8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): April 12, 2011

EAGLE ROCK ENERGY PARTNERS, L.P.

(Exact name of Registrant as specified in its charter)

Delaware	001-33016	68-0629883
(State or other jurisdiction of incorporation or organization)	Commission File Number	(I.R.S. Employer Identification No.)

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)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

oWritten communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o    Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o    Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o    Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 7.01 Regulation FD Disclosure

Joseph A. Mills, Chief Executive Officer of Eagle Rock Energy G&P, LLC (“G&P LLC”), which is the general partner of  the general partner of Eagle Rock Energy Partners, L.P. (the “Partnership”), and Jeffrey P. Wood, Senior Vice President and Chief Financial Officer of G&P LLC are  presenting at the 2011 IPAA Oil and Gas Investment Symposium in New York on Wednesday, April 13, 2011. Messrs. Mills and Wood will also be conducting investor meetings at the conference. The slideshow presentation that will accompany the presentation made by Messrs. Mills and Wood is being furnished to the Securities and Exchange Commission and is attached hereto as Exhibit 99.1. The presentation contains important information regarding the Partnership and may also be accessed by going to www.eaglerockenergy.com, selecting Investor Relations, then Presentations.

The information set forth in this Item 7.01, the attached exhibit, as well as statements made by representatives of the Partnership during the course of the presentation, includes “forward-looking statements.” All statements, other than statements of historical facts, included in this Item 7.01, the attached exhibit, or made during the course of the presentations, that address activities, events or developments that the Partnership expects, believes or anticipates will or may occur in the future are forward-looking statements. These forward-looking statements are based on certain assumptions made by the Partnership in reliance on its experience and perception of historical trends, current conditions, expected future developments and other factors the Partnership believes are appropriate under the circumstances. Such statements are inherently uncertain and are subject to a number of risks, many of which are beyond the Partnership’s control. Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, the Partnership’s actual results and plans could differ materially from those implied or expressed by any forward-looking statement.

The Partnership undertakes no obligation to publicly update any forward-looking statements, whether as a result of new information or future events. For a detailed list of the Partnership’s risk factors and other cautionary statements, including without limitation risks related to the production, gathering, processing, and marketing of natural gas and natural gas liquids, please consult the Partnership’s Form 10-K, filed with the SEC for the year ended December 31, 2010, as well as any other public filings and press releases.

The information in this Current Report on Form 8-K, including the exhibit attached hereto, is being “furnished” pursuant to Item 7.01 and shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that section, and is not incorporated by reference into any Partnership filing, whether made before or after the date hereof, regardless of any general incorporation language in such filing.

Item 9.01               Financial Statements and Exhibits

(d) Exhibits.

Exhibit No.	Description
99.1	2011 IPAA OGIS Conference Presentation — April 2011

2

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		EAGLE ROCK ENERGY PARTNERS, L.P.
	By:		Eagle Rock Energy GP, L.P.,
			its general partner
	By:		Eagle Rock Energy G&P, LLC,
			its general partner
Date: April 12, 2011	By:		/s/ Charles C. Boettcher
			Charles C. Boettcher
			Senior Vice President and General Counsel

3

INDEX TO EXHIBITS

Exhibit No.	Description
99.1	2011 IPAA OGIS Conference Presentation — April 2011

4

EX-99.1

Exhibit 99.1

[LOGO]

2 This document may include "forward-looking statements." All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Partnership expects, believes or anticipates will or may occur in the future are forward-looking statements and speak only as of the date on which such statement is made. These statements are based on certain assumptions made by the Partnership based on its experience and perception of historical trends, current conditions, expected future developments and other factors it believes are appropriate under the circumstances. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Partnership. These include risks related to volatility of commodity prices; market demand for natural gas and natural gas liquids; the effectiveness of the Partnership's hedging activities; the Partnership's ability to retain key customers; the Partnership's ability to continue to obtain new sources of natural gas supply; the availability of local, intrastate and interstate transportation systems and other facilities to transport natural gas and natural gas liquids; competition in the oil and gas industry; the Partnership's ability to obtain credit and access the capital markets; general economic conditions; and the effects of government regulations and policies. Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, the Partnership's actual results and plans could differ materially from those implied or expressed by any forward-looking statements. The Partnership assumes no obligation to update any forward-looking statement as of any future date. For a detailed list of the Partnership's risk factors, please consult the Partnership's Form 10-K, filed with the Securities and Exchange Commission ("SEC") for the year ended December 31, 2010 as well as any other public filings and press releases. Forward Looking Statements

3 Joseph A. Mills Chairman & Chief Executive Officer Jeffrey P. Wood Senior Vice President & Chief Financial Officer Adam K. Altsuler Director, Corporate Finance & Investor Relations Management Representatives

