve and production levels and to otherwise pursue our business plan. This debt may restrict our ability to make distributions.
 

34


As of December 31, 2012, we had $608.5 million outstanding under our senior secured credit facility, leaving approximately $192.5 million of available borrowing capacity as of that date,  and $544.6 million outstanding under our senior notes, net of unamortized discount. Our level of outstanding debt could have important consequences to us, including the following:
 
our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms; 
we will need a portion of our cash flow to make interest payments on our debt, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders; 
our debt level will make us more vulnerable to competitive pressures or a downturn in our business or the economy generally; and 
our debt level may limit our flexibility in responding to changing business and economic conditions.
 
Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. In addition, our ability to service debt under our credit facility will depend on market interest rates, since we anticipate that the interest rates applicable to our borrowings will fluctuate with movements in interest rate markets. If our operating results are not sufficient to service our current or future indebtedness or comply with our financial covenants under our existing credit facility or senior notes, we will be forced to take actions such as eliminating, reducing or further reducing distributions, reducing or delaying our business activities and expenses, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt, or seeking additional equity capital. We may not be able to affect any of these actions on satisfactory terms, or at all.
  
Decreases in commodity prices could result in decreases in the borrowing base under our revolving credit facility, which could materially and adversely affect our operations and financial condition.
Availability under our revolving credit facility is subject to a borrowing base comprised of two components: the upstream component and the midstream component. The upstream component of the borrowing base is determined semi-annually as an amount equal to the loan value of our proved oil and gas reserves. The midstream component of the borrowing base is determined quarterly as an amount equal to the lesser of (i) 55% of the total borrowing base (subject to increase for certain periods following certain material acquisitions up to 60% of the total borrowing base) and (ii) 3.75 times Consolidated EBITDA attributable to our midstream assets for the trailing four fiscal quarters.
As a result, a reduction in the value of our proved oil and gas reserves due to decreases in commodity prices could result in a reduction in the upstream component of our borrowing base. Moreover, because the midstream component of our borrowing base is limited to 55% of the total borrowing base, we have limited ability to offset any reductions in our upstream borrowing base with increases in our midstream borrowing base. If the amount outstanding under our revolving credit facility at any time exceeds the borrowing base at such time, we may be required to repay a portion of our outstanding borrowings. If such an event were to occur, it could materially and adversely affect our operations and financial condition.
Covenants in our credit facility and the indenture governing our senior notes may limit our ability to make distributions, enter into certain types of acquisitions or engage in other business transactions.
 
Our credit facility and the indenture governing our senior notes contain covenants limiting our ability to make distributions, incur indebtedness, grant liens, make acquisitions, investments or dispositions and engage in transactions with affiliates. Furthermore, our credit facility and the indenture governing our senior notes contain covenants requiring us to maintain certain financial ratios and tests. Any subsequent replacement, restatement or amendment of our credit facility and the indenture governing our senior notes or any new indebtedness could impose similar or greater restrictions.
 
We may not be able to execute our business strategy if we encounter illiquid capital and commercial credit markets.
 
One component of our business strategy contemplates pursuing opportunities to acquire assets where we believe growth opportunities are attractive and our business strategies could be applied. We regularly consider and enter into discussions regarding strategic transactions that we believe will present opportunities to pursue our growth strategy.
 
We will require substantial new capital to finance strategic acquisitions. Any limitations on our access to capital or commercial credit will impair our ability to execute this component of our growth strategy. If the cost of such capital or credit becomes too expensive, our ability to develop or acquire accretive assets will be limited. We may not be able to raise the necessary funds on satisfactory terms, if at all. The primary factors that influence our cost of capital include our units’ market

35


performance, conditions in the commercial credit, debt and equity markets and offering or borrowing costs such as interest rates or underwriting discounts.

Our operations require substantial capital expenditures, which will reduce our cash available for distribution. We may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a decline in our cash flows.
 
The oil and natural gas industry is capital intensive. We expect to continue to make substantial capital expenditures in our business for the maintenance, growth, construction and acquisition of midstream and upstream assets and oil and natural gas production and reserves. In 2013, our capital expenditure budget is expected to be approximately $208 million, excluding acquisitions. We intend to finance our future capital expenditures with cash flows from operations, borrowings under our credit facility and the issuance of debt and equity securities, when market conditions allow. The incurrence of debt will require that a portion of our cash flows from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. Our cash flows from operations and access to capital are subject to a number of variables, including:
 
volume throughput through our pipelines and processing facilities; 
the estimated quantities of our proved reserves; 
the amount of oil and natural gas produced from existing wells; 
the prices at which we sell our production or that of our midstream customers; 
the strike prices of our hedges; 
our operating and general and administrative expenses; and 
our ability to acquire, locate and produce new reserves.
 
If our revenues or the borrowing base under our credit facility decrease as a result of lower commodity prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels, or to pursue our growth strategy. Our credit facility and the indenture governing our senior notes may restrict our ability to obtain new financing. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations, which in turn could lead to a possible decline in our gathering and processing available capacity or in our natural gas and crude oil reserves and production. Even if we are successful in obtaining additional financing, the terms of such financing could limit our ability to pay distributions to our unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional partnership interests may result in significant unitholder dilution which could have a material adverse effect on our ability to pay distributions at the then-current distribution rate. Further, we may lose opportunities to acquire oil and natural gas properties and businesses.
 
Our industry is highly competitive, and increased competitive pressure or loss of key customers could adversely affect our business and operating results.
 
We compete with similar enterprises in our respective areas of operation. Some of our competitors are large oil and natural gas companies that have greater financial resources and access to supplies of oil, natural gas and NGLs than we do.
 
In our Midstream Business, we rely on certain natural gas producer customers for a significant portion of our natural gas and NGL supply. The number and relative significance of gas suppliers can change for a number of reasons, including the relative success of the producers’ drilling programs, additions or cancellations of gathering and processing agreements, and the acquisition of new systems. Additionally, some of our competitors may expand or construct gathering, processing and transportation systems or may develop their own gathering, processing and transportation systems in lieu of using ours. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors and our customers. Unless we are able to acquire comparable volumes from other sources, all of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions.
 
In our Upstream Business, our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only drill for and produce oil and natural gas, but also conduct refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for oil and natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, these companies may have a greater ability to continue drilling activities during periods of low oil and natural gas prices, to contract for drilling equipment, to secure trained personnel and to absorb the

36


burden of present and future federal, state, local and other laws and regulations. The oil and natural gas industry has periodically experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation activities and has caused significant price increases. If a significant customer of ours reduces the volume of its purchases from us, we could experience a temporary interruption in sales of, or lower prices for, our production.  As a result our revenues and cash available for distribution could decline which may adversely affect our ability to make cash distributions to our unitholders.
 
In both the Midstream and Upstream Businesses there is significant competition for experienced personnel, particularly in the engineering, accounting and financial reporting, tax and land departments. In addition, competition is strong for attractive midstream assets, oil and natural gas producing properties, oil and natural gas companies and undeveloped leases and drilling rights. We may often be outbid by competitors in our attempts to acquire personnel, assets, properties or companies. Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations.

If we do not make acquisitions on economically acceptable terms, our future growth will be limited.
 
Our ability to grow our business depends, in part, on our ability to make acquisitions that are accretive to our cash available for distributions on a per unit basis. If we are unable to make these accretive acquisitions because we are: (i) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (ii) unable to obtain financing for these acquisitions on economically acceptable terms, or (iii) outbid by competitors, then our future growth and ability to increase distributions will be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations per unit because of unforeseen circumstances.
 
All acquisitions involve potential risks, including, among other things:
 
mistaken assumptions about future prices, volumes, revenues and costs of oil and natural gas, including synergies and estimates of the oil and natural gas reserves attributable to a property we acquire; 
inefficiencies and complexities that can arise because of unfamiliarity with new assets, operations and the businesses associated with them, including their markets and geographic service areas; 
the assumption of unknown liabilities for which we are not indemnified or for which our indemnity is inadequate; 
mistaken assumptions about the overall costs of equity or debt; 
decrease in our liquidity as a result of our using a significant portion of our available cash or borrowing capacity to finance the acquisition; 
increases in our interest expense or financial leverage if we incur additional debt to finance the acquisition; and 
customer or key employee losses at the acquired businesses.
 
If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and our limited partners will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider.
 
Our ability to derive benefits from our acquisitions will depend on our ability to successfully integrate the acquired operations.
 
Achieving the anticipated benefits from acquisitions depends in part upon whether we are able to successfully integrate the assets or businesses of these acquisitions, in an efficient and effective manner. The difficulties combining businesses or assets potentially will include, among other things:
 
geographically separated organizations and possible differences in corporate cultures and management philosophies; 
significant demands on management resources, which may distract management's attention from day-to-day business; and 
differences in the disclosure systems, accounting systems, and internal controls and procedures (including accounting controls and internal controls and procedures we are required to maintain under the Sarbanes-Oxley Act of 2002) of the two companies, which may interfere with our ability to make timely and accurate public disclosure.
  
