EROC (MM)

The filing relates to a proposed business combination (the “Proposed Merger”) involving Vanguard Natural Resources, LLC (“Vanguard”) and Eagle Rock Energy Partners, L.P. (“Eagle Rock”).

August 20, 2014 DRAFT 2014 Citi MLP One-on-One Conference 2015 NAPTP MLP Conference May 20-22, 2015

Disclosure Regarding “Forward-Looking Statements” 2 This document may include "forward-looking statements." All statements, other than statements of historical facts, included in this document 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, 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 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, 2014 and the Partnership's Forms 10-Q filed with the SEC for subsequent quarters as well as any other public filings, and press releases.

Partnership Overview & Recent Highlights

Eagle Rock Energy Partners, L.P. (NASDAQ: EROC) is a growth-oriented upstream MLP with assets in Oklahoma, Alabama, Texas, Mississippi and Arkansas 1Q15 distribution of $0.07/unit, or $0.28/unit annualized (1Q15 distributable cash flow coverage of 1.12x) Current 11% yield offers an attractive, tax-advantaged distribution(2) Recently revised the 2015 capital budget to $75 MM ($40 MM maintenance and $35 MM growth) Production expected to average 75 – 78 MMcfe/d for full year 2015 On April 30, 2015, Regency Energy Partners (RGP) and Energy Transfer Partners (ETP) closed on their previously announced merger Each RGP common unit owned by EROC was converted into 0.4124 ETP common units, or ~1.03 million total units Eagle Rock Overview 4 Market Valuation Key Statistics As of May 15, 2015, Energy Transfer Partners, LP (ETP) had a $57.42 unit price. As of May 15, 2015. ($ in millions, except per unit amounts) Proved Reserves (12/31/14) 318.2 Bcfe % Proved Developed 79.0% % Gas 53.1% % Net Production Operated 75% Proved R/P 12 years 1Q 15 Production 79.7 MMcfe/d Net Acreage 202,632 % HBP 95% Unit Price as of 5/15/15 $2.47 Units Outstanding as of 4/30/15 153.0 Equity Market Cap $377.9 Total Debt as of 4/30/15 203.1 ETP 1.03 MM Units as of 4/30/15 (1) 59.1 Enterprise Value $521.8

Investment Highlights 5 ~80% of expected remaining 2015 total production hedged(2): 85% of crude and condensate production at average strike price of $89.88/Bbl 77% of natural gas and ethane production at average strike price of $4.07/MMbtu 86% of natural gas liquids (C2+) production Reserve base with attractive natural gas exposure 53% natural gas 21% oil 26% NGL 73% of reserves classified as Proved Developed Producing 79% of reserves classified as Proved Developed Over $175 MM of liquidity (~$59 MM ETP units as of 4/30/15(1) and $118 MM revolver availability) Net leverage ratio of 1.7x as of 4/30/15 No debt maturities until 2019 With a solid balance sheet, good liquidity and robust hedge portfolio, EROC is focused on growing through accretive acquisitions of MLP-appropriate assets that will reduce its existing decline and drive growth in distributable cash flow Robust Hedge Portfolio High PDP Profile Strong Balance Sheet Acquisition Focused Inventory of Low-Risk Growth Opportunities ~20,000 net acres in the highly prospective oil-weighted South Central Oklahoma Oil Province (SCOOP) play Established a premier position in the Woodford and Springer shales, with an interest in ~660 locations(3) In SCOOP, currently producing ~17.0 MMcfe/d from 6 operated and 21 non-operated wells Expect to exit 2015 producing ~22.5 MMcfe/d in SCOOP, representing ~55% production growth in the area Value based on ETP unit price of $57.42 as of May 15, 2015. Based on midpoint of 2015 production guidance. Remainder of 2015 from May 1 – Dec 31. Based on drilling 6 wells and 5 wells/section in the Woodford and Springer shales, respectively. This number could be increased as some operators are drilling 10 wells/section in the Woodford shale.

