Eagle Rock Energy Partners L P (EROC) 8-K Eagle Rock Energy Partners, L.P. “Moving Ahead” UBS 2010 MLP One-on-One Conference September 2010

Exhibit 99.1

Eagle Rock Energy Partners, L.P. “Moving Ahead” UBS 2010 MLP One-on-One Conference September 2010

2 The material that follows, as well as statements made by representatives of Eagle Rock during the course of this presentation, includes “forward-looking statements.” All statements, other than statements of historical facts, included in this material, or made during the course of this presentation, that address activities, events or developments that Eagle Rock 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 Eagle Rock in reliance on its experience and perception of historical trends, current conditions, expected future developments and other factors Eagle Rock believes are appropriate under the circumstances. Such statements are inherently uncertain and are subject to a number of risks, many of which are beyond Eagle Rock’s control. These include risks related to volatility of commodity prices; market demand for natural gas and natural gas liquids; the effectiveness of Eagle Rock’s hedging activities; Eagle Rock’s ability to retain key customers; Eagle Rock’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; Eagle Rock’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, Eagle Rock’s actual results and plans could differ materially from those implied or expressed by any forward-looking statements. Eagle Rock 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 Eagle Rock’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 Eagle Rock’s Form 10-K, filed with the Securities and Exchange Commission for the year ended December 31, 2009, 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 Senior Financial Analyst Management Representatives

Midstream Business Strategically Located, Diversified Asset Base 4 5,244 miles of pipeline 19 processing plants >510 MMcf/d gathering volumes 7.1 Mbbl/d equity NGLs / Condensates Midstream Business is exposed to prolific producing geological trends, specifically the Granite Wash, Austin Chalk and Haynesville Shale Upstream Business is weighted towards oil and NGL production, with 88% of reserves classified as proved developed, and is diversified among four low-cost, low-decline producing basins Upstream Business 260 operated producing wells 19.2 MMBoe proved reserves 5,275 Boe/d net production 71% Oil / NGLs by reserves Business Mix (1) Upstream Geographic Profile (2) Midstream Geographic Profile (2) (1) Based on LTM EBITDA PF for Minerals sale. (2) Based on 2Q 2010 EBITDA breakdown. East Texas / Louisiana 35% South Texas 4% Texas Panhandle 60% Gulf of Mexico 1% Permian 23% Alabama 44% South Texas 2% East Texas 31%

Moving Ahead: Creating Opportunity from Challenge 5 In July 2010, Eagle Rock substantially completed a recapitalization of the Partnership which delivered a number of benefits: Greater financial flexibility More unitholder-friendly governance structure Simplified ownership structure to include only common units and warrants convertible to common units Acquired general partner entities Reconstituted and expanded board to include a majority of independent directors Provide for election of independent directors Structural modifications to enhance returns to common units in growth scenarios (elimination of incentive distribution rights) Continued support from Natural Gas Partners as largest unitholder Initial proposal received from NGP Amended Global Transaction Agreement executed Received unitholder approval; completed Sale of Minerals Business; eliminated sub units/IDRs Launched and completed Rights Offering Exercised GP Acquisition Option; announced intent to recommend $0.60/unit annualized distribution

Recapitalization: Greater Financial Flexibility and Liquidity 6 In the midst of a difficult environment, Eagle Rock moved decisively to strengthen its balance sheet Since April 2009, the Partnership has repaid over $320 million of borrowing under its revolving credit facility $100 million of debt repayment from free cash flow $222 million of debt repayment from recapitalization transactions Debt Outstanding ($ in MMs) Commitment Availability ($ in MMs) (1) (1) Based on availability less $9.1 million in unfunded commitments from Lehman Brothers and $240,000 of outstanding letters of credit. Commitments reduced by $100 million on May 24, 2010 in conjunction with closing of sale of minerals business. Commitment availability may be limited by financial covenants. $837 $804 $774 $754 $737 $565 $515 $0 $100 $200 $300 $400 $500 $600 $700 $0 $100 $200 $300 $400 $500 $600 $700 $800 $900 1Q '09 2Q '09 3Q '09 4Q '09 1Q '10 2Q '10 July '10

