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

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
SCHEDULE 14A
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[LOGO]

2 Forward Looking Statements This news release 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, but are not limited to, the risks that the proposed transaction may not be consummated or the benefits contemplated therefrom may not be realized. Additional risks include: the ability to obtain requisite regulatory and unitholder approval and the satisfaction of the other conditions to the consummation of the proposed transaction, the potential impact of the announcement or consummation of the proposed transaction on relationships, including with employees, suppliers, customers, competitors and credit rating agencies, risks related to volatility or declines (including sustained declines) in commodity prices; market demand for crude oil, 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 crude oil and natural gas supply; the availability of local, intrastate and interstate transportation systems and other facilities to transport crude oil, 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, 2012 and the Partnership's Forms 10-Q filed with the SEC for subsequent quarters, including the Partnership’s Form 10-Q filed for the quarter ended September 30, 2013 as well as any other public filings, and press releases.

3 Legend Additional Information and Where to Find It This presentation does not constitute the solicitation of any vote, proxy or approval. This presentation relates to a potential transaction between the Partnership and Regency. This presentation is not a substitute for any proxy statement or any other document which the Partnership may file with the SEC in connection with the proposed transaction. In connection with the proposed transaction, the Partnership will file with the SEC a proxy statement for the unitholders of the Partnership. INVESTORS AND SECURITY HOLDERS ARE URGED TO READ THE PROXY STATEMENT AND OTHER RELEVANT DOCUMENTS FILED WITH THE SEC CAREFULLY IN THEIR ENTIRETY IF AND WHEN THEY BECOME AVAILABLE BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE PROPOSED TRANSACTION. Any such documents will be available free of charge through the website maintained by the SEC at www.sec.gov or by directing a request to the Partnership’s Investor Relations Department, Eagle Rock Energy, L.P., 1415 Louisiana Street, Suite 2700, Houston, TX 77002, telephone number (281) 408-1200. Participants in the Solicitation The Partnership and Regency and their respective general partner’s directors and executive officers may be deemed to be participants in the solicitation of proxies from the unitholders of the Partnership in respect of the proposed transaction. Information regarding the persons who may, under the rules of the SEC, be deemed participants in the solicitation of the unitholders of the Partnership in connection with the proposed transaction, including a description of their direct or indirect interests, by security holdings or otherwise, will be set forth in the proxy statement when it is filed with the SEC.

Partnership Overview and Recent Highlights Eagle Rock Energy Partners, L.P.

 Equity value as of 1/9/14. Net debt as of 9/30/13. Based on Q3 2013 annualized. Based on Q3 2013 Pre-G&A EBITDA. Based on Q3 2013 LTM gross margin based on net equity volumes from Midstream Business and production volumes from Upstream Business and weighted average received prices for respective business segments and periods. 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. Eagle Rock Energy Partners, L.P. Today Business Mix (3) Enterprise Value (1): $2.2 billion Adjusted EBITDA (2): $251.1 million Q3 Midstream Gathering Volumes: 584 MMcf/d Q3 Average Upstream Production: 75.8 Mmcfe/d Total Company Commodity Mix (4) 5 Oil / Condensate 60% Natural Gas 16% NGLs 24% Upstream 53% Midstream 47% Midstream Gathering Systems Existing Upstream Operations Midstream Processing Plants Legend Midstream Gathering Systems Existing Upstream Operations Midstream Processing Plants Legend

Overview of Pending Midstream Business Transaction 6 On December 23, 2013, Eagle Rock announced it had entered into a definitive agreement to contribute its Midstream Business to Regency Energy Partners for total consideration of up to $1.325 billion, consisting of: $200 million of Regency common units Combination of cash and assumed senior unsecured notes (subject to bond exchange described below) Key Terms Closing Conditions Eagle Rock unitholder vote (NGP has committed to vote its units in favor of the transaction) Hart-Scott-Rodino Antitrust Improvements Act approval and other customary closing conditions Use of Proceeds Repay borrowings under the revolving credit facility Pro forma net leverage ratio expected to be under 1.75x Bond Exchange Offer Regency will conduct a bond exchange offer prior to closing in which existing Eagle Rock bondholders will have the opportunity to exchange into Regency bonds with similar terms (equivalent coupon and tenor) and conditions The cash portion of the purchase price will be reduced by the amount of bonds assumed by Regency subject to a 10% adjustment factor such that if all $550 million of bonds are exchanged, the total consideration will equal $1.27 billion