Strong balance sheet after divestiture of Midstream Business ~$177 MM of liquidity (including ETP units) ETP units are freely tradable with no lockups Ability to fund acquisitions with prudent leverage Net leverage ratio of 1.7x as of 4/30/15 Targeting long-term Debt / Adj. EBITDA at or below 3.5x Balance Sheet Strength 6 Common unit repurchase program of up to $100 MM still in effect until March 2016. Value based on ETP unit price of $57.42 as of May 15, 2015. As of April 30, 2015. ($ in millions) Liquidity Summary Debt / LTM EBITDA(3) Long-term financial plan ETP units a source of liquidity to finance acquisitions Otherwise finance growth with 50% debt / 50% equity In order to preserve liquidity for potential acquisition opportunities, EROC has not repurchased any units since its last update on February 23, 2015(1) 8.6 MM units repurchased to date for total consideration of $22 MM 0.0x 1.0x 2.0x 3.0x 4.0x 5.0x 6.0x EROC Peer A Peer B Peer C Peer D Peer E Peer F Peer G Peer H Peer I Peer J Peer Median 4/30/2015 ETP Unit Value (2) $59.1 Credit Facility 152.0 Senior Unsecured Notes 51.1 Total Debt 203.1 Borrowing Base $270.0 Total Availability 118.0 Total Liquidity $177.1 Net Leverage Ratio as of 4/30/15 1.7x

Note: “REM 2015” represents the remainder of 2015 from May 1 – Dec 31. Percent hedged depicted against midpoint of 2015 production guidance (76 .5 MMcfe/d), held flat through 2019 for ease of modeling but not as guidance. Ethane hedgeable volumes in MMbtu equivalents. Prices shown reflect weighted average price of swaps and collar floors ($/Bbl and $/MMBtu). As of April 30, 2015. Robust Hedging Profile 7 Avg. Strike Price (3) Crude and Condensate (1) Natural Gas and Ethane (1)(2) NGLs (>C2)(1) WTI LLS Evaluating additional gas hedges for 2017 – 2019 Evaluating additional NGL hedges for 2016 – 2017 Significant value in hedge portfolio with an estimated mark-to-market value of approximately $90 MM (4) 21% 18% 16% 13% 12% 11% 85% 72% 34% 30% 27% 0% 25% 50% 75% 100% 125% 2015 REM 2016 2017 2018 2019 86% 44% 0% 25% 50% 75% 100% 125% 2015 REM 2016 2017 2018 2019 ($/Gal) 2015 2016 2017 2018 2019 C3 $0.564 $0.606 - - - NC4 0.672 0.718 - - - IC4 0.675 0.723 - - - C5 1.187 1.305 - - - $/(MMbtu) 2015 2016 2017 2018 2019 HH $4.07 $4.25 $3.34 - - ($/Bbl) 2015 2016 2017 2018 2019 WTI $89.88 $84.66 $88.02 $87.50 $87.07 LLS - - 91.25 90.75 90.25 15% 77% 68% 0% 25% 50% 75% 100% 125% 2015 REM 2016 2017 2018 2019

Alabama Area Proved Reserves: 49.9 Bcfe Avg. Prod. Rate (1): 16.7 MMcfe/d % Oil / Gas (1): 80% / 20% Net Acreage: 11,282 Op./Non-Op. Wells: 22/3 Average Operated WI: 73% Permian Area Proved Reserves: 21.7 Bcfe Avg. Prod. Rate (1): 5.2 MMcfe/d % Oil / Gas (1): 72% / 28% Net Acreage: 22,666 Op./Non-Op. Wells: 191/53 Avg. Operated WI: 95% ETX / STX / MS Area Proved Reserves: 19.8 Bcfe Avg. Prod. Rate (1): 5.2 MMcfe/d % Oil / Gas (1): 62% / 38% Net Acreage: 18,371 Op./Non-Op. Wells: 41/102 Average Operated WI: 87% TOTAL UPSTREAM Proved Reserves: 318.2 Bcfe Probable Reserves: 99.4 Bcfe Productive Wells (Op/Non-Op) (2): 561/1,217 1Q15 Average Production: 79.7 MMcfe/d Net Acreage: 202,632 Mid-Continent Assets Proved Reserves: 226.9 Bcfe Avg. Prod. Rate (1): 52.5 MMcfe/d % Oil / Gas (1): 47% / 53% Net Acreage: 150,314 Op./Non-Op. Wells: 307/1,059 Average Operated WI: 84% Note: Proved and probable reserves as of 12/31/14 based on SEC pricing. Based on 1Q15 Production. Well count based on gross operated and gross non-operated wells. Upstream Asset Base 8

