8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report (date of earliest event reported): November 10, 2015

Sanchez Production Partners LP

(Exact name of registrant as specified in its charter)

Delaware	001-33147	11-3742489
(State or other jurisdiction of	(Commission	(IRS Employer
incorporation)	File Number)	Identification No.)

1000 Main Street, Suite 3000
Houston, TX	77002
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (713) 783-8000

(Former name or former address, if changed since last report.)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

oWritten communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

oSoliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

oPre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

oPre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 1.01Entry into a Material Definitive Agreement.

Credit Agreement Amendment

A description of the Credit Agreement Amendment is included in Item 2.03 below and incorporated herein by reference.

Item 2.02Results of Operations and Financial Condition.

On November 12, 2015, Sanchez Production Partners LP (the “Partnership”) issued a press release announcing its third quarter financial results. A copy of the press release is furnished as a part of this Current Report on Form 8-K as Exhibit 99.2 along with the earnings presentation slides as Exhibit 99.3.

In accordance with General Instruction B.2 of Form 8-K, the information in this Item shall not be deemed “filed” for the purpose of Section 18 of the Securities Exchange Act of 1934, as amended, nor shall it be deemed incorporated by reference in any filing.

Item 2.03Creation of a Direct Financial Obligation or an Obligation under an Off-Balance Sheet Arrangement of a Registrant.

On November 12, 2015, the Partnership, as borrower, entered into that certain Third Amendment to Third Amended and Restated Credit Agreement with Royal Bank of Canada, as administrative agent and collateral agent and the lenders party thereto (the “Credit Agreement Amendment”), pursuant to which, among other matters, the parties amended (i) the restricted payment covenant to permit the Unit Repurchase Plan described in Item 8.01 below so long as the Partnership would have unused borrowing capacity in an amount not less than 15% of the borrowing base and (ii) the use of loan proceeds to redeem units pursuant to the Unit Repurchase Plan so long as the unused borrowing capacity, after giving effect to any redemption, is not less than 10% of the reserved-based component of the borrowing base.

The foregoing description of the Credit Agreement Amendment does not purport to be complete and is qualified in its entirety by reference to such document, which is filed as Exhibit 10.1 hereto and incorporated herein by reference.

Item 7.01Regulation FD.

On November 13, 2015, the Partnership posted an updated investor presentation on its website. A copy of this presentation is attached hereto as Exhibit 99.3 and is incorporated herein by reference.

In accordance with General Instruction B.2 of Form 8-K, the information in this Item shall not be deemed “filed” for the purpose of Section 18 of the Securities Exchange Act of 1934, as amended, nor shall it be deemed incorporated by reference in any filing.

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Item 8.01Other Events.

On November 10, 2015, the board of directors of the Partnership’s general partner approved a $10 million common unit repurchase plan (the “Unit Repurchase Plan”).  Under the new Unit Repurchase Plan, the Partnership may repurchase up to $10 million of its common units.  The Partnership may repurchase its common units from time to time, in amounts and at prices the Partnership deems appropriate, subject to market conditions and other considerations.  The Partnership’s repurchase may be executed using open market purchases, privately negotiated agreements or other transactions.  The repurchases will be funded from cash on hand or available borrowings.  The Unit Repurchase Plan may be suspended or discontinued at any time without prior notice.

On November 10, 2015, the board of directors of the Partnership’s general partner declared a third quarter 2015 cash distribution on its common units of $0.40 per unit ($1.60 per unit annualized) payable on November 30, 2015 to holders of record on November 20, 2015.  The Partnership also declared a third quarter 2015 paid-in-kind distribution of 2.5% on its Class A preferred units payable on November 30, 2015 to holders of record on November 20, 2015.  A copy of the press release announcing the distributions is filed as Exhibit 99.1 hereto and incorporated herein by reference.

Item 9.01Financial Statements and Exhibits.

(d)Exhibits.

Exhibit No.	Exhibit
10.1	Third Amendment to Third Amended and Restated Credit Agreement, dated as of November 12, 2015, among Sanchez Production Partners LP, Royal Bank of Canada, as administrative agent and collateral agent, and the lenders party thereto
99.1	Press Release, dated November 10, 2015
99.2	Press Release, dated November 12, 2015
99.3	Investor Presentation

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	SANCHEZ PRODUCTION PARTNERS LP
	By: Sanchez Production Partners GP LLC,
	its general partner
Date: November 13, 2015	By:	/s/ Charles C. Ward
		Charles C. Ward
		Chief Financial Officer

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Exhibit Index

Exhibit No.	Exhibit
10.1	Third Amendment to Third Amended and Restated Credit Agreement, dated as of November 12, 2015, among Sanchez Production Partners LP, Royal Bank of Canada, as administrative agent and collateral agent, and the lenders party thereto
99.1	Press Release, dated November 10, 2015
99.2	Press Release, dated November 12, 2015
99.3	Investor Presentation