Any inability to realize the potential benefits of the acquisition, as well as any delays in integration, could have an adverse effect upon the revenues, level of expenses and operating results of the company, after the acquisitions, which may affect the value of our common units after the acquisition.
 

37


Failure of the natural gas, NGLs, condensate or other products produced at our plants or shipped on our pipelines to meet the specifications of interconnecting pipelines or markets could result in curtailments by the pipelines or markets.
 
The markets and pipelines to which we deliver natural gas, NGLs, condensate or other products establish specifications for the products they are willing to accept.  These specifications include requirements such as hydrocarbon dewpoint, compositions, temperature, and foreign content (such as water, sulfur, carbon dioxide, and hydrogen sulfide), and these specifications can vary by product, pipeline or markets.  If the total mix of a product that we deliver to a pipeline or market fails to meet the applicable product quality specifications, the pipeline or market may refuse to accept all or a part of the products scheduled for delivery to it or may invoice us for the costs to handle or damages from receiving the out-of-specification products. In those circumstances, we may be required to find alternative markets for that product or to shut-in the producers of the non-conforming natural gas that is causing the products to be out of specification, potentially reducing our through-put volumes or revenues.

Our businesses depend in part on gathering, transportation and processing facilities. Any limitation in the availability of, or our access to, those facilities would interfere with our ability to market the oil, natural gas and NGLs we produce, and could reduce our cash available for distribution and adversely impact expected increases in oil, natural gas and NGL production from our drilling program.
 
The marketability of our oil, gas and NGL production depends in part on the accessibility, availability, proximity and capacity of gathering, processing and pipeline systems. The amount of oil, natural gas and NGLs that can be produced and sold is subject to limitation in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering, processing or transportation system, weather, or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. In addition, some of our wells may be drilled in locations that are not serviced by gathering, processing and transportation facilities, or the gathering and transportation pipelines in the area may not have sufficient capacity to transport additional production. As a result, we may not be able to sell the oil, gas and NGL production from these wells until the necessary gathering, processing and transportation facilities are constructed. Any significant curtailment in gathering system or pipeline capacity, or significant delay in the construction of necessary gathering, processing and transportation facilities, would interfere with our ability to market the oil, gas and NGLs we produce, and could reduce our cash available for distribution and adversely impact expected increases in oil and gas production from our drilling program.  Our access to transportation options can also be affected by U.S. federal and state regulations of oil and natural gas production and transportation and other general economic conditions beyond our control. In addition, sulfur is a by-product associated with substantially all of the natural gas production in our upstream operations in Alabama.   If we were unable to sell the sulfur we produce, we may be forced to store it or curtail our oil and gas production.

If third-party pipelines and other facilities interconnected to our midstream systems become unavailable to transport or produce natural gas and NGLs, our revenues and cash available for distribution could be adversely affected.
 
We depend upon third-party pipelines, natural gas gathering systems and other facilities that provide delivery options to and from our pipelines and facilities for the benefit of our midstream customers. Since we do not own or operate any of these pipelines or other facilities, their continuing operation is not within our control. If any of these third-party pipelines and other facilities become unavailable or limited in their ability to transport or produce natural gas and NGLs, our revenues and cash available for distribution could be adversely affected.

Inclement weather, unforeseen events or events of force majeure may limit our ability to operate our business and could adversely affect our operating results.

The weather, unforeseen events or events of force majeure (such as acts of nature or acts of terrorism) in the areas in which we operate can cause disruptions and, in some cases, suspension of our operations (whether directly or by virtue of disrupting or suspending operations of those upon whom we rely in our operations). For example, unseasonably wet or dry weather, extended periods of below freezing weather, hurricanes, lightning strikes, tornadoes, electrical outages, domestic attacks or threats of violence may cause disruptions or suspensions of our operations, which could result in our inability to cause physical delivery of commodities guaranteed under contract or require us to purchase third-party volumes at significantly higher prices to satisfy our delivery obligations. Disruption or suspensions of our operations could adversely affect our operating results.

Our construction of new assets is subject to regulatory, environmental, political, legal and economic risks, and therefore, may not increase revenue as expected; this could adversely affect our results of operations and financial condition.

38


 
One of the ways we intend to grow our business is through the construction of new midstream assets. The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. If we undertake these projects, they may not be completed on schedule or at the budgeted cost, or at all.
 
Our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we expand a pipeline, the construction expenditures may occur over an extended period of time, yet we will not receive any material increases in revenues until the project is completed. Also, we may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. To the extent we rely on estimates of future production in our decision to construct additions to our systems, such estimates may prove to be inaccurate. As a result, new or expanded facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition.
 
The construction of additions to our existing gathering and transportation assets may require us to obtain new rights-of-way prior to constructing new pipelines. We may be unable to obtain such rights-of-way to connect new natural gas supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, our cash flows could be adversely affected.

Our business involves many hazards and operational risks, some of which may not be partially or fully insured or insurable. If a significant accident or event occurs that is not fully insured or interrupts normal operations, our operations and financial results could be adversely affected.
 
Our operations are subject to many hazards inherent in the drilling, producing, gathering, compressing, treating, processing and transporting of oil, natural gas and NGLs, including:
 
damage to production equipment, gathering equipment, pipelines and treating or processing plants, compression and related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters and acts of terrorism; 
inadvertent damage from construction, farm and utility equipment or acts of vandalism; 
leaks of natural gas, poisonous hydrogen sulfide gas, NGLs and other hydrocarbons or losses of natural gas or NGLs as a result of the malfunction of pipeline, equipment or facilities;
mishandling of fluids, including chemical additives that may be toxic;
surface spills or underground migration due to uncontrollable flows of oil, natural gas, formation water or well fluids; 
fires and explosions; and 
other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.
 
These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and attorney's fees and other expenses incurred in the prosecution or defense of litigation and may result in curtailment or suspension of our related operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations and ability to pay distributions to our unitholders.
 
As is customary in the industry, we maintain insurance against some but not all of these risks. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. We are not fully insured against all risks inherent to our business.  For example, we are not fully insured against all environmental accidents which may include toxic tort claims. If a significant accident or event occurs that is not fully insured, it could adversely affect our operations and financial condition. In addition, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased substantially, and could escalate further. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, we may be unable to recover from prior owners of our assets, pursuant to our indemnification rights, for potential environmental liabilities. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition, results of operations and ability to pay distributions to our unitholders.
 

39


Increases in interest rates could adversely impact our unit price and our ability to issue additional equity, to incur debt to make acquisitions or for other purposes or to make cash distributions at our intended levels.
 
Credit markets have experienced a prolonged period of low interest rates. Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity, to incur debt to make acquisitions or for other purposes or to make cash distributions at our intended levels.
 
Our and other operators’ drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors.
 
Drilling for oil and gas involves numerous risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. Our and other operators’ drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors, including:
 
unexpected drilling conditions; 
drilling, production or transportation facility or equipment failure or accidents;
mechanical difficulties, such as lost or stuck drilling or service tools;
abnormally pressured formations or rock compaction;  
increasing costs for or shortages or delays in the availability of drilling rigs, experienced personnel and other services and equipment; 
adverse weather conditions; 
compliance with environmental and governmental requirements; 
title problems;
unusual or unexpected geological formations; 
pipeline ruptures; 
fires, blowouts, craterings and explosions; 
mishandling of fluids, including chemical additives that may be toxic; and 
surface spills or underground migration due to uncontrollable flows of oil, natural gas, formation water or well fluids.
 
We do not provide midstream services to all of our upstream activities. Any curtailment to the gathering systems we use to deliver our oil and gas production for processing, storage or further delivery to end markets could require us to find alternative means to transport the oil and natural gas production from the underlying properties, which alternative means could require us to incur additional costs. Additionally, any delay in the drilling of new wells or significant increase in drilling costs could reduce our revenues. Any such curtailment, delay, cancellation, cost increase or revenue reduction may limit our ability to make cash distributions to our unitholders.

Due to our limited industry and geographic diversification in our midstream operations and in our upstream operated properties, adverse developments in our operations or operating areas would reduce our ability to make distributions to our unitholders.
 
All of our midstream assets are located in the Texas Panhandle, East and South Texas and Louisiana, and all of our upstream operated properties are located in Texas, Oklahoma, Alabama, Arkansas, and Mississippi. Due to our limited diversification in industry type and location, an adverse development in one of these businesses or operating areas would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets and operating areas.

Our estimated oil and natural gas reserve quantities and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or the underlying assumptions will materially affect the quantities and present value of our reserves.
 
Numerous uncertainties are inherent in estimating quantities of oil and natural gas reserves.  The process of estimating oil and natural gas reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, engineering and economic data for each reservoir. Reserve reports rely upon many assumptions, including future oil and natural gas prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the estimated timing of development expenditures may prove to be

40


inaccurate. Over time, we may make material changes to reserve estimates that reflect the actual results of drilling and production. Any significant change in our assumptions or actual performance of our wells could affect our estimates of reserves, the classifications of the reserves and our estimates of the future net cash flows associated with the reserves. In addition, since many of our wells are mature and have low production rates, changes in future production costs assumptions could have a significant effect on our proved reserve estimates.
 