Based on LTM as of 3/31/15 production. Net Margin based on ratio of 1Q 2015 operating cash income to 1Q 2015 production volumes. Production breakout based on 1Q 2015 production volumes. 9 Proved Reserve Profile 318.2 Bcfe of proved reserves at 12/31/14 (based on SEC Pricing) 12 year reserve life (1) Production Profile (2) Total Net Margin of ~$4.60/Mcfe (Including Hedges) (2) High PDP Reserve Base By Product By Category By Area Net Margin by Field Area – Pre-Hedging ($/Mcfe) (2) 7.2 Bcfe Produced in 1Q15 $3.35 $3.29 $2.94 $2.82 $2.66 $1.25 Permian Golden Trend SE Cana ETX/STX/ Other Alabama Other Mid-Con Other Mid - Con 22% Golden Trend 25% SE Cana 19% Permian 6% Alabama 21% ETX/STX/ Other 7% PDP 73% PDNP 6% PUD 21% Oil 21% Gas 53% NGLs 26% Mid - Con 71% Alabama 16% Permian 7% STX/ETX/ Other 6%

Eagle Rock Value Proposition 10 EV / LTM EBITDA Debt / LTM EBITDA EV / 1Q 15 Mcfe/d EV / 2014 Bcfe Eagle Rock currently trades at a discount to upstream MLP peers Eagle Rock offers investors upside potential with its strong balance sheet and ample liquidity for acquisitions Note: As of May 15, 2015. Pro forma for any acquisitions/divestitures. Peers include ARP, BBEP, EVEP, LGCY, LINE, LRE, MCEP, MEMP, NSLP and VNR. 3.5x 4.3x 5.8x 6.3x 6.7x 6.9x 7.3x 7.4x 7.6x 8.6x 8.9x 0.0x 1.0x 2.0x 3.0x 4.0x 5.0x 6.0x 7.0x 8.0x 9.0x 10.0x Peer A EROC Peer B Peer D Peer C Peer G Peer E Peer F Peer H Peer J Peer I EV / LTM EB ITDA 1.7x 1.7x 2.3x 3.5x 3.5x 3.8x 4.8x 4.9x 5.1x 5.1x 5.2x 0.0x 1.0x 2.0x 3.0x 4.0x 5.0x 6.0x EROC Peer A Peer B Peer C Peer D Peer E Peer F Peer G Peer H Peer I Peer J Debt / LTM EBITDA $6,548 $7,623 $8,152 $8,238 $8,296 $8,579 $11,048 $11,056 $12,166 $13,293 $14,182 $0 $2,000 $4,000 $6,000 $8,000 $10,000 $12,000 $14,000 $16,000 EROC Peer B Peer A Peer J Peer H Peer D Peer I Peer F Peer G Peer C Peer E EV / Mcfe/d $1.31 $1.54 $1.57 $1.60 $1.64 $1.78 $1.97 $2.00 $2.09 $2.70 $2.79 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 Peer B Peer A Peer H Peer J EROC Peer I Peer F Peer G Peer D Peer C Peer E $ / Bcfe

Midcontinent

Reserves as of 12/31/14. 150,314 Net Acres, 97% Held by Production Midcontinent Overview 12 1Q15 Daily Production Net 2P Reserves (1) 322.2 Bcfe 52.5 MMcfe/d Midcontinent Reserves (1) Arkoma Legend Eagle Rock Upstream Operations Eagle Rock Wells – Operated Eagle Rock Wells – Non Operated Cana Woodford / Stack Play Cleveland Golden Trend Granite Wash Verden SE Cana Woodford and Springer (SCOOP) Oil 20% Gas 53% NGL 27% Cana 20% Arkoma 15% Anadarko 7% Verden 11% Golden Trend 23% SE Cana 24% Total Oil Gas NGL Equivalent Reserve Category (MMBbl) (Bcf) (MMBbl) (Bcfe) Proved Developed Producing 3.0 91.8 5.6 143.3 Proved Developed Non-Producing 0.4 9.8 0.6 16.0 Proved Undeveloped 1.3 42.2 2.9 67.6 Total Proved 4.7 143.8 9.2 226.9 Probable 1.7 69.7 2.5 95.3 Total 2P 6.4 213.5 11.7 322.2

SCOOP Asset Map – ~20,000 Net Acres CANA WOODFORD ARKOMA WOODFORD ARDMORE WOODFORD SCOOP 50’ 100’ 200’ 300’+ EROC Acreage Woodford Horizontal Wells STACK MARCHAND SCOOP Area Overview 13 SPRINGER (BLACK MARKER) S.E. CANA WOODFORD & SPRINGER Shale Basin Metric Barnett Marcellus Woodford Springer Depth (ft) 6,500' - 8,500' 4,000' - 8,500' 5,000' - 16,500' 11,000' - 14,000' Net Thickness (ft) 100' - 700' 50' - 350' 120' - 400' 60' - 120' Total Organic Carbon (%) 3.0% - 12.0% 2.0% - 13.0% 3.0% - 12.0% 3.0% - 4.0% Total Porosity (%) 4.0% - 6.0% 4.0% - 12.0% 3.0% - 9.0% 3.0% - 9.0%