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EX-10.1

Exhibit 10.1

Execution Version

THIRD AMENDMENT

TO THIRD AMENDED AND RESTATED CREDIT AGREEMENT

This THIRD AMENDMENT TO THIRD AMENDED AND RESTATED CREDIT AGREEMENT (this “Amendment”), dated as of November 12, 2015, is among SANCHEZ PRODUCTION PARTNERS LP, a Delaware limited partnership (the “Borrower”), the guarantors party hereto (the “Guarantors”), each of the Lenders party hereto, and ROYAL BANK OF CANADA, as administrative agent (in such capacity, the “Administrative Agent”), and as collateral agent (in such capacity, the “Collateral Agent”), and relates to that certain Third Amended and Restated Credit Agreement, dated as of March 31, 2015 (as amended, restated, modified or supplemented from time to time prior to the date hereof, the “Existing Credit Agreement”; and as amended hereby, the “Credit Agreement”), among the Borrower, the Lenders, the Administrative Agent, the Collateral Agent, and ROYAL BANK OF CANADA, as letter of credit issuer.

WITNESSETH:

WHEREAS, the Borrower desires to repurchase or redeem a portion of its outstanding common Equity Interests by making Restricted Payments in an amount up to $10,000,000 in the aggregate during the remaining term of the Credit Agreement, which Restricted Payments may be made from proceeds of Loans under the Credit Agreement provided certain conditions are satisfied both before and after giving effect thereto;

WHEREAS, the parties hereto desire to correct certain scrivener’s errors in the Existing Credit Agreement with respect to the inconsistent use of “Adjusted LIBO Rate”;

WHEREAS, Section 12.02 of the Existing Credit Agreement provides that the Borrower and the Lenders may amend the Existing Credit Agreement and the other Loan Documents for certain purposes; and

NOW, THEREFORE, in consideration of the premises contained herein and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto, intending to be legally bound hereby, agree as follows:

Section 1.Definitions.  Unless otherwise defined in this Amendment, each capitalized term used in this Amendment has the meaning assigned to such term in the Credit Agreement.

Section 2.Amendments to the Credit Agreement.  The Credit Agreement is hereby amended as follows:

(a)The definition of “Eurodollar” in Section 1.01 of the Credit Agreement is amended by inserting the word “Adjusted” immediately prior to the words “LIBO Rate” therein.

(b)Clause (b) of Section 3.02 of the Credit Agreement is hereby amended by inserting the word “Adjusted” immediately prior to the words “LIBO Rate” therein.

(c)The last sentence of clause (e) of Section 3.02 of the Credit Agreement is hereby amended by inserting the phrase “, Adjusted LIBO Rate” immediately prior to the words “or LIBO Rate” therein

(d)Subclause (i) of Section 3.02(f) of the Credit Agreement is hereby amended by inserting the words “Adjusted LIBO Rate or the” immediately prior to the words “LIBO Rate” therein.

(e)Subclause (ii) of Section 3.02(f) of the Credit Agreement is hereby amended by inserting the word “Adjusted” immediately prior to the words “LIBO Rate” therein.

(f)Subclause (i) in the second sentence of Section 5.02 of the Credit Agreement is hereby amended by inserting the word “Adjusted” immediately prior to the words “LIBO Rate” therein.

(g)Clause (b) of Section 7.23 of the Credit Agreement is amended and restated to provide:

“(b) for general business purposes, including Restricted Payments, provided that if the Borrower would have unused borrowing capacity that can be accessed under this Agreement in an amount less than 10% of the amount of the RBL Component in effect at such time before or after giving effect to the requested Loan or Letter of Credit, then no proceeds of any Loan or any Letter of Credit may be used to fund Restricted Payments under Section 9.04,”

(i)Section 9.04 of the Credit Agreement is hereby amended by deleting the phrase “and subject to Section 7.23,” from clause (iii) thereof, by deleting the word “and” immediately preceding clause (vi) thereof, deleting the period at the end of clause (vi) and by inserting the following new clause (vii) immediately thereafter:

“and (vii) so long as no Borrowing Base Deficiency, Default or Event of Default has occurred and is continuing or would result therefrom and, after giving effect to any Borrowings under this Agreement, the Borrower would have unused borrowing capacity that can be accessed under this Agreement in an amount not less than 15% of the amount of the Borrowing Base in effect at such time, the Borrower may make Restricted Payments in an aggregate amount not exceeding $10,000,000 prior to the Maturity Date to repurchase or redeem its common Equity Interests.”