Midstream Business Strategically Located, Diversified Asset Base 4 Over 5,482 miles of pipeline 19 processing plants 488 MMcf/d gathering volumes 7.0 Mbbl/d equity NGLs / Condensate Midstream Business is exposed to prolific producing “liquids rich” geological trends, specifically the Granite Wash and Austin Chalk as well as the expanding Haynesville Shale Upstream Business is weighted towards oil and NGL production, with 73% of reserves classified as proved developed, and is diversified among four low-cost, low-decline producing basins PF Upstream Business (2) 600+ operated producing wells 396 Bcfe proved reserves ~80 MMcfe/d net production (3) 64% natural gas by reserves Business Mix (1) PF Upstream Adj. EBITDA (1) Midstream Adj. EBITDA (1) Based on Adjusted EBITDA contribution for the twelve months ended December 31, 2010, pro forma for sale of Minerals Business. Pro forma for Crow Creek acquisition. Pro forma for shut-in production associated with Eustace production facility Permian 9% Alabama 28% East Texas 8% South Texas 2% Crow Creek 53% Upstream 57% Midstream 43%  (1) (2) (3) 4

5 Crow Creek Acquisition Announced April 12th Transaction Summary Acquisition of all equity interests of CC Energy II, L.L.C. (“Crow Creek”) for a total consideration of $525 million $318 million for equity interests Assumption of $207 million of Crow Creek debt (to be refinanced at closing) Balanced acquisition consideration further strengthens Eagle Rock balance sheet and credit profile 58% of purchase price in the form of equity delivered to sellers, primarily Natural Gas Partners Cash portion of equity purchase price plus refinancing of existing Crow Creek debt to be funded initially through the Eagle Rock revolver Asset Overview 268 Bcfe of proved reserves located in multiple basins across Oklahoma, Texas and Arkansas (1) Proved reserve base is 66% proved developed and 80% natural gas; key operating areas include the Golden Trend and Cana Shale 1Q’11 production rate of approximately 47 MMcfe/d more than doubles Eagle Rock producing base with much greater potential for growth Financial Impact Transaction is expected to deliver double-digit accretion to distributable cash flow per unit in 2011 and for the next several years as production levels increase Provides path to $1.00 distribution per unit by year-end 2012 while maintaining target distribution coverage ratio of greater than 1.20x (2) Timing The transaction is expected to close on May 3, 2011 As of 12/31/10 using 2/15/11 strip prices. Based on current expectations of business performance and future commodity prices. All actual distributions paid will be determined at the discretion of the Eagle Rock Board of Directors. (1) (2)

6 Provides long-term accretion (driven by production growth) to distributable cash flow per unit Provides significant additional scale and geographic diversity to Eagle Rock’s existing reserve base Total 3P reserves of 740.5 Bcfe (268 Proved Bcfe) located in multiple basins across Oklahoma, Texas and Arkansas (1) Substantially expands portfolio of identified drilling opportunities (182 PUD locations; 413 probable Cana locations; 56 probable non-Cana locations) Low risk locations in established plays (75% operated) (2) Serves as a base for organic production growth through 2015 (based on current drilling schedule) Lengthens total Upstream reserve life (2010 YE Proved Reserves / 2010 Total Production) Crow Creek R/P = 23 years Existing Eagle Rock R/P = 11 years (3) Pro Forma Eagle Rock R/P = 17 years Significant acreage position in Cana Shale provides upside to be realized through drilling (operated primarily by large or super-independents with significant experience) As of 12/31/10 using 2/15/11 strip prices. Based on estimated 2011 production. Adjusted to reflect estimate of a full year of East Texas production (removing the impact of the Eustace processing facility shut-down). Strategic Rationale (1) (2) (3)

7 Crow Creek Transaction Metrics Transaction Metrics Reserve Value ($453.2mm) Transaction Value ($525mm) Proved Reserves ($/Mcfe) (1) 268.0 Bcfe $1.69 $1.96 Total 3P Reserves ($/Mcfe) 740.5 Bcfe $0.61 $0.71 1Q’11 Production ($/Mcfe/d) ~47 MMcfe/d $9,640 $11,170 2011E Production ($/Mcfe/d) (2) ~51 MMcfe/d $8,850 $10,254 Preliminary Allocation of Transaction Consideration ($ in millions) Reserves in Place $453.2 327 operated wells; 1,040 non-op wells; 115,500 net acres Acquired Acreage 61.0 Assumes ~$5,000 / acre valuation for non-producing Cana Shale acreage (approximately 12,000 net acres) Existing Hedges 10.8 Estimated mark-to-market value of acquired hedges Total $525.0 As of 12/31/10 using 2/15/11 strip prices. Based on anticipated drilling plans reflecting the current natural gas price environment. (1) (2)

