Eagle Rock Energy Partners L P (EROC) 8-K Regulation FD Disclosure

Exhibit 99.1

[LOGO]

Forward Looking Statements 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, the Partnership’s Forms 10-Q, filed with the SEC for subsequent quarters, as well as any other public filings and press releases. 2

Management Representatives Joseph A. Mills Chairman Jeffrey P. Wood & Chief Executive Officer Senior Vice President & Chief Financial Officer L. Patrick Giroir Senior Vice President, Midstream Business Joseph E. Schimelpfening Senior Vice President, Upstream Business Adam K. Altsuler Director of Corporate Finance & Investor Relations 3

Eagle Rock Energy Partners, L.P. Snapshot • Eagle Rock (NASDAQ: EROC) is a growth-oriented MLP engaged in the midstream and upstream businesses and is well-positioned to benefit from some of the most prolific producing basins in the U.S. Enterprise Value(1): $2.1 billion PF Annualized Adj. EBITDA(2): $216 million Q2 Leverage Ratio: 3.4x Estimated Business Mix (3) Oil 24% Total Company Commodity Mix (4) Upstream 60% Midstream 40% Natural Gas 44% (1) Equity value includes common units and warrants priced at their respective prices as of 8/19/11. (2) Calculated based on 3 months ended 6/30/11 Adjusted EBITDA times 4. (3) Based on segment operating income plus DD&A for the LTM ended 6/30/11 and excluding G&A. (4) Based on 6/30/11 LTM net equity volumes from Midstream Business and production volumes from Upstream Business. Adjusted for Eustace processing facility shut-down and pro forma for Crow Creek acquisition. 4 NGLs 32% Legend Midstream Processing Plants Midstream Gathering Systems Existing Areas of Operation

Strategically Located, Diversified Asset Base Midstream Business (1) • 5,482 miles of pipeline • plants Upstream Business (2) • 600 operated producing wells • Bcfe 19 processing • 488 MMcf/d gathering volumes • 6.1 MBbls/d equity NGLs / Condensate 385 proved reserves • 82.8 MMcfe/d net production • 63% natural gas by reserves PF Upstream Business Mix (3) Midstream Business Mix (3) East Texas 12% GOM 4% East Texas / Lo isiana Permian 8% South Texas 1% Mid- Continent 40% Louisiana 27% Alabama 39% Texas Panhandle 68% South Texas 1% 5 (1) Based on Q2 2011. (2) Reserves as of 12/31/10 based on SEC pricing as of 12/31/10. Net production based on Q2 average production. Mid-continent average production rate is based on period beginning May 3, 2011, the date the Crow Creek Acquisition closed, and ending June 30, 2011. (3) Based on Q2 2011 operating income plus DD&A, excluding G&A and hedging impact. Upstream Mid-Continent EBITDA is pro forma for entire second quarter.

Eagle Rock Energy Partners, L.P. Recent Developments Investor Presentation August 2011

May 3, 2011: Closed Crow Creek Acquisition Transaction Overview • Acquisition of all equity interests of CC Energy II L.L.C (“Crow Creek”) for a total purchase price of $563.7 million – 60% sellers Transaction Highlights of purchase price in form of equity to sellers, primarily Natural Gas Partners • Added significant scale and geographic diversity to existing Upstream Business – Proved reserves of 257 Bcfe (Total 3P reserves of 740.5 Bcfe) located in multiple basins across Oklahoma, Texas and Arkansas(1) • Provides for long-term accretion (driven by production growth) to distributable cash flow per unit • Expands portfolio of identified drilling opportunities (adds 182 PUD locations; 413 probable Cana locations; 56 probable non-Cana locations) – Lower-risk locations in established plays (76% operated)(2) – Base for through organic production growth 2015 (based on current drilling schedule) • Lengthens total upstream reserve life (2010 YE Proved Reserves / 2010 Total Production) from 11 years to 17 years(3) • Significant acreage provides 7 position in Cana Shale upside to be realized through drilling (1) Proved reserves as of 12/31/10 based on SEC pricing as of 12/31/10; total 3P reserves as of 12/31/10 based on 2/15/11 strip prices. (2) Based on estimated 2011 production. (3) Adjusted to reflect estimate of a full year of East Texas production (removing the impact of the Eustace processing facility shut-down).

