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Eagle Rock Energy Partners, L.P. IPAA Oil and Gas Investment Symposium April 2010 IPAA Oil and Gas Investment Symposium April 2010

Joseph A. Mills Chairman & Chief Executive Officer Jeffrey P. Wood Senior Vice President & Chief Financial Officer Adam K. Altsuler Senior Financial Analyst Management Representatives

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. 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

Eagle Rock (NASDAQ: EROC) is an MLP with three complementary energy businesses well- positioned to benefit from some of the most prolific producing basins in the U.S. Enterprise Value: $1.2 billion (1) 2009 Adj. EBITDA (2): $189 million Business Segments: Midstream: We gather and process natural gas from top tier producers in Texas and Louisiana Exposure to the Haynesville Shale, active in Austin Chalk (East Texas) and Granite Wash (Texas Panhandle) Upstream: We operate in four low-cost, low-decline producing regions in Texas and Alabama Attractive inventory of new drilling opportunities Minerals: We receive royalty income with no associated operating costs or capital requirements New drilling activity drives underlying production growth ("re-generation" effect) Significant exposure to the Haynesville Shale Introduction to Eagle Rock Energy Partners, L.P. (1) As of April 6, 2010. Subordinated units are valued at common unit price. (2) See Appendix for definition of Adjusted EBITDA. Texas Panhandle Midstream Assets East Texas / Louisiana Midstream Assets West Texas / South Texas Midstream Assets Gulf of Mexico Midstream Assets

Company Highlights 2009 Year in Review 2010 Plans Achieved $188.6 million of Adjusted EBITDA Repaid $83 million of outstanding borrowings under credit facility from May to end of year Entered into agreements with Natural Gas Partners and Black Stone Minerals to simplify structure and enhance liquidity Successfully executed cost-cutting initiatives Lowered Midstream unit operating expense by 21%, from $0.33/Mcfe in 2008 to $0.26/Mcfe in 2009 Lowered Upstream unit operating expense by 14%, from $11.16/Boe in 2008 to $9.60/Boe in 2009 Gathered gas from first Haynesville well via Belle Bower gathering system located in North Louisiana Continued to reduce commodity exposure by swapping into direct NGL product hedges Will hold Special Meeting on May 14th to approve the Recapitalization and Related Transactions Deploying a currently idle high-efficiency cryogenic plant (the Phoenix Plant) to the Texas Panhandle The new plant will consolidate volumes across the East Panhandle system and significantly enhance ethane and propane recoveries from growing Granite Wash production Possible expansion of East Texas assets to gather additional Haynesville production Robust drilling program in Permian Basin Seek appropriate entry point for issuing debt * Re-establish more meaningful distribution by year-end * _________________ * Assumes completion of Recapitalization and Related Transactions discussed on following pages.

Enhancing Unitholder Value Through Debt Reduction Eagle Rock has paid down $100 million of debt since April of 2009, slightly ahead of management's stated target at the time of the distribution cut Redirecting cash flow has allowed the Partnership to remain in compliance with its credit facility covenants and maintain its attractive borrowing cost Since the distribution cut in Q2 of 2009, Eagle Rock's total debt as a % of total enterprise value has fallen from 77% to 60% Total Debt as a % of EVA (1) Total Debt ($ in Millions) (1) Subordinated units are valued at common unit price as of the end of the period.

Proposed Recapitalization Further Enhances Liquidity... Note: Please see Definitive Proxy filed on March 30, 2010 for additional details on the Recapitalization and Related Transactions. (1) Assumes completion of Recapitalization and Related Transactions. Up to $230 million of cash proceeds in the near-term for debt repayment and/or organic growth Selling Minerals Business to Black Stone Minerals for $174.5 million Have certain commitments from Natural Gas Partners to purchase equity Greater access to capital markets Equity: Simplified structure is more unitholder-friendly and easier to understand Debt: Improved credit profile and unitholder alignment Improved liquidity should accelerate ability to pay a more meaningful distribution (1) Interim annualized distribution of $0.40 to $0.60 per unit with respect to Q4 of 2010 New long-term distribution policy to be implemented upon achieving full debt reduction objectives - estimate 2011

