Investor Presentation November 2015

Legal Disclaimers Forward-Looking Statements This presentation contains, and the officers and representatives of the Partnership and its general partner may from time to time make, statements that are considered forward–looking statements within the meaning of the Securities Act of 1933 and the Securities Exchange Act of 1934. These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about our: business strategy; acquisition strategy; financial strategy; ability to make, maintain and grow distributions; the ability of our customers to meet their drilling and development plans on a timely basis or at all and perform under gathering and processing agreements; future operating results, including our forecast of Adjusted EBITDA and Distributable Cash Flow; future capital expenditures; and plans, objectives, expectations, forecasts, outlook and intentions. All of these types of statements, other than statements of historical fact included in this presentation, are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology. The forward-looking statements contained in this presentation are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this presentation are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors listed in the “Risk Factors” section in our Securities and Exchange Commission (“SEC”) filings and elsewhere in those filings. The forward-looking statements speak only as of the date made, and other than as required by law, we do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf. Oil and Gas Reserves The SEC requires oil and gas companies, in filings with the SEC, to disclose “proved oil and gas reserves” (i.e., quantities of oil and gas that are estimated with reasonable certainty to be economically producible) and permits oil and gas companies to disclose “probable reserves” (i.e., quantities of oil and gas that are as likely as not to be recovered) and “possible reserves” (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). Investors are urged to consider closely the disclosure in Sanchez Production Partners’ Annual Report on Form 10-K for the most recent fiscal year. 2

Transforming SPP

Transforming SPP (1) See Slide 12 (2) Reflects anticipated contribution to 2016 base case Adjusted EBITDA forecast before G&A expenses “SOG” refers to Sanchez Oil & Gas Corporation; “SN” refers to Sanchez Energy Corporation (NYSE: SN); “SEPI” refers to Sanchez Energy Partners I, LP, a SOG-operated private company The New Sanchez Production Partners Challenge: Orphan MLP with no sponsor Significant leverage with no ability to grow Asset base: Legacy PDP production Dominated by dry gas assets acquired in the 2007-08 timeframe Distributions: Suspended since 2009 Steps of the Transformation The Old SPP / Constellation Energy Partners EV: < $150 MM (1) (As of 9/30/2015) Established Relationship With SOG Completed First Production Transaction With SN Closed First Midstream Transaction With SN Adjusted EBITDA Adjusted EBITDA (2) Converted from LLC to LP ROFO on Significant, Identified Acquisition Inventory 4 Challenge met: Sponsored partnership Shared Services Agreement with SP Holdings, LLC; supported by the SOG operating platform ROFO on significant, identified acquisition inventory Executed transactions with SEPI and SN to deleverage and grow cash flows Asset base: Fixed fee gathering and processing assets with long-term minimum volume commitments Eagle Ford EWI and other Gulf Coast production assets Other legacy production assets (Mid-Continent) Distributions: An initial quarterly distribution per unit (“DPU”) of $0.40 payable in November 2015 Plans to grow DPU 15% per year through 2019 Production 100% Production 44% Midstream 56% EV: ~ $500 MM (1) (As of 10/14/2015) Production 40% Midstream 60%

2016 Forecast 5 See also SPP Hedging Program, Slide 24; Non-GAAP Financial Measures, Slide 25 Low Midpoint High Adjusted EBITDA 54.0 $ 57.0 $ 60.0 $ Distributable Cash Flow (2) 14.4 $ 17.4 $ 20.4 $ Common Unit Distributions 7.9 $ 7.9 $ 7.9 $ Distribution Coverage Ratio 1.8x 2.2x 2.6x NOTES: (1) Developed using the following key assumptions: - Hedges in place and forward prices as of 9/30/2015 - Divestiture of Mid-Continent assets completed in 2015; proceeds from sale used to reduce debt; hedges retained and restructured - No incremental asset acquisitions or divestitures - No common unit repurchases (2) Adjusted EBITDA, less: - Cash interest expense of $2.2 MM; - Distributions on Class B Preferred Units of $35.0 MM; and - Maintenance capital of $2.4 MM Base Case ($MM) (1)