Mid-Continent Asset Base Golden Trend 64 Op/94 OBO Q2 ‘11 Avg. Rate: 17.0 MMcfe/d Proved Reserves: 85 Bcfe 36 PUDs 52% of Proved Value Cana Shale Trend 1 Op / 27 OBO Arkansas Arkoma Basin O OBO Verden Field OBO Q2 2011 Avg. 3.5 MMcfe/d Proved Reserves: 15 Bcfe 21 PUDs 2% of Proved Value 145 Op / 365 Q2 ‘11 Avg. Rate: 8.0 MMcfe/d Proved Reserves: 57 Bcfe 46 PUDs 17% of Proved Value 14 Op / 106 Q2 ‘11 Avg. Rate: 3.9 MMcfe/d Proved Reserves: 41 Bcfe 33 PUDs 10% of Proved Value Anadarko Texas Oklahoma Barnett Shale 36 Op / 1 OBO Q2 ‘11 Avg. Rate: 9.2 MMcfe/d Proved Reserves: 32 Bcfe 4 PUDs 9% of Proved Value Misc. 70 Op / 470 OBO Q2 ‘11 Avg. Rate: 5.1 MMcfe/d Proved Reserves: 28 Bcfe 42 PUDs 10% of Proved Value 8 Note: Proved reserves as of 12/31/10 based on SEC pricing as of 12/31/10. Average production rates are based on period beginning May 3, 2011, the date the Crow Creek Acquisition closed, and ending June 30, 2011.

Building on Our Core Position Delivering for Our Producer Customers Date Expansion Processing Capacity Oct ’10 Acquisition of CEFS System NA Hemphill County Announced 30 MMcf/d Expansion Dec ’10 Installation of Phoenix- Arrington Ranch Plant 50 MMcf/d 4Q ’11 Phoenix-Arrington Ranch Expansion 30 MMcf/d 1Q ’12 Installation of Woodall Plant 60 MMcf/d Red Deer Canadian Phoenix-Arrington and related Infrastructure Announced 60 MMcf/d Woodall Plant Ranch Roberts County Eagle Rock Processing Facility Wheeler County • Contracted NGL takeaway capacity increases to 22,400 New producer customer acreage dedications Proposed new 6-inch NGL line Bbls/d, effective April 1, 2012 Recently acquired 60 MMcf/d cryogenic plant – future Woodall Plant

Positioning for Further Growth Eagle Rock Has Substantially Improved Its Liquidity and Balance Sheet Stability (1) June 30, 2009 June 30, 2010 June 30, 2011 Equity 43.0% Equity 23.0% Enterprise Value: $1.1 billion Enterprise Value: $1.0 billion Enterprise Value: $2.2 billion Credit Facility Borrowings 20.0% Equity 63.0% Warrants 3.0% Credit Facility Credit Facility Borrowings Senior Notes 14.0% Borrowings 57.0% 77.0% Credit Facility Availability : ~$85 million Credit Facility Availability : ~$180 million Credit Facility Availability : ~$220 million 3-Mo. Avg. Daily Trading Value: ~$2.5 million 3-Mo. Avg. Daily Trading Value: ~$2.4 million 3-Mo. Avg. Daily Trading Value: ~$4.7 million Approximately $32 million of warrant proceeds were received on 8/15/11 exercise date (1) Equity value includes common units and warrants priced at their respective prices as of the respective periods.