Midstream Contribution Strategic Rationale 7 Significant deleveraging to facilitate future growth Pro forma net Leverage Ratio expected to be under 1.75x with improved liquidity either in the form of excess cash or availability under revolving credit facility Enhanced Balance Sheet Strength Accomplishes stated goal of simplifying / streamlining the Partnership with a single business line Improved cost structure with substantial G&A savings Greater clarity for investor base and analysts Simplified Structure: Increased Focus and Efficiency as Pure-Play Upstream MLP Continue measured drilling program focused on high-return opportunities in the SCOOP play Pro forma Eagle Rock will have significant dry powder and more competitive cost of capital to pursue acquisitions Will continue to have exposure to Midstream Business growth and synergies through ownership position in Regency Clearer Path to Growth

Upstream Business Overview Eagle Rock Energy Partners, L.P.

Alabama/Miss. Area Proved Reserves: 61 Bcfe Avg. Prod. Rate (1): 14.3 MMcfe/d % Gas (1): 17% Net Operated Wells: 21 Average Operated WI: 72% Permian Area Proved Reserves: 30 Bcfe Avg. Prod. Rate (1): 5.1 MMcfe/d % Gas (1): 27% Net Operated Wells: 196 Avg. Operated WI: 88% South Texas Area Proved Reserves: 4 Bcfe Avg. Prod. Rate (1): 1.1 MMcfe/d % Gas (1): 72% Net Operated Wells: 6 Avg. Operated WI: 100% East Texas Area Proved Reserves: 23 Bcfe Avg. Prod. Rate (1): 6.5 MMcfe/d % Gas (1): 40% Net Operated Wells: 27 Average Operated WI: 84% TOTAL UPSTREAM Proved Reserves: 350 Bcfe Probable Reserves: 67 Bcfe Productive Wells (Op/Non-Op) (2): 559 / 1,250 Average Production (1): 75.8 MMcfe/d Geographically Diverse Upstream Assets Mid-Continent Assets Proved Reserves: 233 Bcfe Avg. Prod. Rate (1): 48.8 MMcfe/d % Gas (1): 58% Net Operated Wells: 235 Average Operated WI: 83% Note: Proved and probable reserves as of 12/31/12 based on SEC pricing. Based on Q3 2013 production. Well count based on gross operated and gross non-operated wells. 9

Diversified Reserve Base Across High Quality Basins 10 Reserve Profile 350 Bcfe of proved reserves at 12/31/12 13-year reserve life (1) Over 600 (gross) identified drilling locations (2) Production Profile (3) ~75% of Production Generates > $4.00/Mcfe in Net Margin Based Q3 2013 annualized production. 135 drilling locations are categorized as proved undeveloped. Based on SEC pricing. Net Margin based on ratio of Q3 2013 operating cash income to Q3 2013 production volumes. Production breakout based on Q3 2013 production volumes. Net Margin by Field Area ($/Mcfe) $7.80 $7.37 $6.46 $4.52 $2.10 $1.98 $1.64 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 $9.00 Alabama Golden Trend + SE Cana Permian East Texas Cana Verdan Arkoma Cana 5% Arkoma 8% Anadarko 7% Verden 4% Golden Trend 28% SE Cana 13% Permian 7% East Texas 8% South Texas 1% Alabama 19% Oil 22% Gas 56% NGLs 22% PDP 76% PUD 24%