Section 3.Ratification.  Except as expressly amended, modified or waived herein, each of the Borrower and the Guarantors hereby ratifies and confirms all of the Obligations under the Credit Agreement and the other Loan Documents to which it is a party, and all references to the Credit Agreement, the Mortgages and the Notes in any of the Loan Documents shall be deemed to be references to the Credit Agreement, the Mortgages and the Notes as amended, modified or waived hereby.

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Section 4.Effectiveness.  This Amendment shall become effective on the date (the “Amendment Effective Date”) on which each of the following conditions is satisfied:

(a)the Administrative Agent shall have received counterparts of this Amendment executed by the Administrative Agent, the Collateral Agent, the Borrower, the Guarantors and the Majority Lenders;

(b)the Borrower and each Guarantor shall have confirmed and acknowledged to the Administrative Agent and the Lenders, and by its execution and delivery of this Amendment the Borrower and each Guarantor do hereby confirm and acknowledge to the Administrative Agent and the Lenders, that (i) the execution, delivery and performance of this Amendment has been duly authorized by all requisite limited partnership or limited liability company action, as applicable, on the part of the Borrower or such Guarantor, as applicable, (ii) the Credit Agreement and each other Loan Document to which it is a party constitute valid and legally binding agreements enforceable against the Borrower or such Guarantor, as applicable, in accordance with their respective terms, except as such enforceability may be limited by bankruptcy, insolvency, reorganization, moratorium, fraudulent transfer or other similar laws relating to or affecting the enforcement of creditors’ rights generally and by general principles of equity, (iii) the representations and warranties of the Borrower or such Guarantor, if any, set forth in the Credit Agreement and in each other Loan Document to which it is a party, shall be true and correct on and as of the Amendment Effective Date, except to the extent any such representations and warranties are expressly limited to an earlier date, in which case such representations and warranties shall have been true and correct as of such specified earlier date, and (iv) no Default or Event of Default exists under the Credit Agreement or any of the other Loan Documents after giving effect to this Amendment;

(c)the Borrower shall have paid all agreed fees to the extent due and payable in connection with this Amendment and paid or reimbursed the Administrative Agent for all its reasonable and documented out-of-pocket costs and expenses incurred in connection with the preparation and execution and delivery of this Amendment (including the reasonable fees, disbursements and other charges of Mayer Brown LLP), in each case, to the extent provided in Section 12.03 of the Credit Agreement.

Section 5.Governing Law.  THIS AMENDMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY, AND CONSTRUED AND INTERPRETED IN ACCORDANCE WITH, THE LAW OF THE STATE OF NEW YORK.

Section 6.Miscellaneous.

(a)On and after the Amendment Effective Date, each reference in the Credit Agreement to “this Agreement”, “hereunder”, “hereof” or words of like import, referring to the Credit Agreement, and each reference in each other Loan Document to “the Credit Agreement”, “thereunder”, “thereof” or words of like import referring to the Credit Agreement, shall mean and be a reference to the Existing Credit Agreement as amended or otherwise modified by this Amendment.  This Amendment shall constitute a Loan Document for purposes of the Credit Agreement.

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(b)The execution, delivery and effectiveness of this Amendment shall not, except as expressly provided herein, operate as a waiver of any default of the Borrower or any Guarantor or any right, power or remedy of the Administrative Agent or the Lenders under any of the Loan Documents, nor constitute a waiver of any provision of any of the Loan Documents.

(c)Each of the Borrower and each Guarantor represents and warrants that as of the date hereof (i) it has the limited partnership or limited liability company power and authority to execute, deliver and perform the terms and provisions of this Amendment, has taken all necessary limited partnership or limited liability company action to authorize the execution, delivery and performance of this Amendment, delivery and performance of this Amendment does not and will not contravene the terms of the Borrower’s or such Guarantor’s, as applicable, organizational documents; (ii) it has duly executed and delivered this Amendment and this Amendment constitutes the legal, valid and binding obligation of the Borrower or such Guarantor enforceable in accordance with its terms, subject to the effects of bankruptcy, insolvency, fraudulent conveyance, reorganization and other similar laws relating to or affecting creditors’ rights generally and general principles of equity (whether considered in a proceeding in equity or law); (iii) no Default or Event of Default has occurred and is continuing; and (iv) no action, suit, investigation or other proceeding is pending or threatened before any arbitrator or Governmental Authority seeking to restrain, enjoin or prohibit or declare illegal, or seeking damages from the Borrower in connection with this Amendment or which could reasonably be expected, individually or in the aggregate, to result in a Material Adverse Effect.

Section 7.Severability.  Any provisions of this Amendment held by a court of competent jurisdiction to be invalid or unenforceable shall not impair or invalidate the remainder of this Amendment and the effect thereof shall be confined to the provisions so held to be invalid.