Returning Value to Our Unitholders Improved Growth Profile and Capitalization Lead to Greater Unitholder Value Current Annualized Distribution Guidance ** $1.00 $0.75 $1.00 33% 25% per Unit $0.50 0.75 $0.60 $0.60 Annualized Distribution $0.00 $0.25 ** Management's distribution recommendation is subject to change should factors affecting the general business climate or the Partnership's specific operations or applicable regulatory mandates differ from current expectations. All actual distributions paid will be determined and declared at the discretion of the Eagle Rock board of directors. Actual future changes in the distribution level, if any, will be driven by market conditions, future commodity prices, the Partnership's leverage levels, the performance of the Partnership's underlying assets and the Partnership's ability to consummate accretive growth projects or acquisitions, including without limitation this acquisition.

Robust Hedging Profile Crude, Condensate and NGLs (>C2) (1) Ethane and Natural Gas (1) 80% 100% $5.68 $5.96 100% $75.23 99% 88% 60% $5.22 60% 80% $97.60 $81.75 68% 25% 20% 40% $5.55 79% 71% 68% 22% 20% 40% $102.45 Recent Hedge Activity 0% 2011 REM 2012 2013 2014 0% 2011 REM 2012 2013 2014 Product / Derivative Start Date End Date Monthly Quantity Total Quantity Strike Price WTI Crude (Bbls) Swap Jan-2013 Dec-2013 32,000 384,000 $ 101.96 (1) Prices shown reflect weighted average price of swaps and collar floors ($/Bbl and $/MMBtu) and exclude price impact of direct product hedges. 12

Midstream Business Overview

Geographically Diverse Midstream Business East Texas / North Louisiana • 1,213 miles of pipeline • 7 processing plants • 49 700 Granite Wash Panhandle • 3,963 miles of pipeline • 7 processing plants • 141,000 compression HP • 154 MMcf/d gathering volume 49,700 compression HP • 192 MMcf/d gathering volume • 1,169 Bbls/d NGL/condensate Gulf of Mexico • 40 • 4,664 Bbls/d NGL/condensate miles of pipeline • 2 processing plants • 14,180 compression HP • 116 MMcf/d gathering volume • 290 Bbl/d NGL/condensate Haynesville Shale Deep Bossier / Angelina River Trend Tuscaloosa Shale Austin Chalk South Texas 266 il f i li TOTAL MIDSTREAM • miles of pipeline • 3 processing stations • 15,300 compression HP • 27 MMcf/d gathering volume • 12 Bbls/d NGL/condensate Pipeline Miles: 5,482 Processing Plants: 19 Compression HP: 220,180 2Q11 Gathering Volumes: 488 MMcf/d 2Q11 NGL/EROC Processing Plant Condensate Equity Volumes: 6,135 Bbls/d Note: Based on Q2 2011.

Midstream: Panhandle System Announced planned MMcf/d installation of 60 cryogenic processing facility (the Woodall Plant) West Panhandle: • Liquids-rich production from Brown Dolomite formation - 8+ GPM gas East Panhandle: • Liquids-rich production from Granite Wash play (4-6 GPM gas) • Low decline production (6-7% annually) • Eagle Rock system well-positioned in one of the most active plays in the U.S. 

East Panhandle: Rich in Growth Opportunities Hemphill Horizontal Activity 33 Permitted 220 Producing 44 Rigs Running Roberts Horizontal Activity 13 Permitted 161 Producing 15 Rigs Running • 132 directional / horizontal rigs running in Roberts, Hemphill and Wheeler Counties today 57 in System Activity ( Granite Wash Play) • Eagle Rock system currently at 90%+ utilization • Expanding Phoenix-Arrington Ranch plant to 80 MMcf/d (expect Location of completion in Q4 2011) • Recently announced new state-ofthe- art 60 MMcf/d cryogenic plant (the Woodall Plant) in Hemphill County Connecting Pipeline from Roberts County System to Red Deer Plant Expanding Phoenix- Arrington Ranch Plant Proposed New 60 MMcf/d Woodall Plant – Estimated Q1 2012 completion – Secured additional 7,000 Bbls/d NGL takeaway (45% increase) • 4 rigs currently drilling on EROC system to 80 MMcf/d Wheeler Horizontal Activity 45 Permitted 375 Producing 73 Rigs Running – 14 new well connects completed YTD (IPs from 4-15 MMcfd) • New acre dedications and strong well performance yielding positive outlook on 16 system volumes .Source: SEC filings, industry investor presentations, HPDI and RigData.