The standardized measure of discounted future net cash flows of our estimated net proved reserves is not the same as the current market value of our estimated net proved reserves. We base the discounted future net cash flows from our estimated net proved reserves on average prices observed in the previous twelve months and on cost estimates we believe reflect the costs at the end of the period. Actual prices received for production and actual costs of such production will be different than these assumptions, perhaps materially.
 
The timing of both our production and our incurrence of expenses in connection with the development and production of our properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on actual interest rates and the risks associated with our firm in particular or the natural gas and oil industry in general. Any material inaccuracy in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves which could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

Our ability to manage and grow our business effectively may be adversely affected if we lose key management or operational personnel.
 
We depend on the continuing efforts of our key management and operational personnel. The departure of any of our key management or operational personnel could have a significant negative effect on our business, operating results, financial condition, and on our ability to compete effectively in the marketplace. Additionally, our ability to hire, train, and retain qualified personnel will continue to be important and will become more challenging as we grow and face more significant competition in the marketplace. Our ability to grow and perhaps even to continue our current level of service to our current customers will be adversely impacted if we are unable to successfully hire, train and retain these important personnel.

We may not successfully balance our purchases and sales of natural gas, which would increase our exposure to commodity price risks.
 
We purchase from producers and other parties a substantial amount of the natural gas that flows through our natural gas gathering, processing and transportation systems for resale to third parties, including natural gas pipelines, marketers and a reduced number of end-users. We may not be successful in balancing our purchases and sales. A producer or supplier could fail to deliver contracted volumes or deliver in excess of contracted volumes, or a purchaser could purchase less than contracted volumes. Any of these actions could cause our purchases and sales to be unbalanced. If our purchases and sales are unbalanced, we will face increased exposure to commodity price risks and could have increased volatility in our operating income and cash flows.

We have limited control over the activities on properties we do not operate, which includes a substantial number of the properties we acquired in the Mid-Continent Acquisition.

Devon Energy Production Co LP, Continental Resources, Inc., Cimarex Energy Co. and others operate some of the properties in which we have an interest, including the properties we acquired in the Mid-Continent Acquisition. We have less ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund with respect to them versus those fields in which we are the operator. The success and timing of development and exploitation activities on properties operated by others depend upon a number of factors that will be largely outside our control, including:

the operator's expertise and financial resources;
the timing and amount of their capital expenditures;
the rate of production of the reserves;
approval of other participants to drill wells and implement other work programs;
the availability of suitable drilling rigs, drilling equipment, production and transportation infrastructure and qualified operating personnel; and
selection of technology.


41


Our dependence on the operator and other working interest owners for these projects and our reduced influence or ability to control the operation and future development of these properties could materially adversely affect our business, results of operations, financial condition and ability to pay distributions to our unitholders.

We are exposed to the credit risk of our customers and other counterparties, and a general increase in the nonperformance by counterparties could have an adverse impact on our cash flows, results of operations and financial condition.
 

We are subject to risks of loss resulting from nonperformance by our customers and other counterparties, such as our lenders and other hedge counterparties. Any deterioration in the financial health of our customers and counterparties or any factors causing reduced access to capital for them may result in the reduction in their ability to pay or otherwise perform on their obligations to us. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. Any increase in the nonperformance by our counterparties, either as a result of recent changes in financial and economic conditions or otherwise, could have an adverse impact on our operating results and could adversely affect our liquidity.

We do not own all of the land on which our pipelines and facilities are located, so our operations could be disrupted by actions of the landowners.
 
We do not own all of the land on which our pipelines and facilities have been constructed, and we are therefore subject to the possibility of more onerous terms or increased costs to retain necessary land use if we do not have valid rights of way or if such rights of way lapse or terminate. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations and financial condition and our ability to make cash distributions.

Our commodity derivatives trading activities expose us to additional risks associated with selling and marketing products in energy markets.

In 2011, we began conducting commodity derivatives trading activities through our natural gas marketing subsidiary, Eagle Rock Gas Services, LLC. Our portfolio of derivative and other energy contracts may consist of contracts to buy and sell commodities that are settled by the delivery of the commodity or cash. If the values of these contracts change in a direction or manner that we do not anticipate or cannot manage, it could negatively affect our results of operations. In the past, certain marketing and trading companies have experienced severe financial problems due to price volatility in the energy commodity markets. In certain instances this volatility has caused companies to be unable to deliver energy commodities that they had guaranteed under contract. If such a delivery failure were to occur in one of our contracts, we might incur additional losses to the extent of amounts, if any, already paid to, or received from, counterparties. As a result, our business, results of operations, financial condition and ability to pay distributions to our unitholders may be adversely affected.

Risks Inherent in an Investment in Us
 
The amount of cash we have available for distribution to holders of our common units depends primarily on our cash flow and not solely on profitability.
 
The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

NGP controls a substantial portion of our common units and appoints three of our directors, and thus it could exert certain significant influence over us.
Currently, NGP beneficially owns 51,386,169 common units, representing over 35% of our outstanding common units. In addition, pursuant to our partnership agreement, NGP is entitled to appoint three of the nine members of our board of directors. As a result, NGP could exert certain significant influence over us. NGP may have interests that do not align with our interests and with the interests of our unitholders, which could have an adverse impact on our results of operations or cash available for distribution to unitholders. In addition, NGP's level of control may make any potential takeover bids more costly or difficult in the future.

Unitholders have less ability to influence management's decisions than holders of common stock in a corporation.

42


Unlike the holders of common stock in a corporation, unitholders have more limited voting rights on matters affecting our business, and therefore a more limited ability to influence management's decisions regarding our business. Our partnership agreement provides that our general partner may not withdraw and may not be removed at any time for any reason whatsoever. In addition, if unitholders are dissatisfied with the performance of our general partner, they only have the right to elect five of the nine directors.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.
 
Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.
 
We expect that we will distribute all of our available cash to our unitholders. As a result, we expect that we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.
 
In addition, because we distribute all of our available cash, our growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement, our credit facility or the indenture governing our senior notes on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.

If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.
 
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to continue to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.

Our partnership agreement contains provisions that modify and limit our general partner's fiduciary duties to our unitholders.
 
Our partnership agreement contains provisions that modify and limit our general partner's fiduciary duties to our unitholders. Our partnership agreement also contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement:
 
provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action in good faith, and our general partner will not be subject to any other or different standard imposed by our partnership agreement, Delaware law or any other law, rule or regulation or at equity;
 

43


provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, and our partnership agreement specifies that the satisfaction of this standard requires that our general partner must believe that the decision is in the best interests of our partnership;
 
provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
 
provides that our general partner will not be in breach of its obligations under the partnership agreement or its fiduciary duties to us or our unitholders if the resolution of a conflict is:
 
approved by the conflicts committee of our general partner, although our general partner is not obligated to seek such approval; 
approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates; 
on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or 
fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
 
In connection with a situation involving a conflict of interest, any determination by our general partner involving the resolution of the conflict of interest must be made in good faith, provided that, if our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

We have the right to borrow to make distributions. Repayment of these borrowings will decrease cash available for future distributions, and covenants in our credit facility may restrict our ability to make distributions.
 
Our partnership agreement allows us to borrow to make distributions. We may borrow under our credit facility to make distributions. The primary purpose of these borrowings would be to mitigate the effects of short term fluctuation in our cash flow that would otherwise cause volatility in our quarter to quarter distributions.
 
The terms of our credit facility may restrict our ability to pay distributions if we do not satisfy the financial and other covenants in the facility.
 
We may issue additional units without limited partner approval, which would dilute ownership interests.
 
Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
 
our unitholders’ proportionate ownership interest in us will decrease; 
the amount of cash available for distribution on each unit may decrease; 
the ratio of taxable income to distributions may increase; 
the relative voting strength of each previously outstanding unit may be diminished; and 
the market price of the common units may decline.
 
Our management team, directors and NGP may sell common units in the public markets, which sales could have an adverse impact on the trading price of the common units.
 
Currently, our management team, directors and NGP (including through their interests in Montierra) beneficially own an aggregate of 53,826,301 common units, including 1,228,762 common units which are still subject to a vesting requirement. The resale of any of these common units in the public markets could have an adverse impact on the price of the common units or on any trading market that may develop.

44


 
Liability of a limited partner may not be limited if a court finds that unitholder action constitutes control of our business.
 
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. Limited partners could be liable for any and all of our obligations as a general partner if:
 
a court or government agency determined that we were conducting business in a state but had not complied with that particular state's partnership statute; or
 
the right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.
 
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
 
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

Our simplified capital structure (i.e. only one common class of equity outstanding) could result in slower distribution growth and less certainty of minimum distributions.