Section 8.Successors and Assigns.  This Amendment is binding upon and shall inure to the benefit of the Administrative Agent, the Collateral Agent, the Lenders, the Issuer, the Borrower and each Guarantor and their respective successors and assigns.

Section 9.Counterparts.  This Amendment may be executed in any number of counterparts, all of which taken together shall constitute one agreement, and any of the parties hereto may execute this Amendment by signing any such counterpart.  Delivery of an executed counterpart of a signature page to this Amendment by telecopier or electronically by .pdf shall be effective as delivery of a manually executed counterpart of this Amendment.

Section 10.Headings.  The headings, captions and arrangements used in this Amendment are for convenience only and shall not affect the interpretation of this Amendment or any other Loan Document.

Section 11.Integration.  This Amendment represents the final agreement of the Borrower, each Guarantor, the Collateral Agent, the Administrative Agent, the Issuer, and the Lenders with respect to the subject matter hereof, and there are no promises, undertakings, representations or warranties by the Borrower, any Guarantor, the Administrative Agent, the Collateral Agent, the Issuer, nor any Lender relative to subject matter hereof not expressly set forth or referred to herein.

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IN WITNESS WHEREOF, each of the parties hereto has caused this Amendment to be executed by its officer(s) thereunto duly authorized as of the date first above written.

SANCHEZ PRODUCTION PARTNERS LP, as Borrower
By:	SANCHEZ PRODUCTION PARTNERS
	GP LLC, its general partner
By:	/s/ Charles C. Ward
Name:	Charles C. Ward
Title:	Chief Financial Officer
CEP MID-CONTINENT LLC,
as a Guarantor
By:	/s/ Charles C. Ward
Name:	Charles C. Ward
Title:	Chief Financial Officer
NORTHEAST SHELF ENERGY, L.L.C.,
as a Guarantor
By:	/s/ Charles C. Ward
Name:	Charles C. Ward
Title:	Chief Financial Officer
MID-CONTINENT OILFIELD SUPPLY, L.L.C.,
as a Guarantor
By:	/s/ Charles C. Ward
Name:	Charles C. Ward
Title:	Chief Financial Officer

S-1

SEP HOLDINGS IV, LLC,
as a Guarantor
By:	/s/ Charles C. Ward
Name:	Charles C. Ward
Title:	Chief Financial Officer
CATARINA MIDSTREAM, LLC,
as a Guarantor
By:	/s/ Charles C. Ward
Name:	Charles C. Ward
Title:	Chief Financial Officer

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ROYAL BANK OF CANADA,
as Administrative Agent and Collateral Agent
By:	/s/ Yvonne Brazier
Name:	Yvoune Brazier
Title:	Manager, Agency
ROYAL BANK OF CANADA,
as a Lender and the Issuer
By:	/s/ Evans Swann, Jr.
Name:	Evans Swann, Jr.
Title:	Authorized Signatory

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CIT BANK, N.A. (f/k/a OneWest Bank, N.A.),
as a Lender
By:	/s/ Sean Murphy
Name:	Sean Murphy
Title:	Managing Director

S-4

COMPASS BANK,
as a Lender
By:	/s/ Les Werme
Name:	Les Werme
Title:	Director

S-5

SUNTRUST BANK,
as a Lender
By:	/s/ Chulley Bogle
Name:	Chulley Bogle
Title:	Vice President

S-6

CAPITAL ONE, NATIONAL ASSOCIATION,
as a Lender
By:	/s/ Matthew Molero
Name:	Matthew Molero
Title:	Senior Vice President

S-7

CITIBANK, N.A.,
as a Lender
By:	/s/ Cliff Vaz
Name:	Cliff Vaz
Title:	Vice President

S-8

COMERICA BANK,
as a Lender
By:	/s/ Jeffery Treadway
Name:	Jeffery Treadway
Title:	Senior Vice President

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CREDIT SUISSE AG, CAYMAN ISLANDS BRANCH, as a Lender
By:	/s/ Nupur Kumar
Name:	Nupur Kumar
Title:	Authorized Signatory
By:	/s/ Jayant Rao
Name:	Jayant Rao
Title:	Authorized Signatory

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ING CAPITAL LLC,

as a Lender

By:

Name:

Title:

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EX-99.1

Exhibit 99.1

News Release

General Inquiries:  (877) 847-0008

www.sanchezpp.com

Sanchez Production Partners Announces Distributions on

Common Units and Class A Preferred Units

HOUSTON—(Marketwired)—Nov. 10, 2015—Sanchez Production Partners LP (NYSE MKT: SPP) (“SPP” or the “Partnership”) has declared a third quarter 2015 cash distribution on its common units of $0.40 per unit ($1.60 per unit annualized) payable on Nov. 30, 2015 to holders of record on Nov. 20, 2015.  The Partnership has also declared a third quarter 2015 paid-in-kind distribution of 2.5% on its Class A preferred units payable on Nov. 30, 2015 to holders of record on Nov. 20, 2015.