Strategic Footprint in East Texas Austin Chalk: • Large independents staking 14 potential System Activity dedicated sites • Drilling moving east into Louisiana with Austin Chalk and prospective Tuscaloosa Shale / Louisiana Eagle Ford Play • Currently four rigs Indigo Minerals Bentley Lumber 34H #1 and 32#1 Tuscaloosa Shale wells, running on dedicated acreage • Last well reported average IP of Swift and Anadarko Austin Chalk wells approximately 10 MMcf/d 17 Source: SEC filings, industry investor presentations, HPDI and RigData.

Upstream Business Overview

Geographically Diverse Upstream Assets (1) Mid-Continent Assets Proved Reserves: 257 Bcfe Q2 2011 Prod. Rate (2): 46.8 MMcfe/d % Gas (3): 81% Alabama Area Proved Reserves: 65 Bcfe Q2 2011 Prod. Rate: 19.8 MMcfe/d % Gas (3): 23% Permian Area Proved Reserves: 28 Bcfe Q2 2011 Prod. Rate: 5.6 MMcfe/d % Gas (3): 26% East Texas Area Proved Reserves: 28 Bcfe Q2 2011 Prod. Rate: 9.1 MMcfe/d % Gas (3): 43% South Texas Proved Reserves: 7 Bcfe Q2 2011 Prod. Rate: 1.6 MMcfe/d % Gas (3): 97% TOTAL UPSTREAM Proved Reserves: 385 Bcfe Probable Reserves: 400+ Bcfe Avg. Q2 2011 Production (2): 82.8 MMcfe/d 90.0 MMcfe/d 2011 Projected Exit Rate: 19 Note: Proved reserves as of 12/31/10 based on SEC pricing as of 12/31/10; probable reserves as of 12/31/10 based on 2/15/11 strip prices. (1) Includes Barnett Shale. (2) Mid-Continent average production rate is based on period beginning May 3, 2011, the date the Crow Creek Acquisition closed, and ending June 30, 2011. (3) Based on production.

Crow Creek Adds Scale and Diversity to Reserve Base Eagle Rock (Legacy Assets) Crow Creek Current Eagle Rock PUD 11% PUD 26% PUD 34% Catego PDNP 13% PDP PDNP 9% PDP Res PDP (1) 76% (1) 65% 60% PDNP 6% 257 Bcfe 128 Bcfe 385 Bcfe Gas NGLs 29% NGLs 17% NGLs 12% Comm Oil 41% 30% Oil 20% Gas 63% Oil 9% Gas 79% 20 (1) EROC PDP reflects recategorization of reserves following the resumption of East Texas production associated with the Eustace facility. Note: Reserves as of 12/31/10 based on SEC pricing as of 12/31/10. Commodity Reserve Category

Diversified Production Base Across High Quality Basins Eagle Rock (Pre-Crow Creek) PF Q2 2011 Combined (1) Cana 4% Permian 16% Barnett 11% Alabama 24% East Texas 25% Alabama 55% Arkoma 10% Anadarko 6% South Texas 2% South Texas 4% Verden 5% Golden Trend 20% Permian 7% East Texas 11% Q2 2011 Avg. Rate: 82.8 MMcfe/d (1) Q2 2011 Avg. Rate: 36.0 MMcfe/d 21 (1) Crow Creek average production rate is based on period beginning May 3, 2011, the date the Crow Creek Acquisition closed, and ending June 30, 2011.