2 miles 1 mile 760 ft spacing 920 ft spacing Woodford Upper Target Caney Shale Sycamore/Osage Springer Shale (Goddard) Beckham 1-27H Eagle Rock Energy Gamma, Resistivity, Density Woodford Lower Target Separation 920 ft GR RES DPHI 0 600 .2 2000 .3 -.01 14000 13500 12500 Top Woodford Top Hunton 14 Reservoir Characteristics and Development Planning Commentary Springer (Goddard) Shale 11,000 – 14,000 TVD 25 producing wells Discovery well – Wilkerson 1-20H, January 2013 Well spacing: 5 wells/section Extended laterals being tested in 2015 SE Cana Woodford Shale 9,000 – 16,000 TVD 250 producing wells Discovery well – Lambakis 1-11H, May 2011 Well spacing ranges from 5 wells/section to 10 wells/section Extended laterals drilled where possible

Deep laterals are those equal to and greater than 10,000 feet total vertical depth; shallow laterals are those less than 10,000 feet total vertical depth. Location Selection Criteria Reserves by Product Mix Deep vs. Shallow Lateral Drilling Locations (1) Deep Shallow SCOOP Drilling Locations (~20,000 Net Acres) SCOOP Locations 15 NGLs Oil Gas DEEP SCOOP >10,000’ SHALLOW SCOOP <10,000’ Depth range from 9,000’ to 16,000’ TVD Substantially all of EROC acreage is held by production – no lease expirations Utilize existing, re-processed 3-D seismic to avoid faults in the Woodford section 96% of locations are extended 2 section laterals between 7,500’ and 10,000’ Industry evaluating proper spacing between 64 (10 wells/section) and 106-acre spacing (6 wells/section) EROC Operated Acreage EROC NonOp Acreage Drilling Rig Proved Probable Possible Woodford Oil Wells Woodford Gas Wells Woodford Wells WOC Woodford TVD Structure EROC 3D Seismic Legend 41% 59% 12% 50% 38%

EROC drilled Linton 1-5-32XH well in Township 5N6W Section 5 with 30% WI TVD: 16,148 feet Hz. Length: 8,719 feet IP 30: 234 Bbl/d, 7,786 Mcf/d EUR: 11.3 Bcfe gross, 3.3 Bcfe net Have 3 – 4 offset locations Active SCOOP Woodford non-op drilling program in 2015 33 gross/3.3 net wells to be drilled Net Capital: $40.2 MM Expect to grow SCOOP production by ~55% in 2015 Sharon Mae non-op development Drilling 5 non-op wells similar to Briar Unit EROC WI: 30% Net Capital: $14.2 MM Expect first production late 2015 Note: Liquids volumes are oil. 16 Selected Deep SCOOP Activity (Woodford >10,000’ Vertical depth) BRIAR (5 Well Dev) (NFX), WI: 36% AVG IP30: 734 Bbl/d, 4,635 Mcf/d First Sales: August 2014 Selected Deep SCOOP Activity Legend MCLEMORE 1-20H (EROC), WI: 42% IP30: 315 Bbl/d, 2,192 Mcf/d First Sales: April 2014 MADDUX 1-17H (EROC), WI: 53% IP30: 413 Bbl/d, 1,767 Mcf/d First Sales: June 2014 EROC Operated Acreage EROC NonOP Acreage Drilling Rig Proved Probable Possible Woodford Oil Wells Woodford Gas Wells Woodford Wells WOC Woodford TVD Structure EROC 3D Seismic MASHBURN (6 Well Dev) (NFX) WI: 4.4% AVG IP30: 486 Bbl/d, 7,237 Mcf/d First Sales: January 2015 LINTON 1-5-32XH (EROC) WI: 30% IP30: 234 Bbl/d, 7,786 Mcf/d First Sales: January 2015 SINGER 2-18-7XH (CLR) WI: 0.9% IP30: 351 Bbl/d, 5,556 Mcf/d KELLY (6 Well Dev) (NFX) WI: 2.9% IP30: 583 Bbl/d, 4,027 Mcf/d MARY J 1H-25X (NFX), WI: 3.9% IP30: 277 Bbl/d, 2,033 Mcf/d First Sales: November 2014 SHARON MAE (6 Well Dev) (NFX) WI: 30% Drilling HONEYCUTT (10 Well Dev) (CLR) WI: 12% Completing VANARKEL (8 Well Dev) (CLR) WI: 13% Drilling ERNESTEEN 1-21X28H (Vitruvian) WI: 11% Drilling Commentary Eagle Rock Operated Wells Eagle Rock Non-Operated Wells