7 Ownership Structure (pre-Recapitalization) Ownership Structure (as of 7/31/10) Eagle Rock Common 100% NGP/Affiliates Public 76% ~24% 100% Non-economic GP Interest GP Recapitalization: Structuring for Growth The Recapitalization dramatically simplified Eagle Rock’s structure: Elimination of subordinated units and incentive distribution rights; acquisition of general partner Greater alignment among all unitholders and enhanced growth potential NGP remains the largest unitholder (~24% ownership) Retain benefits of a relationship with a leading private equity firm Eagle Rock GP Subs Common 65% LP NGP/Affiliates Public Common 27% Sub 7% LP 1% GP

Eagle Rock is now well-positioned for growth 8 Strong credit profile and availability following recapitalization 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 Dual midstream / upstream platform widens opportunity set “Clean” structure enhances ability to partner for large projects Expect healthy coverage ratio on proposed $0.60/unit annual distribution

9 9 Overview of Midstream Business Panhandle 3,743 miles of pipeline 7 processing plants 131,000 compression HP 133 MMcf/d 2Q10 avg. gathering volume 5.5 Mbbl/d 2Q10 avg. equity NGL / Condensate volume East Texas / North Louisiana 1,195 miles of pipeline 7 processing plants 43,700 compression HP 211 MMcf/d 2Q10 avg. gathering volume 1.2 Mbbl/d 2Q10 avg. equity NGL / Condensate volume Gulf of Mexico 40 miles of pipeline 2 processing plants 14,180 compression HP 98 MMcf/d 2Q10 avg. gathering volume 0.3 Mbbl/d 2Q10 avg. equity NGL volume Processing Plant Haynesville Shale Austin Chalk Granite Wash South Texas 266 miles of pipeline 3 processing stations 14,700 compression HP 70 MMcf/d 2Q10 avg. gathering volume 0.2 Mbbl/d 2Q10 avg. equity NGL / Condensate volume Deep Bossier / Angelina River Trend

Liquids-Rich Wells Offer Greater Economics 10 Dry Gas Well vs. Liquids-Rich Gas Well Economics (1) Wellhead Btu Content 1,000 (0.0 GPM ) Wellhead Btu Content 1,180 (4.2 GPM) Wellhead Btu Content 1,096 (3.3 GPM) Wellhead Btu Content 1,501 (9.1 GPM) (1) Based on June 2010 prices. Higher producer netbacks due to liquids upgrade support sustained drilling activity on Eagle Rock systems Well Head Price $4.27 Well Head Price $4.04 Well Head Price $4.36 Well Head Price $4.04 Liquids Upgrade $1.39 Liquids Upgrade $1.38 Liquids Upgrade $4.72 BTU Equivalent Gas Price $4.27 BTU Equivalent Gas Price $5.43 BTU Equivalent Gas Price $5.74 BTU Equivalent Gas Price $8.76 Dry Shale Gas Wells Granite Wash Wells (East Panhandle) Austin Chalk Wells (Brookeland System) West Panhandle Wells

11 11 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 2010 System Activity: Proven horizontal drilling potential in Granite Wash and Colony Wash Average EUR of approximately 6.0 Bcfe Initial production for first 30 days has averaged 6-10 MMcfe/d 18 new wells connected or drilling through August 2010 Two wells preparing to spud Panhandle Daily Gathering Volumes MMcfe/d Converting “Wet Gas” System to “Dry Gas” System Proven horizontal drilling potential in Granite Wash and Colony Wash Average EUR of approximately 6.0 Bcfe Initial production for first 30 days has averaged 6-10 MMcfe/d 48 total rigs currently running in the Granite Wash (42 horizontal rigs), includes Roberts, Hemphill and Wheeler Counties Connecting Pipeline from Roberts County System to Red Deer Plant 0 25 50 75 100 125 150 175

12 12 Panhandle: Building a “Super-System” Existing Arrington Plant (2009) New Phoenix Plant Plant Efficiency Technology Lean-Oil Cryogenic Ethane (C2) Recovery % 24% 80%+ Propane (C3) Recovery % 84% 90%+ Eagle Rock is in the process of deploying a new cryogenic processing plant to replace the existing Arrington lean oil plant in the East Panhandle Initially configured to process up to 50 MMcf/d, readily expandable to 80 MMcf/d with additional compression Enables movement of volumes between multiple plants in the East Panhandle System (130 MMcf/d total capacity reaching 47% of Granite Wash fairway) Phase II of Texas Panhandle consolidation and processing expansion project originally announced in February 2008 Plant Overview Enhanced Recoveries Growth Opportunities New plant will consolidate volumes across East Panhandle and significantly enhance ethane and propane recoveries from growing Granite Wash production Combination of Red Deer, Canadian and Phoenix plants into a “super-system” with 130 MMcf/d capacity Converting “dry-gas” system in Wheeler County to “wet-gas” system to accommodate increased drilling and gas production Constructing pipeline to connect gas from Roberts County system into Red Deer plant / “super-system” Condensate and marketing logistics/opportunities Additional bolt-on organic expansion and acquisition opportunities

