Eagle Rock Energy Partners L P (EROC) DEFA14A Additional proxy soliciting materials

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2010 2010 NAPTP MLP Investor Conference May 2010

2 Joseph A. Mills Chairman & Chief Executive Officer Jeffrey P. Wood Senior Vice President & Chief Financial Officer Management Representatives

3 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

4 • Eagle Rock (NASDAQ: EROC) is an MLP with three complementary energy businesses wellpositioned 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 May 6, 2010. Subordinated units are valued at common unit price. (2) See Appendix f or definition of Adjusted EBITDA. Texas Panhandle Midstream Assets East Texas / Louisiana Midstream Assets West Texas / South Texas Midstream Assets Gulf of Mexico Midstream Assets

5 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. $737.4 $754.4 $774.4 $804.4 $837.4 60% 63% 71% 77% 69% $500 $600 $700 $800 $900 Q1 '09 Q2 '09 Q3 '09 Q4 '09 Q1 '10 20% 30% 40% 50% 60% 70% 80% 90% 100%

6 Company Highlights – 2010 Plans • Special Unitholder Meeting on May 14th to approve the Recapitalization and Related Transactions • Announced deployment of 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 – Project underway, scheduled completion by Sept 30, 2010 • Expansion of East Texas assets to gather additional Haynesville and Middle Bossier production – Purchased 20” diameter pipeline, acquired substantially all right-of-ways – Seeking producer commitments to initiate construction • Robust drilling program in Permian Basin / East Texas – Three wells drilled and completed year to date, one rig running and expectations to drill between 3 to 6 additional wells in 2010 • 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.

• Eagle Rock exited 2008 with elevated debt levels related to the Millennium Acquisition, creating covenant pressure under its $980 million senior credit facility • Turmoil in the capital markets limited access to external capital • Distribution cut (April 2009) was a reprieve, not a solution – Despite $100 million of debt repayment over the past year, Partnership forecasts potential covenant violations under the credit facility by second / third quarter of 2010, absent further debt repayment or increased Adjusted EBITDA • Reduction in distribution resulted in further structural complications – Arrearages building on common units 7 $837.4 $804.4 $774.4 $754.4 $737.4 4.02x 4.39x 4.75x 4.57x 4.54x $500 $600 $700 $800 $900 $1,000 Q1 '09 Q2 '09 Q3 '09 Q4 '09 Q1 '10 0.00x 1.00x 2.00x 3.00x 4.00x 5.00x Events Leading to Recapitalization Proposal Leverage Ratio Total Debt ($ in Millions) Covenant Test

• Sale of Minerals Business to third party for $174.5 million to close within 10 days after successful vote • Other liquidity-enhancing transactions • Natural Gas Partners (NGP) contributes: – General partner / controlling interests (844,551 general partner units) in exchange for one million common units (1) – 20.9 million subordinated units – Incentive distribution rights – Equity commitments • NGP receives: – $29 million transaction fee in the form of 4.82 million common units (based on a 10% discount to the 10-day VWAP of $6.68/unit announced on 4/26/10) • Contribution of general partner, to occur within a reasonable timeframe after the successful Unitholder Vote, will trigger a restructuring of board to include two additional independent directors and annual unitholder meetings • All Transactions are cross-contingent on each other Special Meeting on May 14th to approve certain of the Recapitalization and Related Transactions 8 Key Terms of Recapitalization and Related Transactions Note: Please see Definitive Proxy filed on March 30, 2010 for additional details on the Recapitalization and Related Transactions. (1) Assumes exercise of GP Acquisition Option.