Commentary Selected Goddard Activity 17 Note: IP data from January and February 2015 Continental Resources Investor Report and Oct 28, 2014 Newfield press release. Selected Goddard (Springer) Shale Activity The Springer play overlays the SE Cana Woodford play, increasing the value of EROC’s existing lease position 33 wells currently producing in the Springer Shale, 8 wells waiting on completion 3 rigs currently running in the Springer Industry has begun testing multi-section laterals and increased density tests at both 5 and 6 wells per section EROC participated in its first non-operated Springer test, the Burkes 1-28H well, in 2014 EROC is currently participating in two dual section laterals, the Celesta 1-05-32XH and the Virginia 1H-4X EROC evaluating drilling its first operated Springer test in 2015 ROBERT JO 1-8H (CLR) IP 24hr: 1,429 Boe/d BALL 1-19H(CLR) IP 24hr: 1,037 Boe/d LYNN 1-13H (CLR) IP 24hr: 1,897 Boe/d SWEET 1-2H (CLR) IP 24hr: 597 Boe/d GALA 1-22H (CLR) IP 24hr: 765 Boe/d BIRT 1-13H (CLR) IP 24hr: 793 Boe/d KL FULTON 1-21H(CLR) IP 24hr: 2,122 Boe/d WILKERSON 1-20H (CLR) IP 24hr: 2,038 Boe/d BURKES 1-28H (CLR) WI: 1% IP30:502 Boe/d (83% oil) HARTLEY DENSITY PILOT (CLR) Completing JARRED 1H-9X(NFX) IP 24hr: 1,950 Boe/d SCOTT TRUST 1-15H (CLR) IP 24hr: 403 Boe/d EROC Operated Acreage EROC NonOP Acreage Drilling Rig Goddard Oil Wells Goddard Gas Wells Goddard Wells WOC Goddard Updip Limit EROC 3D Seismic Goddard Prospects Legend Goddard Updip Limit SCHOOF 1-17H (CLR) IP 24hr: 1,465 Boe/d MARTHA 1-34H(CLR) IP 24hr: 935 Boe/d TANNENBAUM 1-23H 1-23H(CLR) Drilling CELESTA 1-5-32XH (CLR) WI: 0.1% IP30: 1,106 Boe/d (79% oil) RENEW CHICKASHA 1-21H (CLR) IP 24hr: 1,199 Boe/d JEANNA DENSITY PILOT (CLR) Completing VIRGINIA 1H-4X(NFX) WI: 2% Completing LANGWORTHY 1-33H (CLR) IP 24hr: 885 Boe/d

Alabama

Mature, liquids-rich, shallow-decline Smackover and Norphlet fields located in Southern Alabama 8% average annual decline 1Q15 net production of 16.7 Mmcfe/d and 190 LT/d of sulfur Average WI of 75% Continued opportunities exist to extend production by drilling replacement wells and installing field compression Eagle Rock operates the Big Escambia Creek (BEC) H2S treating and NGL processing plant that services field production Significant capital has been spent to upgrade BEC H2S treating facilities to reduce SO2 emissions and improve operational reliability EROC’s operated Flomaton plant has been down-sized to a compressor station and production has redirected to BEC, reducing overall operating expense & capex requirements and improving BEC’s operating life 1Q15 Daily Production Net 2P Reserves (1) 51.6 Bcfe 16.7 MMcfe/d Legend Eagle Rock Upstream Operations Eagle Rock Operated Wells Asset Map Alabama Reserves (1) BEC Field Fanny Church Field Flomaton Field 19 Alabama Overview Reserves as of 12/31/14. Oil 55% Gas 20% NGL 25% PDP 94% PDNP 1% PUD 2% PROB 3% Total Oil Gas NGL Equivalent Reserve Category (MMBbl) (Bcf) (MMBbl) (Bcfe) Proved Developed Producing 4.2 10.1 2.2 48.6 Proved Developed Non-Producing 0.0 0.1 0.0 0.4 Proved Undeveloped 0.1 0.1 0.0 0.9 Total Proved 4.4 10.3 2.2 49.9 Probable 0.2 0.4 0.0 1.7 Total 2P 4.6 10.8 2.2 51.6