13 13 System Overview Strategic Positioning Strategic Footprint in East Texas East Texas Gathering Volumes Growth Opportunities: Renewed drilling activity in Austin Chalk ETML and BGS systems continue to see new drilling activity into the James Lime and Travis Peak formations Evaluating ETML expansion Brookeland system is well-positioned in Austin Chalk trend with large life-of-lease commitments creating a hurdle to new midstream entrants ETML system provides multiple market outlets and lower gathering pressures than do competitors in the area Haynesville Shale development continues to expand in the direction of ETML/BGS with over 13,000 acres dedicated under life-of-lease agreements MMcfe/d 0 50 100 150 200 250 300

14 14 System Update: Haynesville Shale: Continue to monitor drilling activity as it continues to move closer to our acreage Austin Chalk: Play moving east into Louisiana – expect results later in 2010 Currently, four rigs running on acreage dedicated to us 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 15-20 MMcf/d range Haynesville Shale Angelina River Trend Austin Chalk East Texas: Serving Multiple Plays Potential Area of ETML Expansion 1 planned well with 20 potential sites – large independent Nacogdoches/San Augustine Counties: 15+ rigs running in area; Avg. IP 13-21 MMcf/d Large independent staked well; currently 2 rigs running in area Source: SEC filings and Partnership investor presentations. Rig Activity

Alabama Assets (1) 29 Op Producing wells 73% Avg. W.I. 2,660 Boe/d 78% Oil / NGLs (2) 197 LT/d (sulfur) 8.1 MMBoe Proved Reserves Permian Assets (1) 186 Op Producing wells 96% Avg. W.I. 812 Boe/d 70% Oil / NGLs (2) 5.3 MMBoe Proved Reserves South Texas Assets (1) 11 Op Producing wells 100% W.I. 436 Boe/d 6% Oil (2) 1.1 MMBoe Proved Reserves East Texas Assets (1) 34 Op Producing wells 83% W.I. 1,367 Boe/d 68% Oil / NGLs (2) 132 LT/d (sulfur) 4.8 MMBoe Proved Reserves Total Upstream Assets (1) 260 Operated Producing wells 147 OBO Wells (3% Avg. W.I.) 5,275 Boe/d 68% Oil / NGLs (2) 273 LT/d (sulfur) (3) 19.2 MMBoe Proved Reserves 10 year R/P (4) 15 (1) As of year end December 31, 2009. (2) Based on production. (3) Based on July daily production rate. (4) Total proved reserves / 2009 production. Geographically Diverse Upstream Assets

2009 Reserves by Area 2009 Reserves by Type 2009 Reserves by Commodity 2009 Production by Area 16 Overview of Upstream Business Total: 5,275 Boe/d Total: 19.2 MMBoe NGLs 32% Natural Gas 29% Oil 39% South Texas 6% Alabama 42% Permian 27% East Texas 25% South Texas 8% Permian 15% Alabama 51% East Texas 26% PUD 2.3 MMBose 12% PDNP 2.3 MMBose 12% PDP 14.6 MMBose 76%

17 17 Performance Highlights Unit Operating Cost ($/Boe) Boe/d Since 2007, Eagle Rock’s Upstream Business has maintained a steady daily production rate, while lowering unit operating costs by 21% and 14% in 2008 and 2009, respectively Maintained production at approximately 5.3 Mboe/d during 2009 despite unexpected compression downtime at BEC facility 2009 Drilling Program Achieved 81% rate of return on $6.2 million of well capital projects in 2009, including three new wells and ten workovers Unit Development Cost of $6.00/Boe (down from $9.10/Boe in 2008) Continued to improve operating metrics since entrance into the upstream segment 2009 Unit Operating Expense (UOE) of $9.60/Boe 2010 UOE higher due to higher service costs and extended shut-down of Eustace plant in East Texas (3rd party processing) Maintaining Production, Lowering Cost Upstream Production Volumes/Unit Operating Costs 3,485 3,081 2,677 2,965 1,823 1,767 1,773 1,629 589 827 1,077 5,308 5,437 5,276 5,671 $14.10 $11.16 $9.60 $12.04 $6.00 $10.00 $14.00 $18.00 - 1,000 2,000 3,000 4,000 5,000 6,000 2007 2008 2009 2010E Permian ETX/STX/MS/OBO Alabama