Golden Trend Recent Activity McElvaney 2-23 Drilling • Proved Reserves – 85 Bcfe (57% PDP) – 52% of Crow Creek proved value Scott 1-17 IP 290 BO 1100 MCF • 2Q average production rate – 7.6 MMcfd, 673 Bopd, 891 Blpd • Field is productive from multiple formations from 8,000’ to 14,000’ Riddle 9-32 Completing Lane 1-3 IP 103 BO 500 MCF Newby 2-36 IP 328 BO 1000 MCF including Bromide, Big 4, Springer, Morrow, Hart, Deese • Expect a minimum of one operated drilling rig active in the field through Dennis 3-11 Completing 2013 and likely beyond • 2011 program economics: – D&C Costs: $3.8 - $6.5 MM – $1.54/Mcfe UDC Non-operated Recently Drilled Operated 3rd Qtr Well • Evaluating increasing our WI by acquisition 22 Sections with EROC operations Note: Reserve estimates based on Cawley Gillespie and UDC estimates based on management estimates. Average production rate is based on period beginning May 3, 2011, the date the Crow Creek Acquisition closed, and ending June 30, 2011. EROC Operated Rig

Cana Shale Play Drilling Activity • 54 rigs currently drilling horizontal wells in the trend in western Oklahoma – Shale characterized by dry gas to the southwest and oil to the northeast • Cana Shale net leasehold totals 13,100 acres – Majority of acreage in wet gas “window” Stidham 1-16H TD: 17,752’ – One operated rig contracted through 12/2012 – Participating (non-operated) in nine wells Helm 1-25H IP 2.6 MMCFD; p ) currently drilling • Majority of drilling activity conducted by large independent producers such as Devon and Continental 165 Bbls/d NGLs – Devon drilled 87 new wells in play in 2010, plans to drill over 200 wells in 2011 and recently completed construction of gas Johnson 1-14H Next Well 23 processing plant (1) (1) Based on Devon investor presentations and press releases.

Robust Drilling Economics • Exposure to liquids rich plays greatly enhances drilling economics in low gas price environment • Early development of Cana Shale shows a range of EURs, with attractive drilling economics in liquids rich portion of the play using conservative reserve levels • In the Golden Trend Field area, risk is minimized and reserve upside is greatly enhanced with multiple, 60 Golden Trend Economics Cana Shale Economics 60 , prolific pay zones extending from 8,000 – 15,000 feet 40 50 60 Return, % 5 BCF 6 BCF 7 BCF 40 50 Return, % 1.1 BCF 10 20 30 Internal Rate of 10 20 30 Internal Rate of 0 $3.00 $4.00 $5.00 $6.00 $7.00 Natural Gas Price, Henry Hub, $/MMbtu 0 $3.00 $4.00 $5.00 $6.00 $7.00 Natural Gas Price, Henry Hub, $/MMbtu 24 Note: Based on $85 per Bbl flat oil price deck and Eagle Rock management estimates.

Drilling Assumptions / Well Type Curves Golden Trend Type Curve Cana Shale Type Curve • $3.0 million completed well cost of.1 1 Bcfe Golden Trend Drilling Assumptions • $8.6 million completed well cost • EUR of 5-7 Bcfe Cana Shale Drilling Assumptions • 50 Bbl/MMcf Condensate; NGL yield of 80 Bbl/MMcf with 31% shrinkage • 1,000 Btu residue gas • Received natural gas price = Henry Hub less 0.6% • Received oil price = WTI less $5.00/Bbl • Received of 5-Bcfe • 10 Bbl/MMcf Condensate; NGL yield of 50 Bbl/MMcf with 20% shrinkage • 1,000 Btu residue gas • Received natural gas price = Henry Hub less 10% • Received oil price = WTI less $2.50/Bbl • Received = NGL price = WTI less 57% • Opex: $2,500/well/month NGL price less 50% • Opex: $3,500/well/month Note: These represent management's assumptions as to the performance of a typical well in these areas used in evaluating the Crow Creek Acquisition. They were based on the performance of certain wells (all of which were drilled by other oil and gas companies) in the areas, together with management's experience and estimates. In addition, the performance and costs of wells in these areas have shown substantial variance. There can be no guarantee that the actual costs or results of any well in these areas will match management's assumptions. Received NGL price = WTI less 50%