ABOUT THE PARTNERSHIP

Sanchez Production Partners LP (NYSE MKT: SPP) is a publicly-traded limited partnership focused on the acquisition, development, ownership and operation of midstream and other energy production assets.  The Partnership owns an oil and natural gas gathering and processing system located in the Eagle Ford Shale in Dimmit and Webb Counties, Texas.  The Partnership also currently owns producing reserves in the Eagle Ford Shale in South Texas, the Gulf Coast region of Texas and Louisiana, and across several basins in Oklahoma and Kansas.  The Partnership announced in March 2015 that is exploring the possible divestiture of its assets and operations in Oklahoma and Kansas.

ADDITIONAL INFORMATION

Additional information about SPP can be found in the Partnership’s documents on file with the U.S. Securities and Exchange Commission (www.sec.gov) and in the “Investor Presentation” available on the Partnership’s website.

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This press release is intended to be a qualified notice under Treasury Regulation Section 1.1446-4(b). Brokers and nominees should treat one hundred percent (100.0%) of SPP’s distributions to non-U.S. investors as being attributable to income that is effectively connected with a United States trade or business.  Accordingly, SPP’s distributions to non-U.S. investors are subject to federal income tax withholding at the highest applicable effective tax rate.

FORWARD-LOOKING STATEMENTS

This press release 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; anticipated effects of transactions; timing or 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 the gathering and processing agreement; drilling locations; oil, natural gas and natural gas liquids reserves; realized oil, natural gas and natural gas liquids prices; production volumes; lease operating expenses, general and administrative expenses and development costs; future operating results; and plans, objectives, expectations, forecasts, outlook and intentions.  All of these types of statements, other than statements of historical fact included in this press release, 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 press release 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

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prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this press release 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 U.S. 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.

PARTNERSHIP CONTACT

Charles C. Ward

Chief Financial Officer

Sanchez Production Partners GP LLC

(877) 847-0009

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EX-99.2

Exhibit 99.2

News Release

General Inquiries: (877) 847-0008

www.sanchezpp.com

Sanchez Production Partners Reports

Third Quarter 2015 Results; Announces Unit

Repurchase Program and 2016 Forecast

HOUSTON—(Marketwired)—Nov. 12, 2015—Sanchez Production Partners LP (NYSE MKT: SPP) (“SPP” or the “Partnership”) today reported third quarter 2015 results, announced plans to implement a unit repurchase program, and provided a base case forecast for 2016.  Highlights from the report include:

·An initial distribution declared on the Partnership’s common units of $0.40 per unit ($1.60 per unit annualized)

·Implementation of a unit repurchase program of up to $10 million beginning in the fourth quarter 2015

·A base case 2016 forecast that shows the Partnership’s Adjusted EBITDA ranging from $54 million to $60 million, with common unit distribution coverage of 2.2x at the midpoint of this range

·Total revenue of $13.3 million in the third quarter 2015, which includes $7.9 million of sales revenue, approximately 62% of which was from oil and liquids sales and 38% of which was from natural gas sales, $5.0 million from hedge settlements and $0.4 million from services provided to third parties, before $12.3 million in gains from mark-to-market activities, which is a non-cash item

·Operating costs, which include lease operating expenses, production taxes and general and administrative expenses, net of certain non-cash items and non-recurring items, of $24.10 per BOE for the first nine months of 2015, down approximately 5% when compared to the same nine month period of 2014

·Adjusted EBITDA for the third quarter 2015 of $0.3 million before adjustments for non-recurring items and $3.7 million after adjustments for non-recurring items

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MANAGEMENT COMMENTARY

“Our primary focus during the third quarter 2015 was the execution and closing of the Western Catarina Midstream Transaction, our second transaction with Sanchez Energy Corporation (NYSE: SN) this year and our first acquisition involving gathering and processing assets,”  said Gerald F. Willinger, Interim Chief Executive Officer of SPP’s general partner.  “The Western Catarina Midstream Transaction represents the culmination of over two years of work to refocus and improve the Partnership’s strategic direction and financial outlook, and serves as the cornerstone to our midstream business.  With the Western Catarina Midstream Transaction, we believe that we have successfully repositioned the Partnership to provide enhanced visibility for future growth.”

“Having closed the Western Catarina Midstream Transaction last month, we were pleased, earlier this week, to declare a distribution on our common units, initially set at an annualized rate of $1.60 per unit.  We believe that a distribution at this level provides an attractive yield at the current market price of our common units and enhances our ability to pursue our growth strategy.”