BEC plant runtimes have been strong following the SuperClaus installation at the end of 2012 99% runtimes at the sulfur and cryogenic plant Planned 12-day routine turnaround in April 2015 temporarily reduced runtimes, resulting in an Adjusted EBITDA impact of approximately $4 MM in 2Q15 In August 2013, the Flomaton and Fanny Church untreated gas production was re-directed to the BEC plant for treating and processing, with oil stabilization and sales remaining at Flomaton Phase II, completed recently, converted Flomaton to a separation and compression station, permanently reducing operating expenditures, fuel and capital requirements IPC 2-11 #1, WI: 74% IP30: 216 Bb/d, 3,415 Mcf/d (FWS) Oct. 2013 EROC Acreage EROC NonOP Acreage Drilling Location Smackover Oil Wells Smackover Gas Wells Smackover Wells WOC Smackover Net Pay EROC 7/13 Boe/d Rate Legend 429 Smackover Net Pay & Boe/d Rate Map 20 Big Escambia Creek BOOTH RECOMPLETION, WI: 67% IP30: 227 Bd/d, 4,298 Mcf/d (FWS) Nov. 2015 PHILYAW RECOMPLETION, WI: 57% IP30: 293 Bd/d, 4,201 Mcf/d (FWS) Oct. 2015 ESCAMBIA ASSET CO. 4-16 #1 WI: 30.3% Evaluating drilling in 2016

Summary Financial Information

Summary Guidance Historical Summary Financial Results ($ in millions) Pro Forma Upstream Financials and Guidance 22 Expect G&A to decrease to a run-rate of $7.3 – $7.7 MM per quarter, as compared to 1Q15 G&A of $8.5 MM(1) ETP units distribute ~$1.0 MM per quarter ($1.015/unit 1Q15 distribution and 1.03 MM ETP common units owned) EROC intends to monetize the majority of its remaining ETP units by 6/30/15 to fund an acquisition or pay down debt Second Quarter 2015 Total Capex of ~$21 MM for 1Q15 Expected Production of 76 – 79 MMcfe/d for 2Q15 Full Year 2015 Total Capex of ~$75 MM for FY15 Expected Production of 75 – 78 MMcfe/d for FY15 Note: Financial results reflect the Upstream business only. 1Q15 G&A is net of severance payments. 2012A 2013A 2014A 1Q 2015A Volumes (MMcfe) Midcontinent 19,157 17,109 17,450 4,725 Alabama 5,837 5,328 5,113 1,504 Permian 1,985 2,000 2,059 469 East Texas/South Texas/Mississippi 3,292 2,635 2,199 472 Total Volumes 30,271 27,072 26,821 7,170 Total Volumes per Day (MMcfe/d) 82.9 74.2 73.5 79.7 Total Volumes per Day (MBoe/d) 13.8 12.4 12.2 13.3 Revenue Midcontinent $90.5 $104.3 $118.5 $16.7 Alabama 67.3 57.4 49.6 8.2 Permian 19.1 20.1 19.6 2.3 East Texas/South Texas/Mississippi 26.4 19.4 16.2 2.3 Total Upstream Asset $203.3 $201.3 $204.0 $29.5 Plus: Upstream Hedging 30.0 15.6 4.7 14.4 Plus: Other Miscellaneous 0.3 0.1 7.9 2.2 Total Upstream Revenues $233.6 $216.9 $216.5 $46.1 Operating Expenses Lease Operating Expense ($56.7) ($54.4) ($56.6) ($11.5) G&A (43.3) (42.7) (39.0) (9.1) EBITDA $133.6 $119.8 $120.9 $25.5 Capital Expenditures Maintenance $35.6 $46.2 $58.5 $10.3 Growth 128.4 88.2 76.1 16.7 Total Capital Expenditures $164.0 $134.4 $134.5 $27.0

Why Invest in Eagle Rock 23 Strong Balance Sheet Robust Hedge Portfolio Majority HBP Acquisition Focused High PDP Profile