Investment Highlights

SPP Investment Highlights As of 10/14/2015 Enterprise Value (1) ~ $500.0 MM Adjusted EBITDA (2) Midstream 60% Production 40% Proved Reserves (3) 21,036 MBOE % PDP (3) 84% (1) See Slide 12 (2) Reflects anticipated contribution to 2016 base case Adjusted EBITDA forecast before G&A expenses (3) As of 12/31/2014 based on forward prices; Includes SPP Eagle Ford Acquisition, which closed 03/31/2015 Visible Growth Identified acquisition inventory of midstream and production assets with value > $1 billion Growth profile targets 15% DPU CAGR through 2019 Significant liquidity to fund growth Premier Asset Base With Stable Distributable Cash Flow 15 year fixed fee gathering agreement with minimum volume commitments Well structured portfolio of production assets Limited commodity price exposure through active hedging Minimal capital requirements Well-Sponsored Partnership Aligned with Sanchez Energy Corporation (“SN”) and Sanchez Oil & Gas Corporation (“SOG”) Low cost operator with strategically located assets in a highly prolific and economic basin ROFO on SN midstream assets stemming from continued development Capital Optimization Focus Well-bore interests with flat production profile, no drilling requirements, no maintenance capital and no incremental G&A expense Well-hedged, stable cash flow profile for rolling five year periods Facilitates the cycling of capital to optimize the value of portfolio assets Conservative Financial Management Target Debt / Adjusted EBITDA of < 3.0x Target distribution coverage of 1.2x Target borrowing base utilization of < 80% 7 SP Holdings, LLC (DE) Sanchez Production Partners LP (NYSE MKT: SPP) Sanchez Production Partners GP LLC (DE) 100 % 100 % GP Shared Services Agreement / IDRs EFS/Gulf Coast Assets Public Unitholders (LP Interests) SOG Operating Platform Credit Facility $200 MM Borrowing Base Assets Targeted for Divestiture Assets Retained Mid - Continent Assets Sanchez Family, SOG & Insiders (LP Interests) Organizational Structure 8.3% 91.7% Preferred Unitholders Class A ($17.4 MM Face) Class B ($350 MM Face) Western Catarina Midstream Assets

NYSE MKT: SPP (IPO Dec-06 as “CEP”) NYSE: SN (IPO Dec-11) Visible Growth CEP Acquires Gulf Coast Assets from SEP I, LP* (Aug-13) SN acquires Catarina assets from RDS (May-14) LLC-LP conversion implemented with the overwhelming support of SPP’s unitholders (Mar-15) SPP Acquires Palmetto EWI Assets from SN (Mar-15) * Sanchez Energy Partners I, LP, a SOG-operated private company SN grows its Eagle Ford asset base, through the drill bit and acquisitions Development/Growth 2012 2013 2014 Business development relationship between SPP and SOG, a committed sponsor, initiated Distributions Initiated at $0.40/unit/quarter (Nov-15) 2015 and Beyond CEP asset base managed without a sponsor; significant leverage with no ability to grow Yield/Distributions Other targets with value > $1B identified by SN (Ongoing) SPP targets DPU growth of 15% per year (Expected 2015-19) SPP Acquires Western Catarina Midstream Assets from SN (Oct-15) Ongoing Eagle Ford development focused on Catarina drilling activity leads to growth and enhanced performance Cash Flowing Assets Monetized Proceeds Reinvested Additional Stable Cash Flows Shared Services Agreements executed and implemented; CEP (public LLC) is rebranded “SPP” 8