Acquisition Financing Strengthens Balance Sheet 8 Balanced acquisition consideration preserves strong liquidity position and overall credit metrics Transaction Consideration Mix ($ millions) 58% of transaction consideration is in the form of equity issued directly to Crow Creek owners, primarily Natural Gas Partners (“NGP”) At closing, NGP will increase its ownership stake in Eagle Rock from approximately 24% to 40%-45% Majority of board members (five of nine) will remain independent Voting Agreement preserves public unitholder voting influence by restricting NGP to current voting percentage despite increased equity position (1) Pro Forma Capitalization (in millions) (As of December 31, 2010) Status Quo Pro Forma Total Debt $530.0 $752.0 Enterprise Value (2) $1,515 $2,040 Debt/Enterprise Value 35% 37% Units O/S (3) 105.8 135.3 NGP Ownership 24% 40%-45% Subject to, among other things, termination if NGP ownership falls below 25%. Equity value includes common units and warrants priced at their respective prices as of 4/11/11. Assumes units issued at current market value ($10.26); actual number of units to be issued in the acquisition will be subject to a collar of $7.50/unit and $10.50/unit. Assumes exercise of 16.1 million outstanding warrants. 3% 39% 58% (1) (2) (3)

Dual Platform for Organic Growth 9 With the Crow Creek acquisition, Eagle Rock has two balanced platforms through which it can drive growth organically Midstream assets located in liquids-rich plays such as the Granite Wash and Austin Chalk where producers are ramping-up drilling activity Upstream assets with low-risk proved and probable drilling locations in established basins Focus on organic opportunities across both business lines serves as base for growth without relying on acquisition markets Greater opportunity to provide superior returns to unitholders Source: Partnership estimates, Barclays Capital Research and RBC Capital Markets Research. Crow Creek Acquisition Substantially Expands Organic Growth Opportunities Estimated EBITDA Multiple 2.0 - 6.0x 6.0 - 14.0x 0.0x 4.0x 8.0x 12.0x 16.0x Organic Growth Projects Current Acquisition Multiples

10 Arkoma Basin 145 Op / 365 OBO Current Rate: 9.1 MMcfe/d Proved Reserves: 61 Bcfe 46 PUDs 17% of Proved Value Verden Field 14 Op / 106 OBO Current Rate: 4.1 MMcfe/d Proved Reserves: 42 Bcfe 33 PUDs 10% of Proved Value Barnett Shale 36 Op / 1 OBO Current Rate: 10.7 MMcfe/d Proved Reserves: 33 Bcfe 4 PUDs 9% of Proved Value Golden Trend 62 Op / 94 OBO Current Rate: 16.7 MMcfe/d Proved Reserves: 85 Bcfe 36 PUDs 52% of Proved Value Cana Shale Trend No Op / 4 OBO Current Rate: 2.2 MMcfe/d Proved Reserves: 15 Bcfe 21 PUDs 2% of Proved Value Misc. Anadarko 70 Op / 470 OBO Current Rate: 4.2 MMcfe/d Proved Reserves: 33 Bcfe 42 PUDs 10% of Proved Value Note: Based on Q1 2011 average production. Crow Creek Asset Base Texas Oklahoma Arkansas

Alabama Area Proved Reserves: 66 Bcfe Q4 2010 Prod. Rate: 17.2 MMcfe/d % Gas (3): 23% Permian Area Proved Reserves: 28 Bcfe Q4 2010 Prod. Rate: 5.8 MMcfe/d % Gas (3): 27% South Texas Proved Reserves: 7 Bcfe Q4 2010 Prod. Rate: 2.0 MMcfe/d % Gas (3): 96% East Texas Area (2) Proved Reserves: 27 Bcfe Q4 2010 Prod. Rate: 7.6 MMcfe/d % Gas (3): 42% TOTAL UPSTREAM PF Proved Reserves: 396 Bcfe PF Probable Reserves: 400+ Bcfe PF Avg. Q4 2010 Production (2): 72.7 MMcfe/d 11 Pro Forma Eagle Rock Upstream Assets Crow Creek Assets (1): Proved Reserves: 268 Bcfe Q4 2010 Prod. Rate: 40.0 MMcfe/d % Gas (3): 72% Note: Eagle Rock proved reserves are as of 12/31/10 based on SEC pricing. Reserves as of 12/31/10 using 2/15/11 price deck. Adjusted to reflect estimate of a full year of East Texas production (removing the impact of the Eustace processing facility shut-down). Based on production.