Unlike many publicly-traded partnerships, we do not have incentive distribution rights. Incentive distribution rights generally entitle the general partner of a publicly-traded partnership to increasing percentages of the cash distributed by the partnership in excess of a specified level and are designed to encourage the general partner and its affiliates to grow distributions of the partnership through, among other things, the sale or contribution of additional assets to the partnership on an accretive basis. Since we no longer have an independently-controlled general partner with incentive distribution rights in us, we could have difficulty consummating accretive transactions at the same rate as, and see slower distribution growth than, other publicly-traded partnerships.

Unlike many publicly-traded partnerships, we also do not have subordinated units. Subordinated units generally are not entitled to receive any distributions until the common units have received a specified minimum quarterly distribution plus any arrearages from prior quarters. The practical effect of the existence of subordinated units in lieu of common units is to increase the likelihood that a specified minimum quarterly distribution will be distributed on the outstanding common units. Accordingly, there may be more risk that we will not distribute a specified minimum amount each quarter (either present or in arrears) on our common units than there would exist if a portion of our outstanding units were subordinated units rather than common units.

Risks Related to Governmental Regulation

We are subject to compliance with stringent environmental laws and regulations that may expose us to significant costs and liabilities, and future regulations may be more stringent. 

Our operations are subject to stringent and complex federal, state and local environmental laws and regulations. These laws and regulations may impose numerous obligations on our operations including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to limit or prevent releases of materials from our pipelines and facilities, and the imposition of substantial liabilities for pollution resulting from our operations. Failure or delay in obtaining regulatory approvals or drilling permits by us or our operators could have a material adverse effect on our ability to develop our properties, and receipt of drilling permits with onerous conditions could increase our compliance costs. In addition, regulations regarding conservation practices and the spacing, and density of wellbores may limit the quantity of oil and natural gas that may be produced and sold.

45


 
Numerous governmental authorities, such as the federal Environmental Protection Agency ("EPA") and analogous state agencies in which states we operate have the power to enforce compliance with these laws and regulations, oftentimes requiring difficult and costly actions. Failure to comply may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, assessment of monetary penalties and the issuance of injunctions limiting or preventing some or all of our operations. Certain environmental statutes and analogous state laws impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed of or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.
 
There is risk of incurring significant environmental costs and liabilities in connection with our operations as a result of our handling of petroleum hydrocarbons and wastes; operation of our wells, gathering systems and other facilities; air emissions and water discharges related to our operations and historical industry operations and waste disposal practices. Most of our midstream assets have been used for midstream activities for a number of years, oftentimes by third parties, whose treatment and disposal or release of petroleum hydrocarbons or wastes was not under our control. Private parties, including the owners of properties through which our gathering systems pass and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. We may not be able to recover some or any of these costs from insurance. See Part I, Item 1. Business—Regulation of Our Operations.

Changes in environmental laws and regulations occur frequently and such laws and regulations tend to become more stringent over time. Stricter laws, regulations or enforcement policies could significantly increase our compliance costs and have a material adverse effect on our operations or financial position. For example, in response to the April 2010 Macondo well incident the Bureau of Ocean Energy Management (“BOEM”) and the Bureau of Safety and Environmental Enforcement (“BSEE”) and the Office of Natural Resource Revenue ("ONRR"), in addition to their regulatory predecessors, adopted a series of regulatory initiatives that impose a variety of new safety and operating measures on oil and natural gas exploration and production operators in federal waters in the U.S. Gulf of Mexico that are intended to help prevent a similar incident in the future. Additional proposed changes in laws, regulations, guidance and policy could affect exploration and production operators in federal waters of the U.S. Gulf of Mexico and, in turn, adversely affect our midstream business that relies, in part, on the receipt of natural gas from such operators.

In addition, on August 16, 2012, the EPA published final rules that establish new air emission control requirements for natural gas and NGL production, processing and transportation activities, including New Source Performance Standards (NSPS) to address emissions of sulfur dioxide and volatile organic compounds, and National Emission Standards for Hazardous Air Pollutants (NESHAPS) to address hazardous air pollutants frequently associated with gas production and processing activities. Among other things, these final rules require the reduction of volatile organic compound emissions from natural gas wells through the use of reduced emission completions or “green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015. In addition, gas wells are required to use completion combustion device equipment (i.e., flaring) by October 15, 2012 if emissions cannot be directed to a gathering line. The new NSPS rule also requires the control of VOC emissions from new/modified tanks associated with oil and gas production and gathering and processing activities that will increase the costs associated with growth and maintenance. Further, the final rules under NESHAPS include maximum achievable control technology (MACT) standards for “small” glycol dehydrators that are located at major sources of hazardous air pollutants and modifications to the leak detection standards for valves. We are currently evaluating the impact of these final rules on our business. Compliance with these requirements, especially the imposition of these green completion requirements, may require modifications to certain of our operations, including the installation of new equipment to control emissions at the well site that could increase our costs or reduce our production, which could have a material adverse effect on our results of operations and cash flows.


We may incur significant costs and liabilities resulting from safety and compliance-related regulations.

Our gathering operations may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. For example, Louisiana's Pipeline Operations Section of the Department of Natural Resources’ Office of Conservation is generally responsible for regulating gathering facilities in Louisiana, and has authority to review and authorize the construction, acquisition, abandonment and interconnection of physical pipeline facilities and may implement new regulations in the future. Historically, apart from pipeline safety, it has not acted to exercise this jurisdiction respecting gathering facilities. We cannot predict what effect, if any,

46


such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Additionally, we are required to comply with common purchaser statutes which generally require gatherers to purchase without undue discrimination as to source of supply or producer. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. These statutes restrict our right as an owner of gathering facilities to decide with whom we contract to purchase or gather oil or natural gas. Federal law leaves any economic regulation of natural gas gathering to the states. The states in which we operate have adopted complaint-based regulation of oil and natural gas gathering activities, which allows oil and natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to oil and natural gas gathering access and rate discrimination. Other state regulations may not directly regulate our business, but may nonetheless affect the availability of natural gas for purchase, processing and sale; for example, state regulation of production rates and maximum daily production allowable from gas wells.  Although our proprietary gathering lines are currently subject to limited state regulation, there is a risk that state laws will be changed, and this may give producers a stronger basis to challenge the proprietary status of a line, or the rates, terms and conditions of a gathering line providing gathering service. Please see Part I, Item 1. Business—Regulation of Our Operations.

The majority of our gathering systems in Texas have been deemed non-utilities by the TRRC, with the exception being our Turkey Creek gathering system, which is regulated as a utility by the TRRC. Our Hesco Pipeline Company, LLC and the East Texas segment of our DeSoto Pipeline are also regulated by the TRRC. The TRRC has authority over the rates, terms and conditions of service for our DeSoto Pipeline's intrastate transportation activities. Under Texas law, non-utilities are not subject to rate regulation by the TRRC. Should the status of these non-utility facilities change, they would become subject to rate regulation by the TRRC, which could adversely affect the rates that our facilities are allowed to charge their customers.  Texas also administers federal pipeline safety standards under the Pipeline Safety Act of 1968. The non-jurisdictional gathering exemption under the Natural Gas Pipeline Safety Act of 1968 presently exempts most of our gathering facilities from jurisdiction under that statute. The “rural gathering exemption,” however, may be restricted in the future. As a result of recent pipeline incidents in other parts of the country, Congress and the Department of Transportation have passed or are considering imposing more stringent pipeline safety requirements. Costs associated with complying with and qualifying our facilities under these and other regulations could be material and have an adverse effect on us, our financial condition, and our results of operations.

We may incur significant costs and liabilities as a result of pipeline integrity management program testing and any related pipeline repair, or preventative or remedial measures, as well as more stringent pipeline safety standards.

The DOT has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines located where a leak or rupture could do the most harm in "high consequence areas." The regulations require operators to:
 
perform ongoing assessments of pipeline integrity; 
identify and characterize applicable threats to pipeline segments that could impact a high consequence area; 
improve data collection, integration and analysis; 
repair and remediate the pipeline as necessary; and 
implement preventive and mitigating actions.
 
We currently estimate that we may incur costs of $1.1 million in 2013 for specific plant and pipeline integrity management program testing along certain segments of our pipeline, as required by existing DOT and OSHA regulations to be completed this year. This estimate does not include the costs, if any, for repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which could be substantial.