Sanchez Production Partners LP Asset Base Midstream Production % Adjusted EBITDA (1) 60% 40% Total Proved Reserves (2) N/A 21,036 MBOE (84% PDP) EFS / Gulf Coast Assets (2) 6,157 MBOE (100% PDP) Mid-Continent Assets (2) 14,879 MBOE (77% PDP) Houston, Texas Headquarters (1) Reflects anticipated contribution to 2016 base case Adjusted EBITDA forecast before G&A expenses (2) As of 12/31/2014 based on forward prices; Includes SPP Eagle Ford Acquisition, which closed 03/31/2015 Premiere Asset Base Western Catarina Midstream Assets Located in a dedication area covering approximately 35,000 net acres in Dimmit and Webb Counties, TX Includes over 150 miles of gathering lines (4” to 12” diameter), compressors, tanks, vessels and other miscellaneous production equipment Supports production activities across SN’s Catarina asset Long-term fee-based throughput and gathering agreement with SN SPP Production Assets Gulf Coast non-operated assets acquired from Sanchez Energy Partners I, LP in 2013 Eagle Ford Shale (“EFS”) assets acquired from SN in 2015 Mid-Continent assets targeted for divestiture include: Cherokee Basin operated and non-operated assets Other non-operated assets, including Woodford Shale assets and Central Kansas Uplift assets Targeted for Divestiture 9

Well-Sponsored Partnership Sanchez Oil & Gas Corporation (“SOG”) 1972 Private operating platform with ~ 200 employees Experienced management Technical and operational expertise Active business development Shared Services and Business Development Relationships (1) Sanchez Energy Corporation (2) (NYSE: SN) 2011 (IPO) Structure: Public C-Corp Enterprise Value: > $2 billion Asset Focus: Oil resource focus Eagle Ford Shale Tuscaloosa Marine Shale Reserves: 130 MMBOE (at 12/31/2014) Production: 52,844 BOE/D (15Q3 Average) Acres: ~207,000 Acquired $1.1 billion in assets since IPO Credit Rating (Sr. Unsecured): B / B2 Sanchez Production Partners (NYSE MKT: SPP) 2006 (IPO) Structure: Publicly-traded limited partnership Enterprise Value: ~ $500 MM (3) Asset Focus: Stable cash producing assets Gathering and processing midstream assets Escalating working interests Integrated approach to visible growth DPU initiated at $0.40 /unit in November 2015 Plans to grow DPU 15% per year through 2019 Development / Growth Yield / Distributions Operations and Technical Support (1) Covers operational and technical support and business development activities; includes allocation of G&A (2) Source: SN Corporate Presentation- November 2015; SN market data as of 11/6/2015 (3) See Slide 12 Right of First Offer 10

Capital Optimization Focus Growth at SPP generates currency for SN’s future growth SN invests capital in development drilling and acquisitions Produces growth in production, infrastructure and cash flow Assets sold to SPP Large inventory of mature cash producing assets fit best in the MLP model Cash flows at SPP valued on yield Ability to pay market price to SN while capturing economic uplift for SPP Ability to show accretion 4 1 2 3 Perpetuates Growth Platform Capital Deployed Assets Sold As “EWI” (1) Accelerates IRRs to SN Transaction Value Exchanged Provides Stable Cash Flows To SPP Optimizes Cost of Capital Yr. 0-2 Cash Flow To SN Development/Growth Yield/Distributions Improves Credit Metrics (1) “EWI” refers to an “escalating working interest” asset structure; See Appendix I 11

Conservative Financial Management 12 (1) Effective date of the Western Catarina Midstream Transaction (2) Based on ~3.1 MM units outstanding and a $10.79/unit closing price of SPP on NYSE MKT as of 9/30/2015 (3) Based on ~3.0 MM units outstanding and a $10.20/unit closing price of SPP on NYSE MKT as of 10/14/2015 (4) Represents the value of contributed capital plus paid in kind distributions as of the date shown, valued at a $16.00/unit notional conversion price after adjustment for the 1:10 reverse split effective 8/4/2015 ($ in 000’s unless noted) 9/30/2015 Adj. Pro Forma 10/14/2015 (1) Cash & Cash Equivalents 8,963 $ (5,104) $ 3,859 $ Borrowing Capacity 4,000 $ 90,000 $ 94,000 $ = Borrowing Base 110,000 90,000 200,000 - Debt Outstanding 106,000 106,000 Total Liquidity 12,963 $ 84,896 $ 97,859 $ = Borrowing Capacity 4,000 90,000 94,000 + Cash & Equivalents 8,963 (5,104) 3,859 Net Debt 97,037 $ 5,104 $ 102,141 $ = Debt Outstanding 106,000 106,000 - Cash & Equivalents 8,963 (5,104) 3,859 Enterprise Value 148,832 $ 352,172 $ 501,004 $ = Market Capitalization, Common Units (2),(3) 33,985 (2,932) 31,053 + Class A Preferred Units (4) 17,809 17,809 + Class B Preferred Units - 350,000 350,000 + Net Debt 97,037 5,104 102,141 Net Debt / Enterprise Value 65% 20%