12 Eagle Rock (Status Quo) Crow Creek (1) Adjusted to reflect estimate of a full year of East Texas production (removing the impact of the Eustace processing facility shut-down). Note: Eagle Rock reserves based on 12/31/10 price deck (consistent with SEC filings). Crow Creek reserves as of 12/31/10 using 2/15/11 strip prices. Pro Forma EROC Reserve Category Commodity Pro Forma Proved Reserves Profile 268 Bcfe 128 Bcfe 396 Bcfe Oil 41% Gas 30% NGLs 29% PDP (1) 76% PDNP 13% PUD 11% Oil 19% Gas 64% NGLs 17% PDP 60% PDNP 6% PUD 34% PDP (1) 65% PDNP 8% PUD 27%

13 Eagle Rock (Status Quo) (1) Crow Creek (1) Adjusted to reflect estimate of a full year of East Texas production (removing the impact of the Eustace processing facility shut-down). Pro Forma Q4 2010 Production Summary PF Q4 2010 Avg. Rate: 72.7 MMcfe/d (1) PF 2010 Exit Rate: 76.7 MMcfe/d 2010 Exit Rate: ~33 MMcfe/d 2010 Exit Rate: 43.7 MMcfe/d Pro Forma Q4 2010 Combined 4Q’10 Avg. Rate: 32.7 MMcfe/d 4Q’10 Avg. Rate: 40.0 MMcfe/d Permian 18% East Texas 23% (1) South Texas 6% Alabama 53% Cana 1% Barnett 10% Arkoma 12% Anadarko 6% Verden 6% Golden Trend 20% Permian 8% East Texas 10% South Texas 3% Alabama 24% Cana 2% Barnett 18% Arkoma 22% Anadarko 10% Verden 11% Golden Trend 37%

14 OK TX Field is productive from multiple formations from 8,000’ to 14,000’ Active area with 5 Crow Creek wells drilled in the last 4 months Crow Creek has one operated drilling rig active in the field. It is projected to continue through 5/2013 Proved Reserves 85 Bcfe (57% PDP) 52% of Crow Creek proved value Q1 2011 average production rate – ~1,600 Bbls/d, 7.0 MMcf/d Golden Trend Field Non-operated Producing Proved Undeveloped Locations Operated Producing

15 Growing liquids-rich natural gas shale play in western Oklahoma 54 rigs currently drilling horizontal wells in the trend Shale characterized by dry gas to the southwest and oil to the northeast Crow Creek net leasehold totals 12,700 acres Majority of acreage is in wet gas “window” Crow Creek has one operated rig contracted through 12/2012 Participating (non-operated) in seven wells currently drilling Majority of drilling activity conducted by large independent producers such as Devon and Continental Cana Shale Acreage and Activity Devon drilled 87 new wells in play in 2010, plans to drill over 200 wells in 2011 and recently completed construction of gas processing plant (1) (1) Based on Devon investor presentations and press releases.

Midstream Business Investor Presentation April 2011 Eagle Rock Energy Partners, L.P.

17 Overview of Midstream Business Panhandle (2) 3,963 miles of pipeline 7 processing plants 141,000 compression HP East Texas / North Louisiana 1,213 miles of pipeline 7 processing plants 49,700 compression HP Gulf of Mexico 40 miles of pipeline 2 processing plants 14,180 compression HP Processing Plant Haynesville Shale Austin Chalk Granite Wash South Texas 266 miles of pipeline 3 processing stations 15,300 compression HP Deep Bossier / Angelina River Trend (1) Based on Q4 2010. (2) Pro forma for asset acquisition from CenterPoint which closed on October 19, 2010. Gathering Volumes (MMcf/d) (1) Equity NGL/Condensate Volumes (MBbl/d) (1)

18 Panhandle: Rich in Growth Opportunities Hemphill Horizontal Wells 47 Producing 11 Permitted 43 Total MMcf/d Roberts Horizontal Wells 52 Producing 6 Permitted 29 Total MMcf/d Wheeler Horizontal Wells 37 Producing 23 Permitted 124 Total MMcf/d Panhandle System Activity: Currently in the process of connecting nine new wells to Eagle Rock’s gathering systems in East Panhandle Contracted eight new sections of dedicated acreage in Wheeler County Completed installation of new 80 GPM treating facility at Eagle Rock’s Goad Treater in Hemphill County Integration of East Hemphill System completed on January 1, 2011 Panhandle Daily Gathering Volumes MMcfe/d Converted “Dry Gas” System to “Wet Gas” System Proven horizontal drilling potential in Granite Wash EUR of 6 to 8 Bcfe per well (1) Most recent 7 wells in Wheeler County have averaged IPs of 27 MMcfe/d with others with IPs as high as 60 MMcfe/d, including liquids content (1) Connecting Pipeline from Roberts County System to Red Deer Plant (1) Producer investor presentations. 0 25 50 75 100 125 150 175