We may incur significant expenses if anomalous pipeline conditions are discovered or due to the implementation of more stringent pipeline safety standards as a result of new or amended legislation. For example, in January 2012, President Obama signed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“Pipeline Safety Act”), which requires increased safety measures for gas and hazardous liquids transportation pipelines. Among other things, the Pipeline Safety Act directs the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, and leak detection system installation. The Pipeline Safety Act also directs owners and operators of interstate and intrastate gas transmission pipelines to verify their records confirming the maximum allowable pressure of pipelines in certain class locations and high consequence areas, requires promulgation of regulations for conducting tests to confirm the material strength of pipe operating above 30% of specified minimum yield strength in high consequence areas, and increases the maximum penalty for violation of pipeline

47


safety regulations from $1 million to $2 million. PHMSA is also considering changes to its natural gas transmission pipeline regulations to, among other things, expand the scope of “high consequence areas,” strengthen integrity management requirements applicable to existing operators; strengthen or expand non-integrity pipeline management standards relating to such matters as valve spacing, automatic or remotely-controlled valves, corrosion protection, and gathering lines; and add new regulations to govern the safety of underground natural gas storage facilities including underground storage caverns and injection or withdrawal well piping that are not regulated today. We cannot predict the final outcome of these legislative or regulatory efforts or the precise impact that compliance with any resulting new requirements may have on our business.

The adoption of derivatives legislation by the United States Congress and its implementation by the Commodity Futures Trading Commission and SEC could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.
In 2010, Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act ("Dodd-Frank"), which among other things, establishes a comprehensive framework for the regulation of derivatives, or swaps. The SEC, which has jurisdiction over security-based swaps, and the Commodity Futures Trading Commission (the "CFTC"), which has jurisdiction over swaps, have issued regulations to implement this new statutory regime. Once fully implemented, and subject to certain exemptions that may be available to us, entities such as Eagle Rock that enter into swaps will be subject to, among other things, swap recordkeeping and reporting requirements; clearing, trade execution and margin requirements (e.g., posting of collateral). Our swap counterparties may be subject to even greater regulatory requirements and may be subject to regulated capital requirements. Dodd-Frank also provides for the imposition of position limits for referenced futures contracts, including with respect to certain energy commodities, and economically equivalent futures, options and swaps.  The CFTC promulgated regulations imposing position limits, which were vacated by a federal court in September 2012.  The CFTC is currently appealing that decision and could in the future re-promulgate position limits rules in a manner that attempts to address the defects identified by the court.
The legislation and related regulations could increase our cost of compliance, increase the cost and alter the terms of derivatives transactions, and adversely impact the number and creditworthiness of available swap counterparties. All of this could impact our available liquidity, require us to divert funds away from our core business and reduce our ability to hedge and otherwise manage our financial and commercial risks related to commodity price fluctuations.

If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Any of these consequences could have a material, adverse effect on us, our financial condition, and our results of operations.

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.
 
FERC has developed tests for determining which facilities constitute gathering facilities exempt from Federal Energy Regulatory Commission (FERC) regulation under the Natural Gas Act of 1938 (NGA). From time to time, FERC may reconsider the elements of such tests. We cannot predict when and under what circumstances FERC may elect to re-examine activities that could fall within the scope of our business with respect to gathering.
 
We believe that, currently, the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline's status as a gatherer not subject to FERC jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, on-going litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC and the courts. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, and in some instances complaint-based rate regulation. Although our natural gas gathering and intrastate transportation operations are generally exempt from direct FERC regulation, FERC has jurisdiction over natural gas markets and intrastate pipelines engaged in interstate transportation services.  FERC’s policies and practices across the range of its oil and natural gas regulatory activities, such as its policies on open access transportation, ratemaking, price transparency, market manipulation, capacity release and market center promotion, indirectly affect intrastate markets. In recent years, FERC has pursued policies to increase competition, which could increase FERC's regulation over Eagle Rock DeSoto Pipeline.
 
Our Eagle Rock DeSoto Pipeline, L.P. (“DeSoto Pipeline”) transports gas in interstate commerce on its Central and North Texas Systems and is therefore subject to FERC regulation under Section 311 of the NGPA.  

48



Our Eagle Rock DeSoto Pipeline is subject to FERC regulation under Section 311 of the Natural Gas Policy Act, or NGPA. In October 2008, DeSoto Pipeline filed a request for FERC approval to continue to use DeSoto Pipeline's currently-effective rate for NGPA Section 311 service, which is based on a city-gate transportation rate approved by the TRRC as being fair and equitable and not in excess of a cost-based rate.  In March 2009, FERC approved a settlement authorizing DeSoto Pipeline to continue to charge the currently-effective rate for NGPA Section 311 service, subject to a requirement that on or before May 1, 2010, DeSoto Pipeline must either file a new application for rate approval with FERC or file an election to use its then-effective rates for intrastate city-gate transportation service on file with the TRRC.  If the latter, then DeSoto Pipeline was required to make a filing with the TRRC for a cost-based rate determination.  On September 14, 2010, the FERC granted an extension of time to May 1, 2012 for DeSoto Pipeline to file a new application for rate approval or to file the election. On April 23, 2012 DeSoto Pipeline filed an application with the TRRC for a cost-based review of the reasonableness of the currently-effective transportation rate to be used for NGPA Section 311 service, and on May 1, 2012, DeSoto Pipeline filed with the FERC a notice of its election to continue to use DeSoto Pipeline's rates for intrastate city-gate transportation service on file with the TRRC for NGPA Section 311 service. Action on both filings is pending.  Any failure on our part to comply with the rates approved by the FERC for Section 311 service, to comply with the terms and conditions of service established in our FERC-approved Statement of Operating Conditions, or to comply with applicable FERC regulations, the NGPA, or certain state laws and regulations could result in an alteration of the jurisdictional status of DeSoto Pipeline and the imposition of civil and/or criminal penalties.
 
A change in the regulations related to a state's use of eminent domain could inhibit our ability to secure rights-of-way for future pipeline construction projects.

Certain states where we operate are considering the adoption of laws and regulations that would limit or eliminate a state's ability to exercise eminent domain over private property.  This, in turn, could make it more difficult or costly for us to secure rights-of-way for future pipeline construction and other projects. Further, states may amend their procedures for certain entities within the state to use eminent domain. For example, in response to a recent decision from the Texas Supreme Court, the TRRC may alter the process for a pipeline company to claim common carrier status under Texas law.

Climate change laws or regulations restricting emissions of "greenhouse gases" could result in increased operating costs and a decreased demand for oil and natural gas that we produce or process.

In response to findings that emissions of carbon dioxide, methane, and other greenhouse gases, or “GHGs,” present an endangerment to public health and the environment because emissions of such gases are contributing to the warming of the earth's atmosphere and other climate changes, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that would require a reduction in emissions of GHGs from motor vehicles and also may trigger construction and operating permit review for GHG emissions from certain stationary sources. The EPA has asserted that the final motor vehicle GHG emission standards triggered Prevention of Significant Deterioration (“PSD”) and Title V permit requirements for stationary sources, commencing when the motor vehicle standards took effect on January 2, 2011. The EPA has published its final rule to address the permitting of GHG emissions from stationary sources under the PSD and Title V permitting programs, pursuant to which these permitting programs have been “tailored” to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. It is widely expected that facilities required to obtain PSD permits for their GHG emissions also will be required to reduce those emissions according to “best available control technology” standards for GHG that have yet to be fully developed. With regards to the monitoring and reporting of GHGs, on November 30, 2010, the EPA published a final rule expanding its existing GHG emissions reporting rule published in October 2009 to include onshore and offshore oil and natural gas production and onshore oil and natural gas processing, transmission, storage, and distribution activities. Facilities containing petroleum and natural gas systems that emit 25,000 metric tons or more of CO2 equivalent per year are now required to report annual GHG emissions to EPA, with the first report for emissions occurring in 2011 due on September 28, 2012. These EPA rulemakings could adversely affect our operations by limiting drilling opportunities, restricting or delaying our ability to obtain air permits for new or modified facilities, or imposing materially increased costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances, or comply with new regulatory or reporting requirements.
In addition, both houses of Congress have actively considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. These allowances would be expected to escalate significantly in cost over time. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from our equipment and

49


operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas we produce or the oil, natural gas and NGLs we gather and process or fractionate. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our upstream and midstream operations.
Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. We routinely utilize hydraulic fracturing techniques in many of our oil and natural gas well drilling and completion programs. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, the EPA has asserted federal regulatory authority over hydraulic fracturing involving fluids that contain diesel fuel under the Safe Drinking Water Act's Underground Injection Control Program and has released draft permitting guidance for hydraulic fracturing operations that use diesel fuel in fracturing fluids in those states where EPA is the permitting authority. EPA accepted comments on the draft guidance in 2012, but has not yet finalized the permitting guidance. In addition, legislation has been introduced before Congress that would provide for federal regulation of hydraulic fracturing and would require disclosure of the chemicals used in the fracturing process. Moreover, on November 23, 2011, the EPA announced that it was granting in part a petition to initiate a rulemaking under the Toxic Substances Control Act, relating to chemical substances and mixtures used in the hydraulic fracturing process. Further, on May 4, 2012, the Department of the Interior's Bureau of Land Management (“BLM”) issued a proposed rule to regulate hydraulic fracturing on public and Indian land. The rule would require companies to publicly disclose the chemicals used in hydraulic fracturing operations to the BLM after fracturing operations have been completed and includes provisions addressing well-bore integrity and flowback water management plans.
Certain states where we operate, including Texas have adopted, and other states are considering adopting, regulations and legislation that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations. For example, Texas adopted a law in June 2011 requiring disclosure to the Texas Railroad Commission ("TRRC") and the public of certain information regarding the components used in the hydraulic-fracturing process. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells.
We use a significant amount of water in our hydraulic fracturing operations. Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our exploration and production operations, could adversely impact our operations. Moreover, new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas. For example, in October 2011, the EPA announced that it plans to develop standards for disposal of wastewater produced from shale gas operations to publicly owned treatment works (POTWs), which will be proposed in 2014. The regulations will be developed under the EPA's Effluent Guidelines Program under the authority of the Clean Water Act. Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted, all of which could have an adverse affect on our operations and financial condition.
A number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The EPA is conducting a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. The Agency released a progress report outlining work currently underway on December 21, 2012 and is expected to release results of the study in 2014. These on-going or proposed studies, depending on their course and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act, the Toxic Substance Control Act, and/or other regulatory mechanisms. President Obama created the Interagency Working Group on Unconventional Natural Gas and Oil by Executive Order on April 13, 2012, which is charged with coordinating and aligning federal agency research and scientific studies on unconventional natural gas and oil resources.
If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing

50


becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, our fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.
Certain of our properties, including some of our operations in Oklahoma, are located on Native American tribal lands and are subject to various federal and tribal approvals and regulations, which may increase our costs and delay or prevent our efforts to conduct planned operations.

Various federal agencies within the U.S. Department of the Interior, particularly the Bureau of Indian Affairs, Bureau of Land Management and the Office of Natural Resources Revenue, along with each Native American tribe, promulgate and enforce regulations pertaining to gas and oil operations on Native American tribal lands. These regulations and approval requirements relate to such matters as lease provisions, drilling and production requirements, environmental standards and royalty considerations. In addition, each Native American tribe is a sovereign nation having the right to enforce laws and regulations and to grant approvals independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees, requirements to employ Native American tribal members and other conditions that apply to lessees, operators and contractors conducting operations on Native American tribal lands. Lessees and operators conducting operations on tribal lands are generally subject to the Native American tribal court system. In addition, if our relationships with any of the relevant Native American tribes were to deteriorate, we could face significant risks to our ability to continue the projected development of our leases on Native American tribal lands. One or more of these factors may increase our costs of doing business on Native American tribal lands and impact the viability of, or prevent or delay our ability to conduct, our natural gas or oil development and production operations on such lands.

Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service ("IRS") were to treat us as a corporation for federal income tax purposes or if we become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution would be substantially reduced.

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. A publicly traded partnership such as us may be treated as a corporation for federal income tax purposes unless it satisfies a “qualifying income” requirement. Based on our current operations we believe that we satisfy the qualifying income requirement and will be treated as a partnership. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity. We have not requested, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other tax matter affecting us.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35% and would likely pay state income tax at varying rates. Distributions would generally be taxed again as corporate dividends, and no income, gains, losses or deductions would flow through to the limited partners. Because a tax would be imposed upon us as a corporation, our cash available for distributions would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. We are, for example, subject to an entity level tax on the portion of our income that is generated in Texas. Imposition of such any such tax on us by any other state will reduce the cash available for distribution.

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. One such legislative proposal would eliminate the qualifying income exception to

51


the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS challenge will reduce our cash available for distribution.

We have not requested, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest by the IRS will be borne indirectly by our unitholders because the costs will reduce our cash available for distribution.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period would result in the termination of our partnership for federal income tax purposes.

We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest are counted only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders receiving two Schedules K-1) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. A deferral of depreciation deductions would result in increased taxable income or reduced taxable loss to certain unitholders, although the exact increase or reduction for each unitholder cannot be estimated at this time. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our consolidated financial statements or our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine in a timely manner that a termination occurred. The IRS has recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the tax year in which the technical termination occurs.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. Nonetheless, we allocate certain deductions for depreciation of capital additions based upon the date the underlying property is placed in service. The use of this proration method may not be permitted under existing Treasury Regulations. Recently, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose units are the subject of a securities loan (eg., a loan to a “short seller” to cover a short sale of units) may be considered as having disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.


52


Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan of their units are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

Unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if no cash distributions were received from us. Although not anticipated, our taxable income for a taxable year may include income without a corresponding receipt of cash by us, such as accrual of future income, original issue discount or cancellation of indebtedness income. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that result from that income.

Tax gain or loss on disposition of our common units could be more or less than expected.

If a unitholder sells common units, they will recognize a gain or loss equal to the difference between the amount realized and the tax basis in those common units. Prior distributions to a unitholder in excess of the total net taxable income allocated for a common unit, which decreased the unitholder’s tax basis in that common unit, will, in effect, become taxable income to the unitholder if the common unit is sold at a price greater than their tax basis in that common unit, even if the price received is less than the original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder's share of our non-recourse liabilities, if a unitholder sells units, the unitholder may incur a tax liability in excess of the amount of cash received from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as individual retirement accounts ("IRAs"), other retirement plans and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable tax rate, and non-U.S. persons will be required to file U.S. federal tax returns and pay tax on their share of our taxable income. Tax-exempt entities or non-U.S. persons should consult a tax advisor before investing in our common units.

We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Due to a number of factors, including our inability to match transferors and transferees of common units, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to the unitholders. It also could affect the timing of these tax benefits or the amount of gain from sales of common units and could have a negative impact on the value of our common units or result in audit adjustments to tax returns of our unitholders.

Unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our common units.

In addition to federal income taxes, a unitholder will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property, now or in the future, even if the unitholder does not live in any of those jurisdictions. A unitholder will likely be required to file state and local income tax returns and pay state and local income taxes in some or all

53


of these various jurisdictions. Further, a unitholder may be subject to penalties for failure to comply with those return filing requirements. We own assets and conduct business in several states. Many of these states currently impose a personal income tax. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is a unitholder's responsibility to file all United States federal, state and local tax returns.

Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.

The Fiscal Year 2013 Budget proposed by the President recommends elimination of certain key U.S. tax incentives
currently available to oil and natural gas exploration and production companies. Among others, the provisions include: elimination of the ability to fully deduct intangible drilling costs in the year incurred; repeal of the percentage depletion deduction for oil and gas properties; repeal of the manufacturing tax deduction for oil and gas companies; and an increase in the geological and geophysical amortization period for independent producers. It is unclear whether any such changes will be enacted or how soon any such changes would become effective. The passage of this legislation or any other similar changes in U.S. federal income tax laws could eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect the taxable income allocable to the unitholders.


54


Item 1B.
Unresolved Staff Comments.
 
Not Applicable.

Item 2.
Properties.
 
For a complete description of our significant properties, see Item 1. Business, which descriptions are incorporated into this item by this reference. Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of the property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that may have been subordinated to the right-of-way grants. We have obtained, where deemed necessary, license or permit agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, waterways, county or parish roads, municipal streets, railroad properties and state highways, as applicable. In some cases, property on which our pipeline was built was purchased in fee.
 
We believe that we have satisfactory title to our assets. Title to property may be subject to encumbrances and liens on substantially all of our assets as collateral support of our credit facility. We believe that none of these encumbrances will materially detract from the value of our properties or from our interest in these properties or will they materially interfere with their use in the operation of our business.
 
While we own our facilities, plants and gathering systems, in many cases we do not always own the land upon which the facilities, plants and gathering systems reside.  In cases where the land is leased (and not owned), we are ordinarily in long-term leases. From time to time, these long-term leases expire, and we are forced to negotiate new terms at market rates or exit the premises.  For more information, see our table of assets within Part I, Item 1 Business – Our Two Lines of Business and Our Five Reporting Segments – Midstream Business.

Item 3.
Legal Proceedings.
 
Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we are and may, at any given time, be a party to various legal proceedings and litigation arising in the ordinary course of business. However, we are not currently a party to any material litigation. We maintain insurance policies with insurers in amounts and with coverage and deductibles that we, with the advice of our insurance advisors and brokers, believe are reasonable and prudent. We cannot, however, give assurance that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices. We have been indemnified up to a certain dollar amount for two lawsuits. If there ultimately is a finding against us in these two indemnified cases, we would expect to make a claim against the indemnification up to limits of the indemnification.

In July 2012, the Alabama Department of Environmental Management (“ADEM”) notified one of our subsidiaries that ADEM had made a determination that alleged violations warrant enforcement action and determined that the alleged violations are appropriate for resolution by Consent Order and proposed the terms of a to-be-mutually agreed-upon Consent Order (“Proposed Consent Order”).  Such notification and the Proposed Consent Order were the result of findings made by ADEM relating to our subsidiary's Flomaton/Fanny Church Oil and Gas Production and Treating Facility. The Proposed Consent Order primarily related to allegations of emissions in excess of those allowed by the production rate.  Prior to receiving the Proposed Consent Order, we self-reported our emission rates and worked with ADEM to complete a series of quality improvement plans to address the causes of the alleged violations. On November 20, 2012, we executed a revised consent order that became effective on January 11, 2013. The order provides for a civil penalty of $80,000, which was paid on January 31, 2013.