Recent Financial Results

Recent Financial Results 14 (1) Includes lease operating expenses, production taxes, general and administrative expenses and unit-based compensation program expenses (2) Includes loss (gain) on asset sale (3) Includes accretion expense and asset impairments (4) Includes litigation charges of $0.3 MM, transaction charges of $1.2 MM, and out of period charges of $1.9 MM in 15Q3 See Reconciliation Items, Slide 26 15Q3 vs. 15Q2 15Q3 vs. 14Q3 ($ in 000’s unless noted) 15Q3 15Q2 15Q3 14Q3 Production (MBOE) 367 402 367 380 Oil and gas sales 13,320 $ 14,683 $ 13,320 $ 15,802 $ Gain (loss) on mark-to-market activities 12,305 (9,902) 12,305 5,594 Revenue 25,625 $ 4,781 $ 25,625 $ 21,396 $ Operating expenses (1) 13,013 9,687 13,013 9,872 Cost of sales 139 125 139 404 Other (income) expense (2) (50) (17) (50) (76) EBITDA 12,523 $ (5,014) $ 12,523 $ 11,196 $ DD&A (3) 4,053 4,205 4,053 5,030 Interest expense, net 672 1,122 672 511 Income tax expense 3 - 3 - Net income (loss) 7,795 $ (10,341) $ 7,795 $ 5,655 $ Adjusted EBITDA, As Reported 295 $ 5,230 $ 295 $ 5,688 $ Add Back: Non-Recurring Items (4) 3,406 - 3,406 - Equals: Adjusted EBITDA Excluding Non-Recurring Items 3,701 $ 5,230 $ 3,701 $ 5,688 $

Appendix I Escalating Working Interest Advantage

From the Seller’s perspective, monetization of a portion of the well’s stable cash flow in an EWI structure enhances realized rates of return and provides capital for redeployment in the asset base In this example, the sale of the EWI results in: NPV $1.5MM (unchanged) IRR 40.5% Eagle Ford wells are characterized by fast payback during a period of steep decline followed by a longer period of stable cash flow and low decline for the remaining life of the well Years 0 - 2 = ~ 40% of production and 60% of PV Years 2+ = ~ 60% of production and 40% of PV In this example, over the full life of the well the developer expects: NPV $1.5MM IRR 32.9% EWI Case Study: Repeatable “Win/Win” Structure(1) Typical Eagle Ford Well EWI – Seller’s Perspective EWI – MLP Buyer’s Perspective (1) Assumes initial well cost of $4 MM; Three year EWI sold in Year 2 at PV10; Flat price deck of $55/BBL and $3/MCFE; Catarina type curve EWI Seller Achieves Payback, Monetizes FCF For Redeployment, and Enhances IRR EWI Buyer Achieves “Levelized” Production, Which Supports Distributions PV t=0 Mo. $5.8 MM PV t=24 Mo. $1.8 MM From the MLP Buyer’s perspective, the purchase of an EWI, together with hedging (at closing) of the resulting “levelized” production from the asset, provides stable cash flow to support distributions over time while mitigating the need for maintenance capital 16 $ 0.0 $ 1.0 $ 2.0 $ 3.0 $ 4.0 $ 5.0 $ 6.0 0 12 24 36 48 60 72 84 96 108 120 Remaining PV ($mm) Months $ 0.0 $ 1.0 $ 2.0 $ 3.0 $ 4.0 $ 5.0 $ 6.0 0 12 24 36 48 60 72 84 96 108 120 Remaining PV ($mm) Months $ 0.0 $ 1.0 $ 2.0 $ 3.0 $ 4.0 $ 5.0 $ 6.0 0 12 24 36 48 60 72 84 96 108 120 Remaining PV ($mm) Months