18 18 Robust 2010 Capital Program Boe/d Capital Program ($ in MM) Eagle Rock’s 2010 drilling and recompletion budget is one of the largest since the Partnership entered the Upstream business in 2007 Permian drilling program includes six new wells in 2010 (all six wells have been drilled) Recompletion and workover programs in all operating areas yield a strong rate of return Eagle Rock targets a 25% rate of return on upstream projects Recently completed plant turnaround at Big Escambia Creek provides improved runtime reliability to our largest asset 2010E Capex by Region 2010E Capex by Type 2010E Capital Upstream Production / Capital Expenditures Drilling $9.7 MM 36% Plant $3.7 MM 14% Workover $8.5 MM 31% Equipment $0.8 MM 3% Acquisitions $4.2 MM 16% Alabama $11.9 MM 44% East Texas $1.2 MM 4% South Texas $1.8 MM 7% Permian $12.0 MM 45%

Hedging Philosophy The Partnership targets hedging levels of approximately 80% of expected future hedgeable volumes in the current year and 50% to 80% in the following two years Expected future hedgeable liquids volumes currently hedged in excess of 80% in 2010 and 2011 given recent commodity price volatility Mission: Engage in non-speculative hedging activities to reduce the impact that future changes in commodity prices might have on cash flow 19 2010 Hedge Activity Aug 4: 50,000 MMBtu/mo Cal. 2013 Henry Hub swap at $5.645/MMBtu Aug 3: 23,000 Bbl/mo 2H 2011 WTI swap at $86.20/Bbl Aug 3: 29,000 Bbl/mo 1H 2011 WTI swap at $86.20/Bbl Jul 23: Adjusted 45,000 Bbl/mo 8/31/10-12/31/10 swap price to market ($79.80/Bbl) Jun 18: 17,000 Bbl/mo Cal. 2011 WTI swap at $83.30/Bbl Apr 19: 60,000 Bbl/mo Cal. 2013 WTI swap at $89.85/Bbl Apr 9: 20,000 Bbl/mo Cal. 2013 WTI swap at $90.20/Bbl Feb 17: 16,000 Bbl/mo Cal. 2012 WTI collar at $75.00-$94.75/Bbl Feb 16: 12,000 Bbl/mo Cal. 2011 WTI collar at $75.00-$89.85/Bbl

Wtd. Avg. Price ($/bbl) Wtd. Avg. Price ($/MMbtu) Hedging Profile: Rolling Off Below-Market Hedges Ethane and Natural Gas (1) Crude, Condensate and NGLs (>C3) (1) Percent of Hedgeable Volumes Hedged Percent of Hedgeable Volumes Hedged Prices shown reflect weighted average price of swaps and collar floors and exclude price impact of direct product hedges. Based on $75/Bbl oil and $4.50/Mcf natural gas price deck. $70.52 $76.88 $76.90 $89.74 $6.72 $6.92 $6.92 20 $5.65 Remainder of 2010 is being impacted by below-market hedges, which roll off prior to 2011 Hedging Benefit / (Loss) (2) ($ in MMs) ($5.8) ($1.0) $0.6 $3.7 $3.7 $3.5 $3.5 ($8) ($6) ($4) ($2) $0 $2 $4 2Q '10 3Q '10E 4Q '10E 1Q '11E 2Q '11E 3Q '11E 4Q '11E 47% 65% 70% 92% 46% 61% 90% 96% 0% 20% 40% 60% 80% 100% 2010 2011 2012 2013 Q1 2010 Q2 2010 $65.74 $74.46 $76.90 $70.52 $76.88 $76.88 $89.74 $89.94 8% 66% 70% 77% 54% 59% 78% 0% 20% 40% 60% 80% 100% 2010 2011 2012 2013 Q1 2010 Q2 2010 $6.70 $6.90 $6.90 $6.72 $6.92 $6.92 $5.65

21 Partnership Highlights Strong Credit Profile and Simplified Structure Enhance Growth Potential Excellent Organic Growth Opportunities in Core Areas Acquisition Opportunities in One or More Business Segments Well-positioned Asset Base Located in Mature, Growing Basins Diversified Business Model Contributions from dual business lines across energy value chain Strong, Experienced Management Team