Structural modifications result in a single class of equity (1) Subordinated units, GP units and IDRs are surrendered in exchange for a transaction fee Greater alignment of interests among all unitholders Reconstituted board of directors (1) Two new independent board members will be added, increasing total number of seats to nine Common unitholders that are not affiliated with Natural Gas Partners will be entitled to elect a majority (5) of Eagle Rock's board of directors NGP will remain the largest unitholder (pro forma ~25-49% ownership) ....and Simplifies Structure Note: Please see Definitive Proxy filed on March 30, 2010 for additional details. Assumes exercise of GP Acquisition Option. Eagle Rock GP Subs Common Before (as of 12/31/09) Eagle Rock Common Pro Forma EROC (1) 100% 1.1% GP 90.6% 9.4% NGP/Affiliates Public NGP/Affiliates Public ~51-75% ~25-49% GP 100% 72.3% LP 26.7% Sub

Historical Performance and Growth Adjusted EBITDA ($ in Millions) (1) Daily Gathering Volumes (MMcfe/d) Upstream Volumes (2) Minerals Volumes (3) 38% CAGR 32% CAGR (1) See Appendix for a definition of Adjusted EBITDA and a reconciliation to GAAP net income (loss). (2) Includes operations from Escambia and Redman acquisitions beginning on August 1, 2007. (3) Includes operations from the Montierra Acquisition beginning on May 1, 2007 and from the MacLondon Acquisition beginning on July 1, 2007.

Overview of Midstream Business Panhandle 3,743 miles of pipeline 7 processing plants 131,000 compression HP 139 MMcf/d 2009 average volume East Texas / North Louisiana 1,195 miles of pipeline 7 processing plants 43,700 compression HP 249 MMcf/d 2009 average volume Gulf of Mexico 40 miles of pipeline 2 processing plants 14,180 compression HP 117 MMcf/d 2009 average volume Processing Plant Haynesville Shale Austin Chalk Granite Wash South Texas 266 miles of pipeline 3 processing stations 14,700 compression HP 83 MMcf/d 2009 average volume

Panhandle: New Phoenix Processing Plant Eagle Rock will now be able to move volumes between multiple plants on its East Panhandle System; the system has a total capacity of 136 MMcf/d and reaches approximately 47% of the Granite Wash Play Deployment of the Phoenix Plant is Phase II of Eagle Rock's Texas Panhandle consolidation and processing capacity expansion project originally announced in February of 2008 Existing Arrington Plant (2009) New Phoenix Plant Plant Efficiency 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 currently idle high-efficiency cryogenic plant to the East Texas Panhandle Phoenix will initially be configured to process up to 50 MMcf/d and will be easily expandable to 80 MMcf/d with additional compression 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

System Update: Haynesville Shale: In active discussions with a number of producers regarding extending systems Austin Chalk: Recently spent $3.5 million in growth capital in 2009 to capitalize on new drilling opportunities Last four producer wells reported average IP of approximately 12 MMcf/d Deep and Middle Bossier: Producers planning wildcats this year for the play East Texas / North Louisiana Volumes Haynesville Shale Angelina River Trend Austin Chalk East Texas: Serving Multiple Plays East Texas: Serving Multiple Plays EROC Minerals MMcfe/d 393% Increase

Total Upstream Assets (as of 12/31/09): Proved Reserves: 19.2 MMBoe (115.5 Bcfe) % PDP: 88% Producing Wells: 260 gross operated; 147 non-operated Net Production: 5.3 MBoe/d (31.9 MMcfe/d) R/P: ~10 years 2009 UDC: $6.00 / Boe ($1.00 / Mcfe) 2009 Opex: $9.60 / Boe ($1.60 / Mcfe) Eagle Rock's upstream assets consist of long-life, diversified reserves with a high percentage of PDP Overview of Upstream Business Geographic Diversification Price Exposure Weighted to Oil East Tx 1,367 Boe/d Alabama 2,660 Boe/d Permian 812 Boe/d South TX 436 Boe/d 34 Producing Wells; 83% Avg. W.I. 11 Producing Wells; 100% Avg. W.I. 29 Producing Wells; 73% Avg. W.I. 186 Producing Wells; 96% Avg. W.I.