“We also believe the Western Catarina Midstream Transaction provides a solid foundation for next year’s business activity.  Our base case forecast currently shows our Adjusted EBITDA ranging from $54 million to $60 million in 2016.  Based on this forecast, we currently anticipate Distributable Cash Flow of between $14.4 million and $20.4 million in 2016, which would provide coverage on projected distributions to our common unitholders of approximately 2.2x at the midpoint of our forecast.”

“Our base case 2016 forecast assumes divestiture of our Mid-Continent operated assets this year with no additional acquisition or divestiture activity.  However, with recent disruptions in the energy markets and line of sight to over $1 billion in midstream and production assets managed under the Sanchez Oil & Gas Corporation operating platform, we see significant opportunities for growth.  As a result, we currently target a 15% compound annual growth rate in our distribution per unit through 2019.”

“While we are excited about the Partnership’s progress and prospects, we recognize that current conditions in the energy markets have created an environment in which energy companies, generally, and master limited partnerships, in particular, have fallen out of favor in

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the investment community.  As a result, we believe we currently trade at an implied yield that does not yet fully reflect the Partnership’s value proposition.  We view this as a near-term opportunity, and so are pleased to announce a plan to implement a unit repurchase program of up to $10 million.  The plan, which was approved by the board of directors of our general partner earlier this week, reflects our on-going commitment to return value to our unitholders.”

OPERATING AND FINANCIAL RESULTS

The Partnership produced 367 MBOE during the third quarter 2015 for average net production of 3,991 BOE/D during the quarter.  Net oil and liquids production for the third quarter 2015, which accounted for approximately 33% of the Partnership’s total production during the quarter, was 1,308 BBL/D.  For the first nine months of 2015, the Partnership produced 1,093 MBOE for average net production of 4,002 BOE/D, a decrease of 4% when compared to the same nine month period of 2014.  Net oil and liquids production for the first nine months of 2015 was 1,190 BBL/D, an increase of 13% when compared to the same nine month period of 2014.

The Partnership’s total revenue for the third quarter 2015 includes revenue from sales of $7.9 million, of which approximately 62% was from oil and liquids sales and 38% was from natural gas sales, revenue from hedge settlements of $5.0 million, and revenue from services provided to third parties of $0.4 million.  The Partnership’s total revenue also includes a $12.3 million gain on mark-to-market activities, which is a non-cash item.  Revenue from sales and hedge settlements during the third quarter 2015, which totaled $12.9 million, decreased $1.4 million, or approximately 10%, when compared to the second quarter 2015.

Operating costs, which include lease operating expenses, production taxes and general and administrative expenses, net of certain non-cash items and out-of-period expenses totaling approximately $3.4 million, which are non-recurring items, averaged $25.96 per BOE in the third quarter 2015 as compared to $23.13 per BOE in the prior quarter and $25.76 per BOE in the third quarter 2014.  For the first nine months of 2015, operating costs, adjusted for non-recurring items, averaged $24.10 per BOE, which is down approximately 5% when compared to

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$25.45 per BOE reported for the same nine month period of 2014, after adjustments for non-recurring items.

The Partnership reported third quarter 2015 Adjusted EBITDA of $0.3 million, before adjustments for non-recurring items, which compares to Adjusted EBITDA of $5.2 million in the second quarter 2015.  After adjustments for non-recurring items, Adjusted EBITDA for the third quarter 2015 was $3.7 million.  Adjusted EBITDA for the nine months of 2015 was $13.8 million after adjustments for non-recurring items and $5.1 million before adjustments for non-recurring items.  On a GAAP basis, the Partnership reported net income of $7.8 million for the third quarter 2015.  For the first nine months of 2015, the Partnership reported a net loss of $92.5 million, which includes an impairment charge in the first quarter 2015 of $82.9 million related to the Partnership’s legacy assets located in Kansas and Oklahoma.

The Partnership’s capital spending during the third quarter 2015 totaled approximately $0.3 million.  For the first nine months of 2015, the Partnership’s capital spending totaled approximately $1.3 million.

CREDIT FACILITY AND HEDGING UPDATE

As of Nov. 12, 2015, the Partnership has $106 million in debt outstanding under its credit facility, which has a borrowing base of $200 million.  The Partnership reported cash and cash equivalents totaling $8.9 million as of Sep. 30, 2015.

For the period Oct. 1, 2015 through Dec. 31, 2015, the Partnership has hedged approximately 1.1 Bcf of its natural gas production at an effective NYMEX fixed price of approximately $4.17 per Mcf and approximately 109 MBbl of its crude oil production at an effective NYMEX fixed price of approximately $75.64 per barrel.

COMMON UNITS

The Partnership’s issued and outstanding common units as of Nov. 12, 2015 totaled approximately 3.0 million.