Appendix 22

23 23 Eagle Rock Credit Facility Senior secured revolving credit facility with total availability of $356 million (1) from 19 financial institutions Total Borrowings $820 million Pricing: LIBOR + 187.5 bps Borrowing Base Compliance Tests Supported by all Upstream properties Borrowing Base redetermined, effective April 1, 2010, at $130 million Next redetermination date on October 1, 2010 Supported by Midstream Business Compliance tests are based on Midstream EBITDA and non-borrowing base debt Bank Covenants(3): Covenant Q2 2010 Total Leverage Ratio: < 5.00x 3.55x Interest Coverage Ratio: > 2.50x 4.68x Total Borrowings: $515.4 million (2) Pricing: LIBOR + 175 bps Maturity: 12/13/2012 $130 million $385.4 million (2) (1) Commitments reduced by $100 million in conjunction with Minerals Business sale on 5/24/10; $9.1 million in unfunded commitments from LEH. (2) As of 7/31/10. Includes $50 million debt repayment from proceeds of Rights Offering. (3) As of Q2 2010 compliance calculations.

24 Active Commodity Risk Management Combination of contract mix and hedge portfolio results in limited commodity sensitivity Fixed fee contracts comprised 11% of volume in 2007, increasing to 35% as of June 2010 Over 80% of expected volumes hedged for 2010E As of June 2010; based on volume. Based on Partnership’s estimate of future hedgeable volumes. Based on Partnership’s estimate of 2010E gross margin. 24 $70.52 $6.72 Commentary 2010E Commodity Exposure (3) 2010E Hedging Levels (2) Current Midstream Contract Mix (1) Percent of Hedgeable Volumes 96% 78% 0% 20% 40% 60% 80% 100% Oil Gas Unhedged Hedged Keepwhole 6% Fee-Based 35% % of Proceeds / Fixed Recovery 59%

25 System Overview Map of Texas Panhandle System Midstream: Panhandle System Miles of Pipeline: 3,743 Processing Plants: 7 Compression HP: 131,000 2Q10 Avg. Gathering Volume: 133 MMcf/d 2Q10 Avg. Equity NGL / Condensate Volume: 5.5 Mbbl/d 2009 Operating Income (1): $55.1 million 2009 Capex: $7.3 million Producing Formations: Granite Wash Morrow Brown Dolomite Cleveland (1) Excludes G&A, impairment expense, and discontinued operations. Based on June 2010. Contract Mix by Throughput (2) Gross Margin (2) Gross Production Metrics (Q2 2010) East Panhandle: 4 Plants 96 MMcf/d 4.9 MBbl/d West Panhandle: 3 Plants 37 MMcf/d 7.8 MBbl/d Fixed Fee 12% Commodity Based 88%

26 26 System Overview Map of East Texas System Midstream: East Texas System Miles of Pipeline: 1,195 Processing Plants: 7 Compression HP: 43,700 2Q10 Avg. Gathering Volume: 211 MMcf/d 2Q10 Avg. Equity NGL / Condensate Volume: 1.2 Mbbl/d 2009 Operating Income (1): $28.6 million 2009 Capex: $18.2 million Producing Formations: Austin Chalk James Lime Trend Travis Peak Haynesville Shale Cotton Valley Woodbine (1) Excludes G&A, impairment expense, and discontinued operations. Based on June 2010. Contract Mix by Throughput (2) Gross Margin (2) Gross Production Metrics (Q2 2010) East Texas: 211 MMcf/d 6.3 MBbl/d Fixed Fee 80% Commodity Based 20%

27 27 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 and FIML on the Wildhorse System Acquired Wildhorse System as part of Millennium Midstream Partners in October 2008 Wildhorse System is primarily low-decline Canyon Sands production Activity has slowed due to lower 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: 14,700 2009 Operating Income (1): $5.3 million 2009 Capex: $0.1 million (1) Excludes G&A, impairment expense, and discontinued operations. Based on June 2010. Contract Mix by Throughput (2) Gross Margin (2) Fixed Fee 65% Commodity Based 35%

28 28 System Overview Gulf of Mexico System Midstream: Gulf of Mexico System Miles of Pipeline: 40 Processing Plants: 2 (non-operated) Compression HP: 14,180 2009 Operating Income (1): $5.4 million 2009 Capex: $0.4 million Producer interests in approximately 115 blocks committed to life-of-lease contracts Davy Jones discovery in shallow water covers some of our 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. Based on June 2010. Contract Mix by Throughput (2) Gross Margin (2) Producer Activity / Competitive Positioning Fixed Fee 1% Commodity Based 99% Fixed Fee 1% Commodity Based 99%