Upstream: 2009 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 capital projects in 2009, including three new wells and ten workovers Continued to improve operating metrics with Unit Operating Expense of $9.60/Boe Unit Development Cost of $6.00/Boe Maintaining Production, Lowering Cost Upstream Production Volumes/Unit Operating Costs

Upstream: Robust 2010 Drilling Program Boe/d Capital Program ($ in MM) Upstream Production Volumes/Capital Expenditures 2010E Drilling Program Eagle Rock's 2010 drilling and recompletion budget is one of our largest since the Partnership entered the Upstream business in 2007 Budgeted $19.5 million of total capex for 2010 Permian Drilling: $6.1 million Recompletions/Workovers: $8.0 million BEC Compression/Maintenance: $3.3 million Other: $2.1 million

Overview of Minerals Business Total Minerals Assets (as of 12/31/09): Proved Reserves: 3.7 MMboe % PDP: 100% # of Wells: > 2,800 Oil / Gas %: 78% / 22% Net Acres: ~430,000 Avg. Daily Production: 1.1 MBoe/d Permian / Upper Gulf Coast / Mid Continent Numerous fields Generated $14 million of leasing bonuses in 2008 Significant potential upside in Haynesville Shale play LA Basin (Brea Olinda Field) Most significant individual contributor to current royalty income 100% crude production with very low decline rate Eagle Rock's Minerals Business offers diversification, stability and upside

Hedging Update (1) Prices shown reflect average price of crude hedges and exclude price impact of direct product hedges. (2) Prices shown reflect average price of natural gas hedges and exclude price impact of direct ethane hedges. (1) (2) 0% 0%

Investment Highlights Diversified Business Model Contributions from multiple business lines across energy value chain Well-positioned Asset Base Located in Mature, Growing Basins Focused on growing in East Texas / Texas Panhandle - Midstream Focused on growing in West Texas / Alabama - Upstream Excellent Organic Growth Opportunities in Core Areas Potential Liquidity-Enhancing Recapitalization on the Horizon Unitholder vote May 14th Acquisition Opportunities in One or More Business Segments Strong, Experienced Management Team

Appendix

Eagle Rock Credit Facility Senior secured revolving credit facility with total commitments of $971 million from 19 financial institutions Total Borrowings $820 million Pricing: LIBOR + 187.5 bps Borrowing Base Compliance Tests Supported by all Upstream properties Currently undergoing semi-annual re- determination (negotiated process with banks) Supported by Midstream and Minerals Businesses Compliance tests are based on Midstream and Minerals Adjusted EBITDA and allocated debt Bank Covenants: (as of 12/31/09) Leverage Ratio: < 5.0x 4.56x Interest Coverage Ratio: > 2.5x 4.66x Management anticipates continued covenant pressure given current commodity price environment Total Borrowings: $737 million (1) Pricing: LIBOR + 187.5 bps $135 million $602 million (1) (1) As of March 31, 2010. Includes $17 million of debt repayment since 12/31/09.

Contract Mix (12/31/09 Throughput Volumes) Midstream Contract Mix Eagle Rock has a well-balanced mix of fee-based and commodity-based contracts Contract Mix (Jan-Dec 2009 Margin) 2010 Commodity Exposure (1) (1) Based on company estimates.

System Overview Map of Texas Panhandle System Producer Activity Midstream: Panhandle System Miles of Pipeline: 3,743 Processing Plants: 7 Compression HP: 131,000 Contract Mix (1): Fixed Fee 15% Commodity-based 85% 2009 Operating Income (2): $55.1 million 2009 Capex: $7.3 million Producing Formations: Granite Wash Morrow Brown Dolomite Cleveland New Phoenix Plant replacing the older, less-efficient Arrington Plant Will add up to 50 MMcf/d of new capacity to handle growing Granite Wash production Major producers are BP, Cimarex, Cordillera, Chesapeake, Chevron and Excel Production Gathered volumes have remained relatively flat for last 3 years West Panhandle is a rich gas (average 8 GPM) on a shallow annual decline of ~9% East Panhandle is a leaner gas (average 3 GPM) with growing volumes Granite Wash is the primary driver of volume growth in the East Panhandle Horizontal drilling being applied with encouraging results (average IPs of 6 to 10 MMcf/d) (1) As of December 31, 2009. (2) Excludes impairment expense and discontinued operations.