On Oct. 15, 2015, the Partnership notified the holders of its Class A preferred units of its election to convert the Class A preferred units pursuant to the terms of the partnership agreement effective March 31, 2016.  Assuming conversion of the Class A preferred units occurs at par (or $16.00 per unit, after adjustment for the one-for-ten reverse split), the

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Partnership currently projects an increase in its common unit count of approximately 1.2 million common units at the time of the optional conversion.

UNIT REPURCHASE PROGRAM

The Partnership announced that the board of directors of its general partner has approved a plan pursuant to which the Partnership may, from time to time, repurchase common units of SPP in open market or private transactions for an aggregate amount not to exceed $10 million.  In conjunction with the plan, the Partnership and its lenders have executed an amendment to the Partnership’s credit facility that allows for the repurchase of units so long no event of default exists and the Partnership has unused availability of at least 15% under the credit agreement.  The Partnership anticipates that the repurchase program will be implemented in the fourth quarter 2015, and intends to report any repurchases made under the plan in its quarterly filings with the U.S. Securities and Exchange Commission (“SEC”).  The timing and actual number of units repurchased will depend on a variety of factors, including the unit price, regulatory requirements and other market and economic conditions.  Units repurchased under the program, if any, will be retired, which will reduce the Partnership’s common units outstanding.  The plan may be suspended or discontinued at any time.

DISTRIBUTIONS

On Nov. 10, 2015, the Partnership declared a third quarter 2015 cash distribution on its common units of $0.40 per unit ($1.60 per unit annualized) payable on Nov. 30, 2015 to holders of record on Nov. 20, 2015.  The Partnership also declared a third quarter 2015 paid-in-kind distribution of 2.5% on its Class A preferred units payable on Nov. 30, 2015 to holders of record on Nov. 20, 2015.

2016 FORECAST

Based on hedges in place and forward prices as of Sep. 30, 2015, the Partnership’s “base case forecast” estimates that 2016 Adjusted EBITDA will range from $54 million to $60 million, providing Distributable Cash Flow (“DCF”) of $14.4 million to $20.4 million in 2016.  Based on these forecast results, the Partnership currently projects common unit distribution coverage will range from 1.8x to 2.6x, or 2.2x at the midpoint of the Partnership’s 2016 DCF forecast.

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The Partnership’s base case forecast assumes divestiture of its Oklahoma and Kansas operated properties is complete in 2015, with the proceeds from that sale used to reduce debt outstanding under the credit facility.  The forecast also assumes that hedges related to the Partnership’s Oklahoma and Kansas production are retained and restructured.  No incremental asset acquisitions or divestitures are included in the Partnership’s base case forecast.  The base case forecast also assumes no units are repurchased in the open market under the Partnership’s $10 million unit repurchase program.

CONFERENCE CALL INFORMATION

The Partnership will host a conference call at 10:00 a.m. (CST) on Friday, Nov. 13, 2015 to discuss third quarter 2015 results and the Partnership’s 2016 forecast.

To participate in the conference call, analysts, investors, media and the public in the U.S. may dial (888) 849-8924 shortly before 10:00 a.m. (CST).  The international phone number is (773) 756-4804.  The conference password is PARTNERS.

A replay will be available beginning approximately one hour after the end of the call by dialing (866) 388-5359 or (203) 369-0414 (international).  A live audio webcast of the conference call and the earnings release will be available on the Partnership’s website (www.sanchezpp.com) under the Investor Relations page.  The call will also be recorded and archived on the site.

ABOUT THE PARTNERSHIP

Sanchez Production Partners LP (NYSE MKT: SPP) is a publicly-traded limited partnership focused on the acquisition, development, ownership and operation of midstream and other energy production assets.  The Partnership owns an oil and natural gas gathering and processing system located in the Eagle Ford Shale in Dimmit and Webb Counties, Texas.  The Partnership also currently owns producing reserves in the Eagle Ford Shale in South Texas, the Gulf Coast region of Texas and Louisiana, and across several basins in Oklahoma and Kansas.  The Partnership announced in March 2015 that is exploring the possible divestiture of its assets and operations in Oklahoma and Kansas.

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ADDITIONAL INFORMATION

Additional information about SPP can be found in the Partnership’s documents on file with the SEC (www.sec.gov) and in the “Investor Presentation” available on the Partnership’s website.

The Partnership anticipates that it will file its third quarter 2015 Form 10-Q with the SEC on or about Nov. 13, 2015.

NON-GAAP MEASURES

We present Adjusted EBITDA in addition to our reported net income (loss) in accordance with GAAP in this news release.  We also provide our earnings forecast in terms of Adjusted EBITDA and Distributable Cash Flow.

Adjusted EBITDA is a non-GAAP financial measure that is defined as net income (loss) adjusted by interest (income) expense, net; income tax expense (benefit); depreciation, depletion and amortization; asset impairments; accretion expense; (gain) loss on sale of assets; (gain) loss from equity investment; unit-based compensation programs; and (gain) loss on mark-to-market activities. Distributable Cash Flow is defined as Adjusted EBITDA less cash interest expense; distributions on preferred units; and maintenance capital.