9 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 – Other liquidity enhancing transactions – 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

10 • 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 on the Recapitalization and Related Transactions. (1) 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

11 222 349 451 587 0 100 200 300 400 500 600 700 2006 2007 2008 2009 MMcf/d $189 $248 $132 $81 $0 $50 $100 $150 $200 $250 2006 2007 2008 2009 $ in Millions Historical Performance and Growth Adjusted EBITDA ($ in Millions) (1) Daily Gathering Volumes (MMcfe/d) Upstream Volumes (2) Minerals Volumes (3) 38% C AG R 3 2 % C AGR (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 Jul y 1, 2007. 5,308 5,437 5,276 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 2007 2008 2009 Boe/d 1,088 1,080 1,048 0 200 400 600 800 1,000 1,200 1,400 2007 2008 2009 Boe/d

12 Overview of Midstream Business Panhandle • 3,743 miles of pipeline • 7 processing plants • 131,000 compression HP • 128 MMcf/d Q1 2010 avg. volume East Texas / North Louisiana • 1,195 miles of pipeline • 7 processing plants • 43,700 compression HP • 213 MMcf/d Q1 2010 avg. volume Gulf of Mexico • 40 miles of pipeline • 2 processing plants • 14,180 compression HP • 102 MMcf/d Q1 2010 avg. volume Processing Plant Haynesville Shale Austin Chalk Granite Wash South Texas • 266 miles of pipeline • 3 processing stations • 14,700 compression HP • 74 MMcf/d Q1 2010 avg. volume

13 Panhandle: New Phoenix Processing Plant • Eagle Rock will now be able to move volumes between multiple plants on its East Panhandle System; the gathering 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 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

14 45 83 88 84 90 132 156 157 167 177 170 273 271 266 237 221 213 0 50 100 150 200 250 300 350 Q1 '06Q2 '06Q3 '06Q4 '06Q1 '07Q2 '07 Q3 '07Q4 '07Q1 '08Q2 '08Q3 '08Q4 '08Q1 '09Q2 '09Q3 '09Q4 '09Q1 '10 System Update: • Haynesville Shale: In active discussions with a number of producers regarding extending systems • Austin Chalk: Play moving east into Louisiana – expect results later in 2010 • Last four producer wells reported average IP of approximately 12 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 East Texas / North Louisiana Volumes Haynesville Shale Angelina River Trend Austin Chalk East Texas: Serving Multiple Plays EROC Minerals MMcfe/d 3 7 6% Increase Phase I of ETML Expansion Potential Future ETML Expansions 3 planned wells 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 company investor presentations. Rig Activity

15 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 Natural Gas 29% NGLs 32% Oil 39% 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.

16 Upstream 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 5,308 5,437 5,276 $9.60 $11.16 $14.10 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 2007 2008 2009 $6.00 $8.00 $10.00 $12.00 $14.00 $16.00 $18.00 $20.00

17 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 5,700 5,276 5,437 5,308 $19.5 $8.4 $20.7 $2.2 3,000 3,500 4,000 4,500 5,000 5,500 6,000 2007 2008 2009 2010E $0 $10 $20 $30 $40 $50

18 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) Crude, Condensate & NGL (>C3) Hedge Level Natural Gas & Ethane Hedge Level Percent of Hedgable Volumes Percent of Hedgable Volumes $62.35 $74.46 $76.88 $89.94 $6.69 $6.90 $6.90 NA Hedge prices are weighted average of puts, floors and swaps on crude oil only (does not include condensate and NGLs) weighted average floor of crude hedges, $/bbl oil weighted average floor of natural gas hedges, $/mmbtu 91% 70% 65% 47% 0% 20% 40% 60% 80% 100% 2010 Rem 2011 2012 2013 76% 71% 67% 0% 20% 40% 60% 80% 100% 2010 Rem 2011 2012 2013

20 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

22 Eagle Rock Credit Facility • Senior secured revolving credit facility with total commitments of $971 million from 19 financial institutions Borrowing Base Compliance Tests • Supported by all Upstream properties • Borrowing Base recently redetermined at $130 million, effective April 1, 2010 (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 3/31/10) • Leverage Ratio: < 5.0x 4.54x • Interest Coverage Ratio: > 2.5x 4.79x • 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.

23 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 (2009 Margin) 2010 Commodity Exposure (1) Fee-Based 37% Fixed Recovery 12% Keepwhole 8% Percent of Proceeds 43% Fee-Based 31% Percent of Proceeds / Fixed Recovery 46% Keepwhole 23% Fee-Based 31% Commodity Hedged 64% Commodity Unhedged 5% (1) Based on company estimates.

24 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.

25 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.

26 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.

27 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.

28 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.

29 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.

30 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.

31 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.

32 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

33 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)

34 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