Realizing Resource Potential in Central Oklahoma CANA WOODFORD S.E. CANA WOODFORD ARDMORE WOODFORD Woodford Shale Thickness 50’ 100’ 200’ 300’+ EROC Acreage Woodford Horizontal Wells SCOOP 11 Sources: Modified from Modern Shale Gas A Primer, DOE, 2009, I.H.S., Investor presentations (1) STACK Newfield Marmaton Play Outline STACK (1) Major driver of future liquids-rich production growth Eagle Rock currently has interests in 84 producing horizontal Woodford Shale wells in Cana and SCOOP plays; Q3 2013 average net production rate of 34.6 MMcfe/d Through initial learning curve and seeing reductions in drilling times and costs for the horizontal Woodford wells in SCOOP; target ROR of 50%+ on drilling economics Shale Basin Barnett Haynesville Marcellus Woodford Depth. Ft 6,500 - 8,500 10,500 - 13,500 4,000 - 8,500 5,000 - 15,000 Net Thickness (ft) 100-600 200-300 50-200 120-400 Total Organic Carbon, % 4.5 .5 - 4 3 - 12 1 - 14 Total Porosity, % 4 - 5 8 - 9 10 3 - 9

12 Broad Development and Expansion Continues Across Eagle Rock’s Acreage Position Golden Trend and Cana Woodford Trend Eagle Rock Position Cana Development Area: Interest in 72 producing wells SCOOP (~16,500 net acres) Golden Trend (conventional) Operating a 1-rig drilling program S.E. Cana (horizontal) Interest in 13 producing wells 3 producing operated wells (Beckham 1-27H, Kelly 1-2H, Riddle 14-32H) Spud the fourth operated horizontal Woodford test, McLemore 1-20H (20-5N5W), in January 2014 “SCOOP” - Golden Trend / Southeast Cana SE Cana 0.8 MBoe/d 15% Golden Trend 3.6 MBoe/d 66% Legacy Cana 1.0 MBoe/d 19% STACK (1) Cana Development Area (1) STACK Newfield Marmaton Play Outline Current Production

“SCOOP” EROC owns approximately 16,500 net acres in “SCOOP”. 41 rigs currently drilling in Grady, Garvin, McClain and Stephens counties. 33 rigs drilling horizontal wells. Recent Operated wells Beckham 1-27H: has produced 0.9 bcf gas and 25 Mbo in its first 12 months. Kelly 1-2H: EROC’s second operated Southeast Cana well, has produced 0.4 bcf gas and 33.5 Mbo in its first 6 months. Riddle 14-32H: EROC’s third operated Southeast Cana well, has produced 0.5 Bcf gas and 26.2 Mbo in its first 6 months. 2014 Drilling Program: McLemore 1-20H spud on 12/19/2013. Expect to drill 5 Operated wells with an average working interest of 46%. Expect 7 Non-operated wells to be drilled with an average working interest of 23%. Technology Advances: 2 section laterals have proved to be much more economic and are being drilled where possible. 5 & 6 well/section development tested by Newfield. Participating in a Newfield 5 well development in 2014. “SCOOP”: Southeast Cana’s Results Continue 13 Branch (1-6) – 16XH (NFX) June 2012 6 well avg. IP30: 1,513 Boepd (7.4 MMcfd, 287 Bopd) Lambakis 1-11H (CLR) May 2011 IP30:1422 Boepd (10% oil) (7.7 MMcfd, 136 Bopd) Beckham 1-27H (EROC) WI 100%, September 2012 IP30: 856 Boepd (21% oil), (4.1 MMcfd, 178 Bopd) Kelly 1-2H (EROC) EROC WI 72%, March 2013 IP30: 918 Boepd (37% oil) (3.5 MMcfd, 341 Bopd) Eagle Rock Operated Wells Third Party Wells Source: Producer investor presentations, Eagle Rock, IHS, OCC. XH designates extended laterals (>5000’ lateral length) Golden Trend Sparks 1-27H (CLR) August 2013 IP24 Hr: 775 Boepd (71% oil) (1.3 MMcfd, 553 Bopd) Southeast Cana Riddle 14-32H (EROC) WI 60%, July 2013 IP30: 825 Boepd (28% oil) 3.6 MMcfd, 231 Bopd Singer 1-18-7H (CLR) June 2013 IP30: 1,688 Boepd (33% oil), (6.8 MMcfd, 556 Bopd) Casados 1-21XH (NFX) January 2013 IP30: 1,795 Boepd (19% oil), (8.8 MMcfd, 341 Bopd) Campbell 1-36XH (NFX) March 2013 IP30: 1063 Boepd (56% oil) (2.8 MMcfd,595 Bopd) Floyd 1-3XH (NFX) April 2013 IP30: 737 Boepd (39% oil) (2. 7 MMcfd,287 Bopd) Boles 1-14XH (NFX) February 2013 IP30: 1,466 Boepd (57% oil) (3.9 MMcfd,836 Bopd) Arrington 1-23H (CLR) December 2013 IP24 Hr: 1,040 Boepd (32% oil), (4.2 MMcfd, 337 Bopd) McLemore 1-2OH (EROC) WI 60%, Dec 2013 Spud