System Overview Map of East Texas System Producer Activity Midstream: East Texas System Miles of Pipeline: 1,195 Processing Plants: 7 Compression HP: 43,700 Contract Mix (1): Fixed Fee 41% Commodity-based 59% 2009 Operating Income (2): $28.6 million 2009 Capex: $18.2 million Producing Formations: Austin Chalk James Lime Trend Travis Peak Haynesville Shale Cotton Valley Woodbine Austin Chalk play is major driver in near-term future volume growth in Brookeland system with seven additional wells scheduled for 2010 East Texas Main Line (ETML) System continues to see drilling activity into the James Lime and Travis Peak formations Current Belle Bower system throughput of 34 MMcf/d of Haynesville Shale production with expansion to accommodate 70 MMcf/d underway ETML system under review regarding expansion to handle additional Haynesville potential in Nacogdoches and San Augustine counties Major producers are Anadarko Petroleum, Encana Oil & Gas Inc., XTO Energy, Inc., Ergon Exploration Inc. and Goodrich Petroleum Corporation (1) As of December 31, 2009. (2) Excludes impairment expense and discontinued operations.

System Overview Map of South Texas System Producer Activity 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 Miles of Pipeline: 266 Processing JT Skids: 3 Compression HP: 14,700 Contract Mix (1): Fixed Fee 99% Commodity-based 1% 2009 Operating Income (2): $5.3 million 2009 Capex: $0.1 million (1) As of December 31, 2009. (2) Excludes impairment expense and discontinued operations.

System Overview Gulf of Mexico System Producer Activity Midstream: Gulf of Mexico System Miles of Pipeline: 40 Processing Plants: 2 (non-operated) Compression HP: 14,180 Contract Mix (1): Fixed Fee 8% Commodity-based 92% 2009 Operating Income (2): $5.4 million 2009 Capex: $0.4 million Approximately 115 blocks committed to life-of-lease contracts Davy Jones discovery in shallow water covers some of our committed leases Volumes restored since curtailment due to damage from Hurricane Ike and Gustav Major producers are Stone Energy and McMoran Exploration Contracts are life-of-lease commitments and typically percent of proceeds with fixed floors (1) As of December 31, 2009. (2) Excludes impairment expense and discontinued operations.

Asset Overview Permian Basin Properties 2009 Operating Statistics Upstream: Permian Basin Acquisition Date: April 30, 2008 Texas Counties: Ward, Crane, Pecos Producing Wells: 186 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 Financial Summary Revenue ($ in millions): $11.6 Operating Expense ($ in millions) (1): $4.2 Unit Operating Expense ($/BOE) (1): $14.18 (1) Excluding taxes.

Asset Overview Alabama Properties 2009 Operating Statistics Upstream: Alabama Acquisition Date: July 31, 2007 Alabama Counties: Escambia, Choctaw Producing Wells: 29 Net Acreage: 13,000 Net Reserves: 8.1 MMboe (48.3 Bcfe) Average Operated W.I.: 73% Producing Formations: Smackover 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 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.

Asset Overview East Texas Properties 2009 Operating Statistics Upstream: East Texas Acquisition Date: July 31, 2007 Texas Counties: Wood, Rains, Van Zandt, Henderson Operating Producing Wells: 34 Net Acreage: 16,000 Net Reserves: 4.8 MMboe (29.0 Bcfe) Average Operated W.I.: 83% Producing Formations: Smackover Gas Composition: 20-40% H2S Eagle Rock's East Texas production is treated and processed by Regency Field Services' Eustace 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 Financial Summary Revenue ($ in millions): $15.6 Operating Expense ($ in millions) (1): $3.1 Unit Operating Expense ($/BOE) (1): $6.13 (1) Excluding taxes.

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.

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

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 higher prices 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)

Adjusted EBITDA Reconciliation