Appendix

5.2 MMcfe/d 24.1 Bcfe 1Q15 Daily Production Net 2P Reserves (1) The Permian assets contain numerous fields located primarily in Ward, Pecos and Crane counties These fields produce from multiple intervals from the Yates-Seven River-Queen group through the Ellenburger formations 7% average annual decline rate Production essentially held flat in last five years with minimal capex by exploiting behind-pipe reserves in multiple horizons with low-risk workovers Ownership in the Permian region wells average 95% WI and 76% NRI EROC owns 22,666 net acres (96% HBP) Asset Map Permian Reserves (1) Legend Eagle Rock Upstream Operations Eagle Rock Operated Wells Horizontal Wells San Andres Grayburg Bone Springs Wolfcamp Devonian (Woodford) Permian Overview 25 Reserves as of 12/31/14. PDP 80% PDNP 10% PROB 10% Oil 51% Gas 28% NGL 21% Total Oil Gas NGL Equivalent Reserve Category (MMBbl) (Bcf) (MMBbl) (Bcfe) Proved Developed Producing 1.2 6.6 0.9 19.3 Proved Developed Non-Producing 0.1 0.9 0.1 2.4 Proved Undeveloped -- -- -- -- Total Proved 1.4 7.5 1.0 21.7 Probable 0.2 0.8 0.1 2.4 Total 2P 1.5 8.3 1.1 24.1

Whiting Petroleum is currently operating and expanding a successful CO2 flood immediately north of Eagle Rock’s position CO2 injection was initiated in Phase 1 in May 2007 First 3 phases have increased from 2,000 Bbl/d to 10,000 Bbl/d; incremental recovery since injection started is estimated to be approximately 10 MMBoe Whiting’s 3P recovery estimates range from 60 – 170 MMBoe Whiting’s cumulative oil (% HCPV) to cumulative injection estimates indicate incremental recoveries of up to 15% of OOIP Whiting is continuing full-field development of the CO2 flood Whiting is currently on Phase 4 of 8 planned phases Phase 6 offsetting EROC’s acreage is expected to occur in 2016 According to Whiting’s presentations, Phase 6 is expected to recover an incremental net 1.6 – 4.2 MMBoe per section (1.8 – 4.8 MMBoe gross) Whiting North Ward Estes CO2 Project Whiting CO2 Project Eagle Rock CO2 Project Areas Phase 1 Phase 2 Phase 3 Phase 4 Phase 7 Phase 6 Phase 5 Phase 8 Permian CO2 Potential 26

5.2 MMcfe/d 19.8 Bcfe 10% average annual decline rate East Texas Production primarily from the Smackover formation at 12,000 feet to 12,700 feet Produced gas includes approximately 30% hydrogen sulfide, nitrogen and CO2 Production is delivered to the third-party operated Eustace Processing Plant The Edgewood field contains sweet Cotton Valley production South Texas – Jourdanton field, Atascosa County Operate seven productive wells with 100% WI and 88% NRI Production primarily from the Edwards Carbonates at 7,300 feet to 7,400 feet, but production has been established in several horizons above the Edwards Mississippi Production primarily from the Smackover formation at 16,500 feet to 17,200 feet Operates two producing wells 1Q15 Daily Production Net 2P Reserves (1) ETX / STX / MS Reserves (1) Legend Eagle Rock Upstream Operations Eagle Rock Operated Wells Asset Map ETX / STX / MS Overview 27 Reserves as of 12/31/14. Oil 18% Gas 38% NGL 44% PDP 99% PDNP 1% Total Oil Gas NGL Equivalent Reserve Category (MMBbl) (Bcf) (MMBbl) (Bcfe) Proved Developed Producing 0.6 7.3 1.4 19.5 Proved Developed Non-Producing 0.0 0.1 0.0 0.3 Proved Undeveloped -- -- -- -- Total Proved 0.6 7.4 1.4 19.8 Probable -- -- -- -- Total 2P 0.6 7.4 1.4 19.8

Adjusted EBITDA and DCF Reconciliation 28 Source: 1Q 2015 Earnings Release. Three Months Ended December 31, 2015 2014 2014 Net loss to Adjusted EBITDA Net loss, as reported (58,719) $ (18,563) $ (344,591) $ Depreciation, depletion and amortization 14,645 20,406 22,615 Impairment 68,344 - 378,587 (Gain) loss from risk management activities, net (19,534) 10,323 (93,786) Total commodity derivative settlements 13,430 (4,846) 8,856 Non-cash mark-to-market of Upstream product imbalances 126 (6) 2 Restricted units non-cash amortization expense 1,856 2,583 1,208 Income tax benefit (826) (865) (2,767) Interest - net including realized risk management instruments and other expense 3,257 6,461 2,006 Discontinued operations 966 10,603 348 Loss on short-term investments 2,004 - 62,028 Adjusted EBITDA 25,549 $ 26,096 $ 34,506 $ Net loss to Distributable Cash Flow Net loss, as reported (58,719) $ (18,563) $ (344,591) $ Depreciation, depletion and amortization expense 14,645 20,406 22,615 Impairment 68,344 - 378,587 (Gain) loss from risk management activities, net (19,534) 10,323 (93,786) Total derivative settlements 13,430 (4,846) 8,856 Capital expenditures-maintenance related (10,326) (15,009) (14,584) Non-cash mark-to-market of Upstream product imbalances 126 (6) 2 Restricted units non-cash amortization expense 1,856 2,583 1,208 Income tax benefit (826) (865) (2,767) Cash income taxes (98) - - Discontinued operations 966 10,603 348 Loss on short-term investments 2,004 - 62,028 Distributable Cash Flow 11,868 $ 4,626 $ 17,916 $ Three Months Ended March 31,