SPP Eagle Ford Acquisition Illustrated below, the SPP Eagle Ford Acquisition was structured to offset natural production declines, minimize maintenance capital requirements, and maintain more stable cash flows over the life of the asset for SPP The escalating working interests acquired from SN are expected to “levelize” production to SPP in years one through five Hedges covering a high percentage of production in years one through five, executed by SN, were novated to SPP at closing Escalating Working Interest Purchased From SN By SPP SN Retains EWI Year = * * Factors shown exclude natural gas liquids production Stable Cash Flow, Low Decline In this EWI structure (closed in Mar-15), SPP’s WI increases annually which, when applied to the production total, yields flat SPP production in EWI Years 1 - 5 SPP Owns 17 - 200 400 600 800 1,000 1,200 1 2 3 4 5 MBOE Per Year SPP PDP PDP Total SPP Receives: 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024+ Avg. Working Interest 18.2% 26.1% 33.5% 40.6% 47.5% 47.5% 47.5% 47.5% 47.5% 47.5% Avg. Net Revenue Interest 13.2% 18.9% 24.2% 29.4% 34.3% 34.3% 34.3% 34.3% 34.3% 34.3% % PDP Total Shown Above 33.1% 50.7% 66.2% 80.9% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% Hedges as a % of Acquired Interests* 95.0% 90.0% 85.0% 85.0% 80.0%

SPP Eagle Ford Acquisition (Closed March 2015) Source: Graphics from the SN Corporate Presentation – December 2014; Transaction details provided by SN and verified by SPP EURs (MBOE) 450 – 750 % Oil / Liquids 75% / 89% Palmetto Well Characteristics Trend Eagle Ford Shale Field Palmetto Location (County) Gonzales County, TX Type Wellbore Interests Operator Marathon Well (Reserve) Type Producing (PDP Only) Well Count 59 Transaction Structure Escalating Working Interests Avg. WI / NRI – Year 1 18.3% / 13.2% Avg. WI / NRI – Years 5+ 47.5% / 34.3% Forecast Net Production , 2015 through 2019 ~1,000 BOE/D Producing Horizons Upper Eagle Ford, Lower Eagle Ford Asset Mix, 2015-19 84.2% Oil/Liquids, 15.8% Natural Gas Asset Mix, Life Cycle 83.9% Oil/Liquids, 16.1% Natural Gas % PV10 Value Years 1 – 5 63.3% Assets Included In Transaction Producing Horizon Trend Field Type Curve Geology 18 LEF BUDA UEF

Appendix II Western Catarina Midstream Transaction

Total Net Acres ~106,000 Average Working Interest 100% Average Net Revenue Interest 75% Planned Well Spacing (Acres) 75 – 100 Net Identified Drilling Locations 1,250 - 1,650 Gross Wells On Production (1) 264 Awaiting / Undergoing Completions (1) 18 Western Catarina The Catarina Field Acreage, Inventory & Operational Overview Lower Eagle Ford Well Economics (1) Well status as of 9/30/2015 Source: SN Corporate Presentation – November 2015 Acquired by SN from Royal Dutch Shell in June 2014 Significant South Texas (Eagle Ford Shale) acreage position, larger in size than the Houston Metropolitan area Western Catarina (~43,000 net acres) Early results support stacked pay development in three Eagle Ford benches; Upper, Middle, & Lower Eagle Ford Well performance currently exceeding high end Catarina type curve through first year of development Partially developed; Excellent offset operator results Central Catarina (~26,000 net acres) Early results in South-Central Catarina in line with the strongest to date in the asset: 30-Day IP Rates of nearly 1,350 BOE/D Expected further future development in South-Central region in 2016 Exploration area; full 3D seismic coverage; inversion processing in progress Eastern Catarina (~37,000 net acres) Early results ~50% above existing wells in Eastern Catarina Substantial number of potential Lower Eagle Ford drilling locations EURs (MBOE) 600 – 700 D&C Costs ($MM) $4.5 F&D Cost ($ / BOE) $8.57 – $10.00 IRR @ $60 / BBL & $3.75 / MCF 35%+ Central Catarina Eastern Catarina 20