Deese (Hart Sand) Springer Sand Sycamore Lime Woodford Shale Hunton Lime Viola Lime Producing Formations GR Log Golden Trend Update Tiger 5-20 (100% WI) 1st Sales: 8/23/2013 IP30: 699 Bbl/d, 1,200 Mcf/d EROC Acreage 2013 Completed EROC Drilling Bromide Oil Wells Bromide Gas Wells Bromide Wells WOC Legend Beam 4-17 (100% WI) 1st Sales: 5/20/2013 IP30: 340 Bbl/d, 737 Mcf/d Dennis 4-11 (100% WI) 1st Sales: 4/4/2013 IP30: 56 Bbl/d, 393 Mcf/d Beam 3-17 (100% WI) 1st Sales: 8/8/2013 IP30: 170 Bbl/d, 750 Mcf/d One to Two Rig Vertical Program Drilling Bromide/Big Four Wells During 2013 Sterr 1-15 (95% WI) 1st Sales: 8/8/2013 IP30: 288 Bbl/d, 724 Mcf/d Brown Trust 1-3 (94% WI) Flowing Back Bromide Sands 14 Riddle 12-32 (92% WI) 1st Sales: 4/2/2012 IP30 210 Bbl/d 1,313 Mcf/d Riddle 13-32 (97% WI) 1st Sales: 6/28/2013 IP30: 252 Bbl/d, 1,180 Mcf/d Riddle 15-32 (96%) 1st Sales: 11/23/2013 IP30: 237 Bbl/d, 617 Mcf/d Trula 1-16 (99.5% WI) 1st Sales: 8/8/2013 IP30: 80 Bbl/d, 250 Mcf/d Beam 5-17 (100% WI) Trula 2-16 (99.5% WI): 1st Sales: 12/26/2013 IP24HR: 238 Bbl/d 423 Mcf/d Shelby 1-16 (99.6% WI): Flowing Back

Golden Trend Upside 2-rig program active through most of 2013 Vertical Bromide/Big 4 well performance has exceeded expectations in the deeper structural positions Additional locations are being developed in the N-NW (deeper) area of the field utilizing 3-D seismic, capitalizing on recent results Overview 2013 Drilling Wedge – Operated New Drills 2013 Golden Trend Bromide / Big 4 New Drills Oil Gas 3rd Party Processing Plant Shut-in 15

Midstream Business Overview Eagle Rock Energy Partners, L.P.