19 System Update: Austin Chalk: Large independents staking 20 potential sites dedicated to Eagle Rock Currently, three rigs running on acreage dedicated to Eagle Rock Last two producer wells reported average IP of approximately 16 MMcf/d Deep and Middle Bossier: Producers planning wildcats this year for the play – Middle Bossier IP’s in the 15-30 MMcf/d range Haynesville Shale: Continue to monitor drilling activity as it continues to move closer to our acreage Strategic Footprint in East Texas Source: SEC filings, industry investor presentations and DrillingInfo. Brookeland System Tyler County System East Texas Main Line Simsboro Bellebower Panola Sligo Indian Springs Brookeland

Strong credit profile and capital availability Absence of incentive distribution rights enhances long-term accretion potential Core midstream operations in liquids-rich areas with substantial exposure to Granite Wash and expansion potential in East Texas Haynesville Shale Balanced midstream / upstream platform widens opportunity set Crow Creek acquisition provides substantial drilling inventory (over 600 drilling locations) and immediate double-digit accretion to distributable cash flow per unit Management’s expectation to recommend $1.00/unit distribution by end of 2012 while maintaining target distribution coverage ratio greater than 1.20x (1) Eagle Rock is Well-Positioned for Continued Growth 20 (1) Based on current expectations of business performance and future commodity prices. All actual distributions paid will be determined at the discretion of the Eagle Rock Board of Directors.

Appendix Investor Presentation April 2011 Eagle Rock Energy Partners, L.P.

Robust Hedging Profile Status Quo Hedging Summary (1) Percent of Hedgeable Volumes Hedged Prices shown reflect weighted average price of swaps and collar floors ($/Bbl and $/MMbtu) and exclude price impact of direct product hedges. Prices shown reflect weighted average price of swaps and collar floors ($/Bbl and $/MMbtu) and exclude price impact of direct product hedges. Pro forma for Crow Creek Energy’s existing hedging portfolio and expected production. Crow Creek expected ethane production is included in the NGL component. 22 Pro Forma Hedging Summary (2) On April 7, 2011, Eagle Rock entered into the following crude oil and natural gas hedging transactions: 20,000 Bbl/mo WTI swap at $104.85/Bbl for the twelve month period ending December 31, 2013 45,000 Bbl/mo WTI swap at $102.45/Bbl for the twelve month period ending December 31, 2014 80,000 MMbtu/mo Henry Hub swap at $4.865/Mmbtu for the twelve month period ending December 31, 2012 105,000 MMbtu/mo Henry Hub swap at $5.30/Mmbtu for the twelve month period ending December 31, 2013 Recent Hedging Activity Crude $74.92 $79.87 $92.10 $102.45 $73.74 $79.35 $91.24 $102.45 Natural Gas $7.19 $6.54 $5.37 NA $6.20 $5.79 $5.17 NA 90% 80% 74% 25% 60% 60% 40% 0% 0% 20% 40% 60% 80% 100% 2011 REM 2012 2013 2014 Crude, Condensate and NGLs (>C3) Ethane and Natural Gas 87% 73% 66% 23% 69% 59% 37% 0% 0% 20% 40% 60% 80% 100% 2011 REM 2012 2013 2014 Crude, Condensate and NGLs (>C3) Ethane and Natural Gas

23 Pro Forma Eagle Rock Credit Facility Senior secured revolving credit facility with total availability of $341 million (1) from 18 financial institutions Borrowing Base Compliance Tests Eagle Rock’s lenders have approved an increase of $245 million to its borrowing base, attributable to Crow Creek’s reserves, upon closing Eagle Rock’s standalone Borrowing Base was recently redetermined at $160 million, effective April 1, 2011, as part of regular semi-annual redetermination Supported by Midstream Business Compliance tests are based on Midstream EBITDA and non-borrowing base debt Bank Covenants (2): Covenant Q4 2010 Total Leverage Ratio: < 5.00x 4.27x Interest Coverage Ratio: > 2.50x 3.81x Adjusted for recent increase in borrowing base, effective April 1, 2011. Commitments reduced by $100 million in conjunction with Minerals business sale on 5/24/10; availability reduced by $9.1 million in unfunded commitments from LEH. As of Q4 2010 compliance calculations. Includes pro forma credit for Phoenix processing plant in Texas Panhandle. Total Borrowings Status Quo (1) Pro Forma w/ Crow Creek Eagle Rock Borrowing Base $160.0 $405.0 Funded Debt 370.0 347.0 Total Borrowings $530.0 $752.0 Total Leverage Ratio 4.27x 3.76x (1) (2)