Woodford Shale – Potential Room to Run Eagle Rock acreage

Focus on Low Cost Operations 2.10 2.40 35 40 Crow Creek Legacy Assets Unit OPEX Upstream Historical and Projected Operating Costs (1) 1.20 1.50 1.80 20 25 30 l OPEX (MM$) Unit OPEX ($/Mcfe) 0.00 0 2008 2009 2010 2011E 2012E • Operating expense of the legacy assets driven by sulfur treating costs in 2010 - OPEX averaged $1.95/Mcfe - Included $ 2.3 million of plant turnaround ($ 1.78/Mcfe removing turnaround and Eustace shut-down impact) (2) p g p ) - Workover expense above normal levels • Mid-Continent assets have a conventional gas composition resulting in lower treating expense • Large, existing gathering infrastructure reduces producer gathering and compression expense • Mid-Continent assets improve the Partnership’s overall operating cost structure-New assets. $0.45/Mcfe (1) OPEX excludes production and ad valorem taxes. (2) Adjusted to reflect estimate of a full quarter of East Texas production (removing the impact of the Eustace processing facility shut-down). - Pro forma 2011 OPEX - $1.13/Mcfe 0.90 0.60 0.30 15 10 0

Upstream Organic Growth Production Growth Driven by Lower-Risk Drilling Inventory Eagle Rock Identified Locations PUD PROB Cana Shale 21 413 Golden Trend 36 2 180 120 Cana Mid-Con Conventional Legacy Anadarko 42 21 Arkoma 46 11 Barnett Shale 4 9 Verden 33 13 Other 28 0 TOTAL 210 469 90 135 60 90 Capital Capital ($ in MMs)(1) 4-Year Production CAGR = 30% 45 30 0 0 2008 2009 2010 2011E (2) 2012E (1) This capital spending is subject to the availability of adequate sources, including cash from operations, borrowings under our revolving credit facility and potentially the issuance of additional equity or debt securities. (2) Adjusted to reflect estimate of a full quarter of East Texas production (removing the impact of the Eustace processing facility shut-down). Average Production (MMcfe/d)

Eagle Rock is Well-Positioned for Continued Growth 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 organic growth opportunities in Granite Wash and expansion potential in Austin Chalk and Louisiana Balanced midstream / upstream platform widens opportunity Substantial drilling inventory (~680 drilling locations) focused in attractive basins including the Cana Shale and Golden Trend in Oklahoma Management’s expectation to recommend $1.00/unit distribution by end of 2012 (1) 29 (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.

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

Midstream: Panhandle System System Overview Map of Texas Panhandle System (1) • Miles of Pipeline: 3,963 • Processing Plants: 7 • Compression HP: 141,000 p , • 2Q11 Avg. Gathering Volume: 154 MMcf/d • 2Q11 Avg. Equity NGL / Condensate Volume: 4.7 Mbbl/d • 2011 Operating (2): $23.7 million Q2 Income : • Q2 2011 Capex: $7.9 million • Producing Formations: Granite Wash Morrow Brown Dolomite Cleveland Contract Mix by Throughput (3) Gross Margin (3) Fixed Fee 19% Fixed Fee 9% Commodity Based 81% Commodity Based 91% 31 (1) Includes planned installation and construction of Woodall Plant in Hemphill County. (2) Excludes Depreciation, depletion, amortization and impairment. (3) Based on December 2010.