Gathering and processing assets originally constructed by Royal Dutch Shell as part of the infrastructure for the development of the Catarina Field Development and construction of the assets were promulgated under rights embedded in the lease agreement Pipeline capacity can be easily expanded through small compression projects at nominal costs (~$1 MM/year in growth capital planned) Western Catarina Midstream Asset Overview Asset Details Asset Overview Western Catarina Dedicated Acreage (1) Covers ~ 85,000 net development acres 21 Dedicated Acreage ~ 35,000 acres (1) Pipeline Assets ~ 150 miles of gathering lines (ranging in diameter from 4” to 12”) Facilities Four main gathering and processing facilities, which include: Eight stabilizers (5,000 BBL/D) ~ 25,000 BBL storage capacity NGL pressurized storage ~ 18,000hp compression ~ 300 MMCF/D dehydration capacity Interconnections Crude oil: Plains All American Pipeline header system delivered to Gardendale Terminal Connectivity to all four takeaway pipelines to Corpus Christi Natural gas: Southcross Energy Kinder Morgan Energy Transfer Enterprise Products Targa Resources Interconnections located at each of the four main processing facilities Capacity Condensate: 40,000 BBL/D Natural Gas: 200 MMCF/D

Western Catarina Midstream Transaction Buyer: Sanchez Production Partners LP (“SPP”) Seller: SN Catarina, LLC, a wholly-owned subsidiary of Sanchez Energy Corp. (“SN”) Purchase Price: ~ $345 MM Effective Date: 10/14/2015 Closed: 10/14/2015 Assets: All of the issued and outstanding membership interests in Catarina Midstream, LLC, which owns ~ 150 miles of gathering lines, compressors, tanks, vessels and other gathering and processing infrastructure in Dimmit and Webb Counties, TX Transaction Agreement: Purchase and Sale Agreement; includes right of first offer on additional midstream asset sales by SN Gathering Agreement: Effective upon closing; 15 year term with fixed rates and a five year “Minimum Quarterly Quantity” Dedicated Acreage: ~ 35,000 acres in Western Catarina, SN’s most active development area Operations: Managed with the support of SOG since SN’s June 2014 acquisition Financing Overview: Financed through a preferred equity raise with Stonepeak Infrastructure Partners and available cash with incremental new debt capacity reserved for future growth 22

Appendix III Other Information

SPP Hedging Program(1) (1) As of 9/30/2015 (2) NYMEX swaps NOTE: The Partnership accounts for derivatives using the mark-to-market accounting method SPP intends to hedge a high percentage of PDP for up to five years SPP’s hedge strategy primarily utilizes swaps and costless collars, as warranted by market conditions Hedges executed with SPP’s lenders and subject to limitations in SPP’s Credit Facility Hedges in place result in the following fixed price positions, which were in-the-money $28.1 MM as of 9/30/2015: 24 Hedge Positions Balance at 9/30/2015 2015 2016 2017 2018 2019 Natural Gas Hedges (2) $/MMbtu 4.17 4.14 3.52 3.58 3.62 MMbtu 1,118,334 4,108,556 296,048 295,683 277,888 Crude Hedges (2) $/Bbl 75.64 73.82 64.80 65.40 65.65 Bbl 109,582 441,239 213,003 212,555 199,768