Midstream Business Panhandle (1) 6,514 miles of pipeline 11 processing plants 211,500 compression HP Gathering Volume: 393 MMcf/d Equity NGL/Condensate: 5,816 Bbls/d EROC Processing Plant Haynesville Shale Austin Chalk Granite Wash Deep Bossier / Angelina River Trend TOTAL MIDSTREAM (1) Pipeline Miles: 8,134 Processing Plants: 20 Compression HP: 286,219 Gathering Volumes: 584 MMcf/d NGL/Condensate Equity Volumes: 6,572 Bbls/d Volumes based on Q3 2013. Tuscaloosa Marine Shale East Texas and Other Midstream (1) 1,620 miles of pipeline 9 processing plants 74,719 compression HP Gathering Volume: 191 MMcf/d Equity NGL/Condensate: 756 Bbls/d Tonkawa Hogshooter Morrow/Cleveland Woodbine 17

Leading Franchise in Texas Panhandle Planned interconnects 86 active rigs in counties in which EROC operates (10 -15 rigs on dedicated acreage)(1) Over 330 new wells permitted in area over past six months ~6,500 miles of gathering lines in heart of Granite Wash, Tonkawa and Cleveland plays Over 3,800 wells connected to combined system ~540 MMcf/d of processing capacity Roberts Completed May 2013 Completed interconnects Completed June 2013 Q1 2014 Completion Expected 60 MMcf/d plant brought on-line in July 2013 Includes Beaver, Beckham, Carson, Ellis, Gray, Hansford, Hemphill, Hutchinson, Lipscomb, Moore, Ochiltree, Potter, Roberts, Roger Mills, Sherman, Texas and Wheeler counties. 18

On June 4, 2012, completed construction of $72 million cryogenic processing plant with 60 MMcfd of capacity in the Granite Wash play On July 8, 2013, announced in-service of $65 million, 60 MMcfd cryogenic processing plant in the Granite Wash area increasing the Partnership’s cryogenic processing capacity in the Texas Panhandle to 540 MMcfd 2010 2011 2012 Texas Panhandle Midstream BP Midstream Assets 2013 Phoenix Plant Woodall Plant Wheeler Plant Acquisitions Growth Projects Apache Midstream Contract Contracts Development of the Texas Panhandle Super System On October 9, 2010, the Partnership acquired a natural gas gathering system in the Texas Panhandle from CenterPoint Energy Field Services for $27.0 million Assets included 200-mile gathering system with 18.5 MMcfd of volume On October 1, 2012 the Partnership acquired BP’s Texas Panhandle midstream assets for $230.6 million which included the Sunray and Hemphill processing plants and the associated 2,500-mile gathering system In conjunction with the transaction, the Partnership entered into a 20-year, fixed-fee natural gas gathering and processing agreement with BP On March 6, 2013, the Partnership announced a fee-based natural gas gathering contract with Apache Corporation encompassing more than 106,000 gross acres in the Texas Panhandle $20 million, 30 MMcfd expansion of the Phoenix Plant located in Hemphill County, Texas to accommodate volume growth in the Granite Wash play Monarch Agreement On May 8, 2013, the Partnership announced a fee-based natural gas gathering and processing agreement with Monarch Natural Gas, LLC encompassing more than 150,000 gross acres in the Texas Panhandle Texas Panhandle Plant Processing Capacity E Wheeler Plant Sunray Plant Hemphill Plant Woodall Plant Phoenix - Arrington Ranch Expansion Eagle Rock Legacy Panhandle 19 Phoenix - Arrington Ranch Plant

BP Acquisition: Accelerating Growth Note: All corporate logos are registered trademarks of the respective companies or their affiliates. 20 New Dedicated Acres + 7,700 acres + 5,700 acres + 13,400 acres + 12,800 acres + 8,300 acres + 350,000 acres + 106,000 acres + 150,000 acres Since the beginning of 2011, Eagle Rock has secured commitments for over 670,000 acres in the Texas Panhandle; with over 620,000 acres facilitated by expanded footprint following the BP Acquisition Dedicated producers (shown below) currently operate over 50% of the rigs in the Panhandle area (86 rigs), of which approximately 10 – 15 are operating on Eagle Rock dedicated acreage Monarch Natural Gas, LLC Crest Resources, Inc. + 16,000 acres + 600 acres - 100,000 200,000 300,000 400,000 500,000 600,000 700,000 New Acreage Dedications Dedicated Acreage (Gross)

Shifting Midstream Contract Mix Reduced Commodity Exposure Through Increased Fee-Based Business Through the new or amended contracts with BP, Apache, Anadarko and others, the Partnership has taken significant steps in transitioning to a more fee-based/fixed-recovery model (1) Based on Management estimates. Contract Mix Based on Gathering Volumes (MMcf/d) Commodity-Based Fee-Based (1) (1) 21 21% 27% 40% 47% 79% 73% 60% 53% 0% 20% 40% 60% 80% 100% 2011 2012 2013E 2014E

Hedging Update Eagle Rock Energy Partners, L.P.