Item 4.
Mine Safety Disclosures.

Not applicable.


55


PART II

Item 5.
Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.
 
Our common units are listed on the NASDAQ Global Select Market under the symbol “EROC.” The following table sets forth, for the periods indicated, the high and low sales prices of our common units as reported by the NASDAQ Global Select Market, as well as the amount of cash distributions declared per quarter.
Quarter Ended
 
High
 
Low
 
Distribution
per Unit
 
Record Date
 
Payment Date
March 31, 2011
 
$
10.35

 
$
8.61

 
$
0.1500

 
May 9, 2011
 
May 13, 2011
June 30, 2011
 
$
13.00

 
$
10.00

 
$
0.1875

 
August 5, 2011
 
August 12, 2011
September 30, 2011
 
$
11.48

 
$
8.50

 
$
0.2000

 
November 4, 2011
 
November 14, 2011
December 31, 2011
 
$
11.73

 
$
8.50

 
$
0.2100

 
February 7, 2012
 
February 14, 2012
 
 
 
 
 
 
 
 
 
 
 
March 31, 2012
 
$
11.81

 
$
9.74

 
$
0.2200

 
May 8, 2012
 
May 15, 2012
June 30, 2012
 
$
10.00

 
$
8.25

 
$
0.2200

 
August 7, 2012
 
August 14, 2012
September 30, 2012
 
$
9.81

 
$
8.55

 
$
0.2200

 
November 7, 2012
 
November 14, 2012
December 31, 2012
 
$
10.58

 
$
8.23

 
$
0.2200

 
February 7, 2013
 
February 14, 2013
 
The last reported sale price of our common units on the NASDAQ Global Select Market on February 25, 2013 was $8.98. As of that date, there were 129 holders of record and approximately 36,319 beneficial owners of our common units.
 
Cash Distribution Policy
 
We intend to distribute to our unitholders, on a quarterly basis, all of our available cash in the manner described below and as further described in our partnership agreement. Available cash generally means, for any quarter ending prior to liquidation, all cash on hand at the end of that quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the general partner to:
 
provide for the proper conduct of our business, including for future capital expenditures and credit and other needs;
comply with applicable law or any partnership debt instrument or other agreement; or
provide funds for distributions to unitholders and the general partner in respect of any one or more of the next four quarters. 

Under the terms of the agreements governing our debt, we are prohibited from declaring or paying any distribution to unitholders if a default or event of default (as defined in such agreements) exists. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Capital Requirements—Revolving Credit Facility.
  
Our Board of Directors will evaluate our distribution policy from time to time as conditions warrant in the future.

 Repurchases of Common Units
 
The following table sets forth certain information with respect to repurchases of common units during the three months ended December 31, 2012
Period
 
Total Number of Units Purchased
 
Average Price Paid Per Unit
 
Total Number of Units Purchased as Part of Publicly Announced Plans or Programs
 
Maximum Number (or Approximate Dollar Value) of Units that May Yet Be Purchased Under the Plan or Programs
October 1, 2012 to October 31, 2012
 

 

 

 

November 1, 2012 to November 30, 2012
 
254,190

 
$
8.69

 

 

December 1, 2012 to December 31, 2012
 

 

 

 

Total
 
254,190

 
$
8.69

 

 


56


 
All of the units were surrendered by employees to pay tax withholding in connection with the vesting of restricted common units.  As a result, we are deeming the surrenders to be “repurchases.”  These repurchases were not part of a publicly announced program to repurchase our common units, nor do we have a publicly announced program to repurchase our common units.

Sales of Unregistered Securities
 
We did not sell our equity securities in unregistered transactions during the twelve months ended December 31, 2012.

Common Unitholder Return Performance Presentation

The performance graph below compares the cumulative total unitholder return on our common units with the cumulative total returns on the Standard & Poor’s 500 Index (the “S&P 500 Index”) and the Alerian MLP Total Return Index (the “Alerian MLP”). The Alerian MLP is a composite of the 50 most prominent energy master limited partnerships and limited liability companies, as determined by Standard & Poor’s using a float-adjusted market capitalization methodology. The graph assumes an investment of $100 in our common units, and in each of the S&P 500 Index and the Alerian MLP on December 31, 2007 and reinvestment of all dividends and distributions. The results shown in the graph are based on historical data and should not be considered indicative of future performance.

______________________________
Note: The above graph compares the cumulative total unitholder return on our common units assuming rights associated with Eagle Rock's Rights Offering were distributed effective May 27, 2010, the record date for the Rights Offering, and then immediately sold with the proceeds re-invested in Eagle Rock common units on the same day.

The information contained in the Performance Graph above will not be deemed to be "soliciting material" or to be "filed" with the SEC, nor will such information be incorporated by reference into any future filings of the Securities Act of 1933, as amended (the "Securities Act"), or the Securities Exchange Act of 1934, as amended (the "Exchange Act"), except to the extent that we specifically incorporate it by reference into any such filing.


57


 Item 6.              Selected Financial Data.
 
The following table shows selected historical financial data from our audited consolidated financial statements for the five fiscal years from January 1, 2008 to December 31, 2012. The following financial data should be read in conjunction with our consolidated financial statements and the accompanying notes and "Management's Discussion and Analysis of Financial Condition and Results of Operations" included elsewhere in this report.
 
Our historical results of operations for the periods presented below may not be comparable either from period to period or going forward due to the following significant transactions:

On April 30, 2008, we completed the acquisition of Stanolind Oil and Gas Corp., which we refer to as the Stanolind Acquisition, for an aggregate purchase price of $81.9 million in cash.  As a result, financial results for the periods prior to May 2008 do not include the financial results from these assets.
 
On October 1, 2008, we completed the acquisition of Millennium Midstream Partners, L.P., which we refer to as the Millennium Acquisition, for approximately $183.6 million in cash and 3,362,280 (recorded value of $29.3 million) of our common units.  As a result, financial results for the periods prior to October 2008 do not include the financial results from these assets.

On May 24, 2010, we completed the sale of our Minerals Business (assets acquired from Montierra and MacLondon Acquisitions) to Black Stone for approximately $171.6 million, and resulted in a pre-tax gain in the disposition of approximately $37.7 million. We used these proceeds to pay down amounts outstanding under our senior secured credit facility. Operations related to these assets for 2010 have been recorded as part of discontinued operations. Financial information for these assets for 2008 and 2009 have been retrospectively adjusted to reflect as assets and liabilities held-for-sale and discontinued operations.

On June 30, 2010, we closed our Rights Offering, for which we received gross proceeds of $53.9 million. We used these proceeds to pay down amounts outstanding under our senior secured credit facility.

On October 19, 2010, we completed the acquisition of certain natural gas gathering systems and related facilities from Centerpoint Energy Field Services, Inc. for $27.0 million of cash. As a result, financial results for the periods prior to October 19, 2010 do not include the financial results from these assets.

On May 3, 2011, we completed the acquisition of all the outstanding membership interests of CC Energy II L.L.C. ("Crow Creek Energy") for total consideration of $563.7 million including 28.8 million common units valued at $336.1 million, debt assumed of $212.6 million and cash of approximately $15.0 million. As a result, financial results for the periods prior to May 3, 2011 do not include the financial results from these assets.

On May 20, 2011, we sold our Wildhorse Gathering System in our East Texas and Other Midstream Segment. The Wildhorse Gathering System was acquired as part of the Millennium Acquisition on October 1, 2008. Operations related to these assets for 2011 have been recorded as part of discontinued operations. Financial information for these assets for 2008, 2009 and 2010 have been retrospectively adjusted to reflect as assets and liabilities held-for-sale and discontinued operations.

On May 27, 2011, the Partnership, along with its subsidiary, Eagle Rock Energy Finance Corp. ("Finance Corp"), as co-issuer, issued $300 million of 8 3/8% senior unsecured notes (the "Senior Notes") through a private placement. The Senior Notes will mature on June 1, 2019, and interest is payable on each June 1 and December 1, commencing December 1, 2011. These Senior Notes were exchanged for registered notes on February 15, 2012.

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 $100 million. During 2012, we issued 834,327 common units under this program for net proceeds of approximately $7.3 million.

On July 13, 2012, the Partnership, along with Finance Corp, issued $250 million of Senior Notes through a private placement. This issuance supplemented our prior $300 million of Senior Notes issued in May 2011. The Senior Notes issued in May 2011 and July 2012 are treated as a single series.

On August 17, 2012, we closed an underwritten public offering of 10,120,000 common units for net proceeds of approximately $84.3 million. The net proceeds were used to repay a portion of the outstanding borrowings under our

58


revolving credit facility in advance of funding the Panhandle Acquisition.

On October 1, 2012, we completed the Panhandle Acquisition for total consideration of $230.6 million. As a result, financial results for the periods prior to October 1, 2012 do not include the financial results from these assets.