29 SEC Reserve Disclosures The SEC requires oil and gas companies to disclose proved reserves quantities and allows for the optional disclosure of probable reserves. The Partnership has provided internally generated estimates for probable reserves in this presentation in accordance with SEC guidelines and definitions. “2P reserves” refer to the Partnership’s estimated aggregate proved and probable reserves as of December 31, 2014. The SEC prohibits companies from aggregating proved and probable reserves in filings with the SEC due to the different levels of certainty associated with each reserve category. Actual quantities that may be ultimately recovered from Eagle Rock’s interests may differ substantially from the estimates in this presentation. Factors affecting ultimate recovery include the scope of our proposed drilling program, which will be directly affected by the availability of capital, drilling, and production costs, commodity prices, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors, and actual drilling results, including geological and mechanical factors affecting recovery rates.

Information about the Proposed Merger and Where to Find It This communication does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval. In connection with the proposed Merger, Vanguard intends to file with the Securities and Exchange Commission (the “SEC”) a Registration Statement on Form S-4 that will include a preliminary joint proxy statement of Eagle Rock and Vanguard that also constitutes a preliminary prospectus of Vanguard. After the registration statement has been declared effective by the SEC, a definitive joint proxy statement/prospectus will be sent to (i) security holders of Eagle Rock seeking their approval with respect to the proposed Merger and (ii) security holders of Vanguard seeking their approval with respect to the issuance of Vanguard common units in connection with the proposed Merger. Vanguard and Eagle Rock also plan to file other documents with the SEC regarding the proposed transaction. INVESTORS AND SECURITY HOLDERS ARE URGED TO CAREFULLY READ THE JOINT PROXY STATEMENT/PROSPECTUS (INCLUDING ALL AMENDMENTS AND SUPPLEMENTS THERETO) AND OTHER DOCUMENTS FILED WITH THE SEC WHEN THEY BECOME AVAILABLE BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE PROPOSED MERGER. Investors and security holders will be able to obtain a free copy of the joint proxy statement/prospectus (if and when it becomes available) and other documents, once such documents are filed by Vanguard and Eagle Rock with the SEC, through the website maintained by the SEC at http://www.sec.gov. Copies of the documents filed with the SEC by Vanguard will be available free of charge on Vanguard’s internet website at http://www.vnrllc.com or by contacting Vanguard’s Investor Relations Department by email at investorrelations@vnrllc.com or by phone at (832) 327-2234. Copies of the documents filed with the SEC by Eagle Rock will be available free of charge on Eagle Rock’s internet website at http://www.eaglerockenergy.com or by contacting Eagle Rock’s Investor Relations Department by email at info@eaglerockenergy.com or by phone at (281) 408-1203. Participants in the Solicitation Vanguard, Eagle Rock, and their respective directors, executive officers and other members of their management and employees may be deemed to be “participants” in the solicitation of proxies in connection with the proposed Merger. Investors and security holders may obtain information regarding Vanguard’s directors, executive officers and other members of its management and employees in Vanguard’s Annual Report on Form 10-K for the year ended December 31, 2014, which was filed with the SEC on March 2, 2015, Vanguard’s proxy statement for its 2015 annual meeting, which was filed with the SEC on April 20, 2015, and any subsequent statements of changes in beneficial ownership on file with the SEC. Investors and security holders may obtain information regarding Eagle Rock’s directors, executive officers and other members of their management and employees in Eagle Rock’s Annual Report on Form 10-K for the year ended December 31, 2014, which was filed with the SEC on March 2, 2015, Eagle Rock’s proxy statement for its annual meeting, which was filed with the SEC on March 31, 2015 and any subsequent statements of changes in beneficial ownership on file with the SEC. These documents can be obtained free of charge from the sources listed above. Additional information regarding the direct and indirect interests of these individuals will also be included in the joint proxy statement/prospectus regarding the proposed transaction when it becomes available. 30