24 System Overview (1) Map of Texas Panhandle System Midstream: Panhandle System Miles of Pipeline: 3,963 Processing Plants: 7 Compression HP: 141,000 4Q10 Avg. Gathering Volume: 143 MMcf/d 4Q10 Avg. Equity NGL / Condensate Volume: 5.4 Mbbl/d 2010 Operating Income (2): $80.1 million 2010 Capex: $29.3 million Producing Formations: Granite Wash Morrow Brown Dolomite Cleveland (1) Pro forma for acquisition of Centerpoint assets. Excludes G&A, impairment expense, and discontinued operations. Based on December 2010. Contract Mix by Throughput (3) Gross Margin (3) Fixed Fee 9% Commodity Based 91% (2) (3)

25 System Overview Map of East Texas System Midstream: East Texas System Miles of Pipeline: 1,213 Processing Plants: 7 Compression HP: 49,700 4Q10 Avg. Gathering Volume: 194 MMcf/d 4Q10 Avg. Equity NGL / Condensate Volume: 1.3 Mbbl/d 2010 Operating Income (1): $35.8 million 2010 Capex: $15.8 million Producing Formations: Austin Chalk James Lime Trend Travis Peak Haynesville Shale Cotton Valley Woodbine (1) Excludes G&A, impairment expense, and discontinued operations. (2) Based on December 2010. Contract Mix by Throughput (2) Gross Margin (2) Fixed Fee 27% Commodity Based 73% Commodity Based 65% Fixed Fee 35%

26 System Overview Map of South Texas System Producer Activity / Competitive Positioning Midstream: South Texas System Major producers are Chesapeake and Sanchez Oil & Gas in South Texas Activity has slowed due to lower natural gas commodity prices Phase 1 20-inch provides lower pressure service with access to two competing processing plants for producers Miles of Pipeline: 266 Processing JT Skids: 3 Compression HP: 15,300 2010 Operating Income (1): $6.2 million 2010 Capex: $0.1 million (1) Excludes G&A, impairment expense, and discontinued operations. (2) Based on December 2010. Contract Mix by Throughput (2) Gross Margin (2) Fixed Fee 37% Commodity Based 63% Fixed Fee 74% Commodity Based 26%

27 System Overview Gulf of Mexico System Midstream: Gulf of Mexico System Miles of Pipeline: 40 Processing Plants: 2 (non-operated) Compression HP: 14,180 2010 Operating Income (1): $3.2 million 2010 Capex: $0.2 million Producer interests in approximately 115 blocks committed to life-of-lease contracts Davy Jones discovery in shallow water covers some of Eagle Rock’s committed leases Deep subsalt shelf drilling could provide additional upside Major producers are Stone Energy and McMoran Exploration Contracts are life-of-lease commitments and typically percent of proceeds with fixed floors Have processing contracts with four third party plants and our two equity plants Provides ability to handle producers’ needs across the Gulf of Mexico (1) Excludes G&A, impairment expense and discontinued operations. (2) Based on December 2010. Contract Mix by Throughput (2) Gross Margin (2) Producer Activity / Competitive Positioning Fixed Fee 14% Commodity Based 86% Commodity Based 99% Fixed Fee 1%

28 Alabama: Largest Upstream Asset Acquisition Date: July 31, 2007 Alabama Counties: Escambia, Choctaw Operated Producing Wells: 29 Non-Op Wells: 2 Net Acreage: 13,000 Net Reserves: 10.9 MMboe (65.4Bcfe) Average Operated W.I.: 73% Producing Formations: Smackover, Norphlet Gas Stream Composition (+/-): 20% H2S 45% CO2 Assets include two treating plants (100 MMcf/d capacity) and one cryogenic processing plant (50 MMcf/d) to remove H2S and CO2 prior to sales Net Production: Gas Mcf/d: 3,578 Oil Bo/d: 1,566 NGLs Bl/d: 647 Sulfur LT/d: 169 Total Mcfe/d: 16,798 (21% gas) Financial Summary Revenue ($ in millions): $55.4 Operating Expense ($ in millions) (1): $14.3 Unit Operating Expense ($/BOE) (1): $14.28 Florida / Alabama State Border (1) Excluding taxes. Exploit behind-pipe zones in current wellbores Continue to increase market flexibility for all products Optimize gathering system to increase production Reconfigure wells and install artificial lift to improve flow efficiencies Asset Overview Alabama Properties 2010 Operating Statistics 2011 Objectives