Midstream: East Texas System System Overview Map of East Texas System • Miles of Pipeline: 1,213 • Processing Plants: 7 • Compression HP: 49,700 p • 2Q11 Avg. Gathering Volume: 192 MMcf/d • 2Q11 Avg. Equity NGL / Condensate Volume: 1.2 Mbbl/d • Q2 2011 Operating Income (1): $9.6 million 2011 • Q2 Capex: $1.5 million • Producing Formations: Austin Chalk James Lime Trend Travis Peak Haynesville Shale Cotton Valley Woodbine Contract Mix by Throughput (2) Gross Margin (2) Fixed Fee Fixed Fee 35% Commodity Based 65% 27% Commodity Based 32 (1) Excludes Depreciation, depletion and amortization. (2) Based on December 2010. 73%

Midstream: South Texas System System Overview Map of South Texas System • Miles of Pipeline: 266 • Processing JT Skids: 3 • Compression HP: 15,300 • 2011 Operating (1): $0.3million Q2 Income : 0.3 million • Q2 2011 Capex: $0.02 million Contract Mix by Throughput (2) Gross Margin (2) Producer Positioning Fixed Fee 74% Commodity Based 26% Fixed Fee 37% Commodity Based 63% Activity / Competitive • Major producers are Chesapeake and Sanchez Oil & Gas in South Texas • Activity has slowed due to lower natural gas prices commodity • Phase 1 20-inch provides lower pressure service with access to two competing processing plants for producers 33 (1) Excludes Depreciation, depletion, amortization and discontinued operations. (2) Based on December 2010.

Midstream: Gulf of Mexico System System Overview Gulf of Mexico System • Miles of Pipeline: 40 • Processing Plants: 2 (non-operated) • Compression HP: 14,180 • Q2 2011 Operating Income (1): $1.3 million • Q2 2011 Capex: $0.0 million Contract Mix by Throughput (2) Gross Margin (2) Fixed Fee 1% Commodity Based 99% Fixed Fee 14% Commodity Based 86% • Producer interests in approximately 115 blocks committed to life-of-lease contracts – Davy Jones discovery in shallow water covers of Eagle Rock’s Producer Activity / Competitive Positioning some 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 34 across the Gulf of Mexico (1) Excludes Depreciation, depletion and amortization. (2) Based on December 2010.

Mid-Continent: Upstream Asset • Acquisition Date: May 3, 2011 • Oklahoma Counties: Dewey, Blaine, Canadian, Caddo, Asset Overview Mid-Continent Properties Grady, Love, Marshall Coal, Pittsburg, Latimer • Texas Counties Tarrant, Ochiltree, Lipscomb • Arkansas Counties: Franklin, Johnson, Pope, Sebastian, Scott Logan, Crawford • Operated Producing Wells: 330 • Non-Op Wells: 1,063 • Net Acreage: 115,500 • Net Reserves: 123.4 MMboe (740.5 Bcfe) • Average Operated W.I.: 84% • Producing Formations: Woodford, Springer, Cleveland, Bromides • Gas Stream Composition: Various 2011 Objectives • Fully integrate the Crow Creek acquisition into the Eagle Rock Upstream business • Grow production on the Cana Shale leasehold and within the Golden Trend field with both operated and non-operated drilling and recompletion programs • Continue to acquire leasehold in the productive liquidsrich 35 rich window of the Cana Shale play and in the Golden Trend field area

Alabama: Upstream Asset • Acquisition Date: July 31, 2007 • Alabama Counties: Escambia, Choctaw • Operated Producing Wells: 29 • Wells: 2 Asset Overview Alabama Properties Non-Op • Net Acreage: 13,000 • Net Reserves: 10.9 MMboe (65.4Bcfe) • Average Operated W.I.: 73% • Producing Formations: Smackover, Norphlet • (+/-): 20% H2S Gas Stream Composition 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 Florida / Alabama State Border Net Production: • Gas Mcf/d: 3,578 • Oil Bo/d: 1,566 • NGLs Bl/d: 647 • Exploit behind-pipe zones in current wellbores • Continue to increase market flexibility for all products 2010 Operating Statistics 2011 Objectives • Sulfur LT/d: 169 • Total Mcfe/d: 16,798 (21% gas) Financial Summary • Revenue ($ in millions): $55.4 • Operating Expense ($ in millions) (1): $14.3 • Optimize gathering system to increase production • Reconfigure wells and install artificial lift to improve flow efficiencies • Improve SO2 recoveries at BEC and Flomaton facilities changing 36 • Unit Operating Expense ($/BOE) (1): $14.28 (1) Excluding taxes. to comply with emissions requirements