Robust Hedging Profile: Eagle Rock Today Includes Both Upstream and Midstream Hedgeable Volumes $96.16 $89.10 $84.60 $4.38 $4.10 $4.25 Avg. Strike Price (1) Total Hedges in Place NGL Volumes Hedged Directly Total Hedges in Place Crude, Condensate and NGLs (>C2) (1) Ethane and Natural Gas (1) Prices shown reflect weighted average price of swaps and collar floors ($/Bbl and $/MMBtu) and exclude price impact of direct product hedges. Reflect percent hedged based on “Hedgable Volumes.” 23 84% 58% 56% 21% 0% 0% 0% 20% 40% 60% 80% 100% 2014 2015 2016 106% 83% 70% 0% 0% 0% 20% 40% 60% 80% 100% 2014 2015 2016

Robust Hedging Profile: Pro Forma Eagle Rock Upstream Hedgeable Volumes Only $96.82 $89.88 $84.66 $4.51 $4.07 $4.25 Avg. Strike Price (1) Total Hedges in Place NGL Volumes Hedged Directly Total Hedges in Place Crude, Condensate and NGLs (>C2) (1) Ethane and Natural Gas (1) Prices shown reflect weighted average price of swaps and collar floors ($/Bbl and $/MMBtu) and exclude price impact of direct product hedges. Reflect percent hedged based on “Hedgable Volumes.” 24 88% 88% 84% 55% 0% 0% 0% 20% 40% 60% 80% 100% 2014 2015 2016 101% 107% 104% 0% 0% 0% 20% 40% 60% 80% 100% 2014 2015 2016

Appendix Eagle Rock Energy Partners, L.P.

Adjusted EBITDA Reconciliation Adjusted EBITDA Reconciliation 26 2013 2012 2013 2012 Net cash flows provided by operating activities $47,120 $49,229 $152,194 $111,000 Add (deduct): Depreciation, depletion, amortization and impairment (104,030) (96,295) (187,263) (240,867) Amortization of write-offs of debt issuance costs and discounts (1,176) (1,019) (3,283) (2,425) (Loss) gain from risk management activities, net (27,507) (36,936) (15,245) 47,309 Derivative settlements - operating (1,637) (10,367) (15,677) (17,927) Other (2,999) (3,401) (10,312) (8,704) Accounts receivables and other current assets (11,701) 16,953 (1,027) 1,976 Accounts payable, due to affiliates and accrued liabilities 7,408 (32,224) (31,831) 6,643 Risk management activities - 6,606 - 7,663 Other assets and liabilities 2,957 559 3,397 (107) Net income (loss) ($91,565) ($106,895) ($109,047) ($95,439) Add (deduct): Interest (income) expense, net 19,089 15,931 56,013 43,709 Depreciation, depletion and amortization 104,030 96,295 187,263 240,867 Income tax (benefit) provision (2,033) (386) (4,055) (556) EBITDA $29,521 $4,945 $130,174 $188,581 Add (deduct): Loss (gain) from risk management activities, net 27,507 36,936 15,245 (47,309) Total derivative settlements 1,812 13,911 16,729 29,891 Restricted unit compensation expense 3,939 3,080 10,106 8,092 Non-cash mark-to-market Upstream imbalances 3 229 (2) 339 ADJUSTED EBITDA $62,782 $59,101 $172,252 $179,594 ($ in thousands) ($ in thousands) Three Months Ended Nine Months Ended September 30, September 30,