29 East Texas Smackover Trend Assets Acquisition Date: July 31, 2007 Texas Counties: Wood, Rains, Van Zandt, Henderson Operating Producing Wells: 34 Non-Op Producing Wells: 123 (ETX/LA) Net Acreage: 16,000 Net Reserves: 4.5 MMboe (27.0 Bcfe) Average Operated W.I.: 83% Producing Formations: Smackover, Cotton Valley Gas Composition: 20-40% H2S Eagle Rock’s East Texas production is treated and processed by Tristream Energy facilities Net Production: Gas Mcf/d: 5,199 Oil Bo/d: 261 NGLs Bl/d: 518 Sulfur LT/d: 103 Total Mcfe/d: 9,876 (53% gas) Financial Summary Revenue ($ in millions): $19.0 Operating Expense ($ in millions) (2): $3.9 Unit Operating Expense ($/BOE) (2): $8.54 (1) Includes the Partnership’s Mississippi and South Texas operations. (2) Excluding taxes. Exploit new Cotton Valley discovery with targeted drilling and well re-entries Improve well performance through well re-configuration and artificial lift Optimize compression to reduce wellhead pressures and increase production Asset Overview East Texas Properties 2010 Operating Statistics (1) 2011 Objectives

30 Asset Overview Permian Basin Properties 2010 Operating Statistics Permian Basin Assets Acquisition Date: April 30, 2008 Texas Counties: Ward, Crane, Pecos Operated Producing Wells: 186 Non-Op Producing Wells: 21 Net Acreage: 24,000 Net Reserves: 4.7 MMboe (28.2 Bcfe) Average Operated W.I.: 96% Producing Formations: Yates, Queen, San Andres, Wichita Albany, Holt, Wolfcamp and Penn Net Production: Gas Mcf/d: 1,563 Oil Bo/d: 469 NGLs Bl/d: 221 Total Mcfe/d: 5,706 (27% gas) Financial Summary Revenue ($ in millions): $17.4 Operating Expense ($ in millions) (1): $5.0 Unit Operating Expense ($/BOE) (1): $14.53 (1) Excluding taxes. 2011 Objectives Exploit behind-pipe reserves in multiple horizons with low risk workovers Evaluate tertiary CO2 flood potential Target bolt-on acquisition opportunities

31 Asset Overview South Texas Properties Upstream: South Texas Acquisition Date: July 31, 2007 Texas Counties: Atascosa Operating Producing Wells: 11 Net Acreage: 1,400 Net Reserves: 1.1 MMboe (6.6 Bcfe) Average Operated W.I.: 100% Producing Formations: Edwards Successful re-completion program conducted in 2008 with infill drilling locations identified for future development Acreage is well-positioned in the “wet” gas window of the Eagleford Shale Evaluating options to exploit resource Note: South Texas operations included in East Texas operating statistics.

32 SEC Reserve Disclosures The SEC permits oil and gas companies, in their filings with the SEC, to disclose only “reserves” as defined by SEC rules. Estimates of reserves in this communication are based on economic assumptions with regard to commodity prices (NYMEX strip) that differ from the prices required by the SEC (historical 12 month average) to be used in calculating reserves estimates of reserves prepared in accordance with SEC definitions and guidelines. In addition, the SEC generally prohibits in SEC filings the reporting of reserves of different categories on a combined basis (3P) because each category of proved, probable and possible reserves involves substantially different risks of ultimate recovery. Factors affecting ultimate recovery include the scope of our proposed drilling program, which will be directly affected by the availability of capital, drilling and production costs, commodity prices, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors, and actual drilling results, including geological and mechanical factors affecting recovery rates. Accordingly, actual quantities that may be ultimately recovered from the Partnership's interests may differ substantially from the Partnership’s estimates of reserves. In addition, the Partnership's estimates of reserves may change significantly as development of the Partnership’s properties provide additional data.