East Texas Smackover Trend Assets • Acquisition Date: July 31, 2007 • Texas Counties: Wood, Rains, Van Zandt, Henderson • 34 Asset Overview East Texas Properties Operating Producing Wells: • 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 • Exploit new Cotton Valley discovery with targeted drilling and well re-entries • 2010 Operating Statistics (1) 2011 Objectives • Sulfur LT/d: 103 • Total Mcfe/d: 9,876 (53% gas) Financial Summary • Revenue ($ in millions): $19.0 • Operating Expense ($ in millions) (2): $3.9 Improve well performance through well re configuration and artificial lift • Optimize compression to reduce wellhead pressures and increase production 37 • Unit Operating Expense ($/BOE) (2): $8.54 (1) Includes the Partnership’s Mississippi and South Texas operations. (2) Excluding taxes.

Permian Basin Assets Asset Overview Permian Basin Properties • Acquisition Date: April 30, 2008 • Texas Counties: Ward, Crane, Pecos • Operated Producing Wells: 186 21 • Non-Op Producing Wells: • 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 2010 Operating Statistics Net Production: • Gas Mcf/d: 1,563 • Oil Bo/d: 469 • NGLs Bl/d: 221 2011 Objectives • Exploit behind-pipe reserves in multiple horizons with low risk workovers • Evaluate CO2 flood • 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 tertiary potential • Target bolt-on acquisition opportunities 38 (1) Excluding taxes.

South Texas Upstream Assets Asset Overview South Texas Properties • 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 39 Note: South Texas operations included in East Texas operating statistics.

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. 40

Use of Non-GAAP Financial Measures 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. 41

Use of Non-GAAP Financial Measures (Continued) 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. 42

Adjusted EBITDA Reconciliation Adjusted EBITDA Reconciliation 2011 2010 2011 2010 June 30, June 30, Three Months Ended Six Months Ended ($ in thousands) ($ in thousands) Net cash flows provided by operating activities $6,059 $25,269 $25,693 $42,662 Add (deduct): Discontinued operations (311) 39,493 407 43,645 Depreciation, depletion, amortization and impairment (36,136) (30,599) (60,158) (58,043) Amortization of debt issuance costs (806) (551) (1,046) (820) Risk management portfolio value changes 71,202 37,051 19,769 45,707 derivative 2,443 323 2,443 628 Reclassing financing settlements 2,443 2,443 Other 2,273 (1,726) 1,128 (4,207) Accounts receivables and other current assets (18,434) (7,879) 5,483 (8,711) Accounts payable, due to affiliates and accrued liabilities 28,208 7,646 7,020 10,482 Other assets and liabilities 573 (884) 615 781 Net income (loss) $55,071 $68,143 $1,354 $72,124 Add (deduct): Interest (income) expense, net 10,856 9,163 19,354 18,465 Depreciation, depletion and amortization 36,136 30,599 60,158 58,043 Income tax (benefit) provision (691) (425) (733) 274 EBITDA $101,372 $107,480 $80,133 $148,906 Add (deduct): Risk management portfolio value changes (45,942) (37,051) 5,491 (45,707) Restricted unit compensation expense 1,024 1,550 1,934 3,358 Non-cash mark-to-76 (1,033) (16) (567) market Upstream imbalances Discontinued operations, net of tax 311 (39,493) (407) (43,645) Other income 90 21 90 (78) Other operating income (2,983) 0 (2,983) 0 ADJUSTED EBITDA $53,948 $31,474 $84,242 $62,267 Three Months Ended Six Months Ended June 30, June 30, 43 2011 2010 2011 2010 Amortization of commodity derivative costs -- $430 -- $3,078