29 29 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: 8.1 MMboe (48.3 Bcfe) 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 MMcf/d: 3.5 Oil Bo/d: 1,508 NGLs Bl/d: 577 Sulfur LT/d: 197 Total BOE/d: 2,660 (78% Oil / NGLs) Financial Summary Revenue ($ in millions): $32.4 Operating Expense ($ in millions) (1): $11.5 Unit Operating Expense ($/BOE) (1): $11.89 Florida / Alabama State Border (1) Excluding taxes. Continue to invest in plant reliability Completed turnaround in May 2010 Production back to >3,000 Boe/d Restore production to legacy shut-in wells Exploit Smackover behind pipe potential in Norphlet fields Establish alternative condensate markets to improve netback pricing Asset Overview Alabama Properties 2009 Operating Statistics 2010 Objectives

30 30 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: 4.8 MMboe (29.0 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 MMcf/d: 2.7 Oil Bo/d: 309 NGLs Bl/d: 616 Sulfur LT/d: 132 Total BOE/d: 1,367 (68% Oil / NGLs) Financial Summary Revenue ($ in millions): $15.6 Operating Expense ($ in millions) (1): $3.1 Unit Operating Expense ($/BOE) (1): $6.13 (1) Excluding taxes. Sustain base production performance Long-life, low-decline assets Production held flat overall since 2007 Exploit new Cotton Valley discovery with targeted drilling and well re-entries Achieve fuel savings through joint projects with the plant operator, Tristream Energy Asset Overview East Texas Properties 2009 Operating Statistics 2010 Objectives

31 31 Asset Overview Permian Basin Properties 2009 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: 5.3 MMboe (31.6 Bcfe) Average Operated W.I.: 96% Producing Formations: Yates, Queen, San Andres, Wichita Albany, Holt, Wolfcamp and Penn Net Production: Gas MMcf/d: 1.4 Oil Bo/d: 382 NGLs Bl/d: 190 Total BOE/d: 812 (70% Oil / NGLs) Financial Summary Revenue ($ in millions): $11.6 Operating Expense ($ in millions) (1): $4.2 Unit Operating Expense ($/BOE) (1): $14.18 (1) Excluding taxes. 2010 Objectives Drill six wells in 2010 $9.00/Boe development cost Anticipate 1,200 Boe/d in 2010 Exploit behind-pipe reserves in multiple horizons with low risk workovers Evaluate tertiary CO2 flood potential Target bolt-on acquisition opportunities

32 Asset Overview South Texas Properties 2009 Operating Statistics Upstream: South Texas Acquisition Date: July 31, 2007 Texas Counties: Atascosa Operating Producing Wells: 11 Net Acreage: 1,400 Net Reserves: 1.1 MMboe (6.7 Bcfe) Average Operated W.I.: 100% Producing Formations: Edwards Successful re-completion program conducted in 2008 with infill drilling locations identified for future development Net Production: Gas MMcf/d: 2.5 Oil Bo/d: 24 Total BOE/d: 436 Financial Summary Revenue ($ in millions): $3.9 Operating Expense ($ in millions) (1): $1.7 Unit Operating Expense ($/BOE) (1): $10.62 (1) Excluding taxes. Acreage is well-positioned in the “wet” gas window of the Eagleford Shale Evaluating options to exploit resource

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, 2009 2008 2007 2006 Net Income (loss) ($171,258) $87,520 ($145,634) ($23,314) Add: Interest (income) expense, net 41,349 38,260 44,587 30,383 Depreciation, depletion, amortization and impairment 138,324 291,605 86,308 43,220 Income tax provision (benefit) 1,087 (1,134) 158 1,230 EBITDA $9,502 $416,251 ($14,581) $51,519 Add: Income from discontinued operations (290) (1,764) (1,130) 0 Risk management portfolio value changes 177,061 (180,107) 144,176 23,531 Restricted unit compensation expense 6,685 7,694 2,395 142 Other income (2,328) (5,328) (696) 0 Other operating expense (3,552) 10,699 2,847 6,000 Non-cash mark-to-market of Upstream imbalances 1,505 841 0 0 Non-recurring operating items 0 0 (795) 0 Adjusted EBITDA $188,583 $248,286 $132,216 $81,192 Year Ended December 31, 2009 2008 2007 2006 Amortization of commodity derivative costs $48,363 $13,288 $8,224 $19,227