Non-GAAP Financial Measures Use of Non-GAAP Financial Measures – Historic Financials: EBITDA and Adjusted EBITDA are non-GAAP financial measures that are reconciled to their most comparable GAAP financial measure under Reconciliation of Non-GAAP Financial Measures in this presentation. The reconciliations are only intended to be reviewed in conjunction with the presentation to which they relate. EBITDA is defined as net income (loss) adjusted by interest (income) expense, net; income tax expense (benefit); depreciation, depletion and amortization; asset impairments; and accretion expense. Adjusted EBITDA is defined as EBITDA adjusted by (gain) loss on sale of assets; (gain) loss from equity investment; unit-based compensation programs; and (gain) loss from mark-to-market activities. These financial measures are used as a quantitative standard by our management and by external users of our financial statements such as investors, research analysts and others to assess the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness; and our operating performance and return on capital as compared to those of other companies in our industry, without regard to financing or capital structure. These financial measures are not intended to represent cash flows for the period, nor are they presented as a substitute for net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Use of Non-GAAP Financial Measures – Forecast Financials: In addition to Adjusted EBITDA, we provide a forecast of Distributable Cash Flow in this presentation. Distributable Cash Flow is defined as Adjusted EBITDA less cash interest expense; distributions on preferred units; and maintenance capital. We are unable to reconcile our forecast range of Adjusted EBITDA or Distributable Cash Flow to GAAP net income, operating income or net cash flow provided by operating activities because we do not predict the future impact of adjustments to net income (loss), such as (gains) losses from mark-to-market activities and equity investments or asset impairments due to the difficulty of doing so, and we are unable to address the probable significance of the unavailable reconciliation, in significant part due to ranges in our forecast impacted by changes in oil and natural gas prices and reserves which affect certain reconciliation items. Summary of Non-GAAP Financial Measures : 25 Non-GAAP Measure Slide(s) Where Used in Presentation Most Comparable GAAP Measure Slide Containing Reconciliations Adjusted EBITDA, EBITDA 5, 14 Net Income 26

Reconciliation Items 26 (1) Includes accretion expense and asset impairments (2) Includes $1.0 MM in charges related to the implementation of the Services Agreements in 14Q2; employee severance charges of $4.4 MM, transaction charges of $0.6 MM, conversion charges of $0.3 MM, and litigation charges of less than $0.1 MM in 15Q1; and litigation charges of $0.3 MM, transaction charges of $1.2 MM, and out of period charges of $1.9 MM in 15Q3; Excluding these non-recurring items in the quarterly results shown, 15Q1 Adjusted EBITDA was $4.9 MM and 15Q3 Adjusted EBITDA was $3.7 MM; Excluding these non-recurring items in year-to-date results, YTD 14Q3 Adjusted EBITDA was $20.7 MM and YTD 15Q3 Adjusted EBITDA was $13.8 MM (3) Includes lease operating expenses, production taxes, general and administrative expenses, and unit-based compensation program expenses (4) See footnote (2) for a description of Non-recurring items Reconciliation of Net Income (Loss) to Adjusted EBITDA ($ in 000s) 14Q3 YTD 14Q3 15Q1 15Q2 15Q3 YTD 15Q3 Net income (loss) 5,655 $ (2,295) $ (89,986) $ (10,341) $ 7,795 $ (92,532) $ Interest expense, net 511 1,569 646 1,122 672 2,440 Income tax expense - - - - 3 3 DD&A (1) 5,030 13,894 86,238 4,205 4,053 94,496 EBITDA 11,196 $ 13,168 $ (3,102) $ (5,014) $ 12,523 $ 4,407 $ (Gain) loss on sale of assets - (23) (59) (54) 2 (111) Unit-based compensation programs 86 1,216 1,992 396 75 2,463 (Gain) loss on mark-to-market activities (5,594) 5,318 732 9,902 (12,305) (1,671) Adjusted EBITDA (1),(2) 5,688 $ 19,679 $ (437) $ 5,230 $ 295 $ 5,088 $ Operating Expense to Operating Cost ($/BOE) 14Q3 YTD 14Q3 15Q1 15Q2 15Q3 YTD 15Q3 Operating expenses (3) 25.99 $ 27.40 $ 45.78 $ 24.12 $ 35.44 $ 34.34 $ Less: Unit-based compensation included in operating expense 0.23 1.07 6.15 0.99 0.20 2.25 Less: Non-recurring items (4) - 0.88 16.43 - 9.28 7.99 Operating cost 25.76 $ 25.45 $ 23.20 $ 23.13 $ 25.96 $ 24.10 $