 
Year Ended
December 31,
2012
 
Year Ended
December 31,
2011
 
Year Ended
December 31,
2010
 
Year Ended
December 31,
2009
 
Year Ended
December 31,
2008
Statement of Operations Data:
 
 
 
 
 
 
 
 
 
Sales to external customers
$
926,065

 
$
1,027,398

 
$
741,095

 
$
679,220

 
$
1,266,992

Unrealized derivative gains (losses)
6,562

 
52,876

 
8,224

 
(189,590
)
 
207,824

Realized derivative gains (losses)
51,332

 
(20,366
)
 
(17,010
)
 
83,300

 
(46,059
)
Total revenues
983,959

 
1,059,908

 
732,309

 
572,930

 
1,428,757

Cost of natural gas, NGLs and condensate
532,719

 
633,184

 
468,304

 
470,099

 
886,019

Operating and maintenance expense
119,828

 
93,048

 
76,415

 
71,496

 
73,203

Taxes other than income
19,432

 
19,148

 
12,226

 
10,709

 
18,210

General and administrative expense
69,994

 
57,891

 
45,775

 
45,819

 
45,618

Other operating (income) expense

 
(2,893
)
 

 
(3,552
)
 
10,699

Impairment expense
177,003

 
16,288

 
6,666

 
21,788

 
173,110

Depreciation, depletion and amortization
161,045

 
131,611

 
106,398

 
108,530

 
108,356

Operating (loss) income
(96,062
)
 
111,631

 
16,525

 
(151,959
)
 
113,542

Interest expense, net
56,205

 
41,023

 
42,171

 
27,751

 
65,044

Other expense (income)
38

 
184

 
(450
)
 
136

 
(363
)
(Loss) income from continuing operations before income taxes
(152,305
)
 
70,424

 
(25,196
)
 
(179,846
)
 
48,861

Income tax (benefit) provision
(1,703
)
 
(2,432
)
 
(2,585
)
 
989

 
(1,459
)
(Loss) income from continuing operations
(150,602
)
 
72,856

 
(22,611
)
 
(180,835
)
 
50,320

Discontinued operations, net of tax

 
276

 
17,262

 
9,577

 
37,200

Net (loss) income
$
(150,602
)
 
$
73,132

 
$
(5,349
)
 
$
(171,258
)
 
$
87,520

(Loss) income from continuing operations per common unit - diluted
$
(1.13
)
 
$
0.61

 
$
(0.26
)
 
$
(2.38
)
 
$
0.67

 
 
 
 
 
 
 
 
 
 
Balance Sheet Data (at period end):
 
 
 
 
 
 
 
 
 
Property, plant and equipment, net
$
1,968,206

 
$
1,763,674

 
$
1,137,239

 
$
1,124,695

 
$
1,197,945

Total assets
2,294,216

 
2,045,688

 
1,349,397

 
1,534,818

 
1,773,061

Long-term debt
1,153,103

 
779,453

 
530,000

 
754,383

 
799,383

Net equity
868,374

 
1,007,347

 
579,113

 
530,398

 
727,715

 
 
 
 
 
 
 
 
 
 
Cash Flow Data:
 
 
 
 
 
 
 
 
 
Net cash flows provided by (used in):
 
 
 
 
 
 
 
 
 
Operating activities
$
145,501

 
$
117,800

 
$
94,128

 
$
77,228

 
$
138,785

Investing activities
(528,670
)
 
(373,936
)
 
73,545

 
(37,284
)
 
(330,667
)
Financing activities
382,317

 
251,970

 
(175,446
)
 
(73,260
)
 
102,816

Discontinued operations

 
994

 
9,090

 
18,132

 
38,430

Other Financial Data:
 
 
 
 
 
 
 
 
 
Cash distributions per common unit (declared)
$
0.88

 
$
0.75

 
$
0.23

 
$
0.10

 
$
1.63

Adjusted EBITDA(a)
$
245,815

 
$
208,208

 
$
126,026

 
$
172,587

 
$
206,418

________________________
(a)
See Part II Item 6. Selected Financial Data – Non-GAAP Financial Measures for reconciliation of “Adjusted EBITDA” to net cash flows from operating activities and net income (loss).


59


Non-GAAP Financial Measures
 
We include in this report Adjusted EBITDA, which does not comply with accounting principles generally accepted in the United States ("GAAP"). We provide reconciliations of this non-GAAP financial measure to its most directly comparable financial measures as calculated and presented in accordance with GAAP.
 
We define 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 our 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.  We use Adjusted EBITDA as a measure of our core profitability to assess the financial performance of our assets. Adjusted EBITDA is also used as a supplemental financial measure by external users of our financial statements such as investors, commercial banks and research analysts.  For example, the compliance covenant used by our lenders under our revolving credit facility which is designed to measure our viability and our ability to perform under the terms of our revolving credit facility uses Adjusted EBITDA.  We believe that investors benefit from having access to the same financial measures that our management team uses in evaluating performance.  Adjusted EBITDA is useful in determining our 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 our executed derivative instruments and is independent of our assets’ performance or cash flow generating ability, we believe Adjusted EBITDA reflects more accurately our ability to generate cash sufficient to pay interest costs, support our level of indebtedness, make cash distributions to our unitholders and general partner and finance our maintenance capital expenditures. We further believe that Adjusted EBITDA also describes more accurately the underlying performance of our operating assets by isolating the performance of our operating assets from the impact of an unrealized, non-cash measure designed to describe the fluctuating inherent value of a financial asset. Similarly, by excluding the impact of non-recurring discontinued operations, Adjusted EBITDA provides users of our financial statements a more accurate picture of our current assets’ cash generation ability, independently from that of assets which are no longer a part of our operations. Our 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 us. For example, we include in Adjusted EBITDA the actual settlement revenue created from our commodity hedges by virtue of transactions occasionally undertaken by us to reset commodity hedges to higher prices or purchase puts or other similar floors, despite the fact that we exclude from Adjusted EBITDA any charge for amortization of the cost of such commodity hedge reset transactions or puts. 

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 U.S. GAAP.
 
The following table provides a reconciliation of Adjusted EBITDA to net cash flows provided by operating activities and net income (loss):

60



 
Year Ended
December 31,
2012
 
Year Ended
December 31,
2011
 
Year Ended
December 31,
2010
 
Year Ended
December 31,
2009
 
Year Ended
December 31,
2008
Reconciliation of “Adjusted EBITDA” to net cash flows provided by operating activities and net income (loss):
 
 
 
 
 
 
 
 
 
Net cash flows provided by operating activities
$
145,501

 
$
117,800

 
$
94,128

 
$
77,228

 
$
138,785

Add (deduct):
 
 
 
 
 
 
 
 
 
Discontinued operations, net of tax

 
276

 
17,262

 
9,577

 
37,200

Depreciation, depletion, amortization and impairment
(338,048
)
 
(147,899
)
 
(113,064
)
 
(130,318
)
 
(281,466
)
Amortization of debt issuance cost
(3,483
)
 
(2,415
)
 
(1,305
)
 
(1,068
)
 
(958
)
Risk management portfolio value changes
19,534

 
84,753

 
9,195

 
(147,751
)
 
199,339

Reclassing financing derivative settlements
14,449

 
6,267

 
1,131

 
8,939

 
(11,063
)
Other
(9,151
)
 
(1,489
)
 
(5,319
)
 
(2,878
)
 
(4,811
)
Accounts receivable and other current assets
35,951

 
13,394

 
(10,500
)
 
(18,810
)
 
(45,688
)
Accounts payable, due to affiliates and accrued liabilities
(17,524
)
 
189

 
3,418

 
34,903

 
57,041

Other assets and liabilities
2,169

 
2,256

 
(295
)
 
(1,080
)
 
(859
)
Net income (loss)
(150,602
)
 
73,132

 
(5,349
)
 
(171,258
)
 
87,520

Add:
 
 
 
 
 
 
 
 
 
Interest expense, net
61,705

 
46,618

 
35,007

 
40,280

 
37,327

Depreciation, depletion, amortization and impairment
338,048

 
147,899

 
113,064

 
130,318

 
281,466

Income tax (benefit) provision
(1,703
)
 
(2,432
)
 
(2,585
)
 
989

 
(1,459
)
EBITDA
247,448

 
265,217

 
140,137

 
329

 
404,854

Add:
 
 
 
 
 
 
 
 
 
Unrealized (gains) losses from derivative activity
(11,870
)
 
(59,243
)
 
(1,060
)
 
177,061

 
(180,107
)
Restricted unit compensation expense
9,882

 
5,145

 
5,407

 
6,685

 
7,694

Non-cash mark-to-market Upstream imbalances
317

 
74

 
(746
)
 
1,505

 
841

Discontinued operations, net of tax

 
(276
)
 
(17,262
)
 
(9,577
)
 
(37,200
)
Other income
38

 
184

 
(450
)
 
136

 
(363
)
Other operating (income) expense (a)

 
(2,893
)
 

 
(3,552
)