33 This presentation includes, and certain statements made during this presentation may include, the non-generally accepted accounting principles, or non-GAAP, financial measures of Adjusted EBITDA. The accompanying non-GAAP financial measures schedule provides reconciliations of Adjusted EBITDA to its most directly comparable financial measure calculated and presented in accordance with accounting principles generally accepted in the United States, or GAAP, with respect to the references to Adjusted EBITDA that are of a historical nature. Where references are forward-looking or prospective in nature, and not based in historical fact, this presentation does not provide a reconciliation. Eagle Rock could not provide such reconciliation without undue hardship because the Adjusted EBITDA numbers included in the presentation, and that may be included in certain statements made during the presentation, are estimations, approximations and/or ranges. In addition, it would be difficult for Eagle Rock to present a detailed reconciliation on account of many unknown variables for the reconciling items. For an example of the reconciliation, please consult the reconciliations included for the historical Adjusted EBITDA numbers in this appendix. Non-GAAP financial measures should not be considered as alternatives to GAAP measures such as net income (loss), operating income (loss), cash flows from operating activities or any other GAAP measure of liquidity or financial performance. Eagle Rock defines Adjusted EBITDA as net income (loss) plus or (minus) income tax provision (benefit); interest-net, including realized interest rate risk management instruments and other expense; depreciation, depletion and amortization expense, impairment expense; other operating expense, non-recurring; other non-cash operating and general and administrative expenses, including non-cash compensation related to 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) expenses. Eagle Rock uses Adjusted EBITDA as a measure of its core profitability to assess the financial performance of its assets. Adjusted EBITDA also is used as a supplemental financial measure by external users of Eagle Rock’s financial statements such as investors, commercial banks and research analysts. For example, Eagle Rock’s lenders under its revolving credit facility use a variant of Eagle Rock’s Adjusted EBITDA in a compliance covenant designed to measure the viability of Eagle Rock and its ability to perform under the terms of its revolving credit facility; Eagle Rock, therefore, uses Adjusted EBITDA to measure its compliance with its revolving credit facility. Eagle Rock believes that investors benefit from having access to the same financial measures that its management uses in evaluating performance. Adjusted EBITDA is useful in determining Eagle Rock’s ability to sustain or increase distributions. By excluding unrealized derivative gains (losses), a non-cash, mark-to-market benefit (charge) which represents the change in fair market value of Eagle Rock’s executed derivative instruments and is independent of its assets’ performance or cash flow generating ability, Eagle Rock believes Adjusted EBITDA reflects more accurately Eagle Rock’s ability to generate cash sufficient to pay interest costs, support its level of indebtedness, make cash distributions to its unitholders and general partner and finance its maintenance capital expenditures. Eagle Rock further believes that Adjusted EBITDA also describes more accurately the underlying performance of its operating assets by isolating the performance of its operating assets from the impact of an unrealized, non-cash measure designed to describe the fluctuating inherent value of a financial asset. Similarly, by excluding the impact of non-recurring discontinued operations, Adjusted EBITDA provides users of the Partnership’s financial statements a more accurate picture of its current assets’ cash generation ability, independently from that of assets which are no longer a part of its operations. Use of Non-GAAP Financial Measures

34 Eagle Rock’s Adjusted EBITDA definition may not be comparable to Adjusted EBITDA or similarly titled measures of other entities, as other entities may not calculate Adjusted EBITDA in the same manner as Eagle Rock. For example, Eagle Rock includes in Adjusted EBITDA the actual settlement revenue created from its commodity hedges by virtue of transactions undertaken by it to reset commodity hedges to prices higher than the then-current forward strip price for such future period or purchase puts or other similar floors despite the fact that Eagle Rock excludes from Adjusted EBITDA any charge for amortization of the cost of such commodity hedge reset transactions or puts. Eagle Rock has reconciled historical Adjusted EBITDA numbers to the GAAP financial measure of net income (loss) in the appendix to this presentation but has not reconciled prospective Adjusted EBITDA numbers. Use of Non-GAAP Financial Measures (Continued)

35 Adjusted EBITDA Reconciliation ($ in 000's) Year Ended December 31, 2010 2009 2008 2007 2006 Net Income (loss) ($5,349) ($171,258) $87,520 ($145,634) ($23,314) Add: Interest (income) expense, net 35,058 41,350 38,282 44,587 30,383 Depreciation, depletion, amortization and impairment 141,656 132,043 282,090 72,531 43,220 Income tax provision (benefit) (2,545) 1,022 (1,567) 13 1,230 EBITDA $168,820 $3,157 $406,325 ($28,503) $51,519 Add: Income from discontinued operations ($43,207) ($9,397) ($37,169) ($2,096) $0 Risk management portfolio value changes (1,060) 177,061 (180,107) 144,176 23,531 Restricted unit compensation expense 5,407 6,685 7,694 2,395 142 Other income (501) (934) (1,318) 18 0 Non-cash mark-to-market of Upstream imbalances (746) 1,505 841 0 0 Non-recurring operating items 0 (3,552) 10,699 2,052 6,000 Adjusted EBITDA $128,713 $174,525 $206,965 $118,042 $81,192 Year Ended December 31, 2010 2009 2008 2007 2006 Amortization of commodity derivative costs $3,957 $48,363 $13,288 $8,224 $19,227