Adjusted EBITDA and Distributable Cash Flow are used as quantitative standards 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.  Adjusted EBITDA and Distributable Cash Flow 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.

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

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(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.

FORWARD-LOOKING STATEMENTS

This press release 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; anticipated effects of transactions; timing or 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 press release, 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 press release 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 press release are not guarantees of future performance, and we cannot assure

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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 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.

PARTNERSHIP CONTACT

Charles C. Ward

Chief Financial Officer

Sanchez Production Partners GP LLC

(877) 847-0009

(Operating and Financial Highlights Follow)

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Sanchez Production Partners LP

Operating Statistics

	Three Months Ended Sep. 30,				Nine Months Ended Sep. 30,
	2015		2014		2015		2014
Net Production in MBOE:
Total production (MBOE)	367		380		1,093		1,135
Average daily production (BOE/D)	3,991		4,129		4,006		4,157
Average Sales Price per BOE:
BOE Net realized price, including hedges (1)	$	35.21	$	39.50	$	35.46	$	42.40
BOE Net realized price, excluding hedges (2)	$	21.55	$	34.03	$	22.11	$	38.71

(1) Excludes impact of mark-to-market gains (losses)

(2) Excludes all hedges, the impact of mark-to-market gains (losses).

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Sanchez Production Partners LP

Condensed Consolidated Statements of Operations

	Three Months Ended Sep. 30,						Nine Months Ended Sep. 30,
	2015			2014			2015			2014
	($ in thousands)						($ in thousands)
Oil, liquids, and gas sales	$	13,320		$	15,802		$	40,659		$	50,544
Gain (loss) on mark-to-market activities	12,305			5,594			1,671			(5,318		)
Total revenues	25,625			21,396			42,330			45,226
Operating expenses:
Lease operating expenses	5,194			5,296			15,452			15,598
Cost of sales	139			404			469			1,198
Production taxes	443			796			1,396			2,563
General and administrative	7,376			3,780			20,669			12,942
(Gain) loss on sale of assets	2			—			(111		)	(23		)
Depreciation, depletion and amortization	2,851			4,836			9,050			13,206
Asset impairments	937			43			84,664			237
Accretion expense	265			151			782			451
Total operating expenses	17,207			15,306			132,371			46,172
Other expenses:
Interest expense	672			511			2,440			1,569
Other expense (income)	(52		)	(76		)	48			(220		)
Total expenses, net	17,827			15,741			134,859			47,521
Income (loss) before income taxes	7,798			5,655			(92,529		)	(2,295		)
Income tax expense	3			—			3			—
Net income (loss)	7,795			5,655			(92,532		)	(2,295		)
Less:
Preferred unit paid-in-kind distributions	(445		)	—			(969		)	—
Net income (loss) attributable to common unitholders	$	7,350		$	5,655		$	(93,501	)	$	(2,295	)
Adjusted EBITDA	$	295		$	5,688		$	5,088		$	19,679
Net income (loss) per unit prior to conversion (1)
Class A units - Basic	$	—		$	2.33		$	(0.38	)	$	(0.54	)
Class B units - Basic	$	—		$	1.94		$	(0.31	)	$	(0.79	)
Class A units - Diluted	$	—		$	2.33		$	(0.38	)	$	(0.54	)
Class B units - Diluted	$	—		$	1.93		$	(0.31	)	$	(0.79	)
Weighted Average Units Outstanding prior to conversion (1)
Class A units - Basic	—			48,451			48,451			85,720
Class B units - Basic	—			2,855,257			2,879,163			2,835,859
Class A units - Diluted	—			48,451			48,451			85,720
Class B units - Diluted	—			2,866,088			2,879,163			2,835,859
Net income (loss) per unit after conversion (1)
Common units - Basic	$	2.33		$	—		$	(29.83	)	$	—
Common units - Diluted	$	0.55		$	—		$	(29.83	)	$	—
Weighted Average Units Outstanding after conversion (1)
Common units - Basic	3,124,004			—			3,103,608			—
Common units - Diluted	14,074,856			—			3,103,608			—

(1) Amounts adjusted for 1-for-10 reverse split completed August 3, 2015.

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Sanchez Production Partners LP

Condensed Consolidated Balance Sheets

	Sep. 30,		Dec. 31,
	2015		2014
	($ in thousands)
Current assets	$	32,239	$	27,300
Oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairments	123,543		135,310
Other assets	13,997		10,637
Total assets	$	169,779	$	173,247
Current liabilities	$	10,343	$	6,893
Long-term debt	106,000		42,500
Other long-term liabilities	18,593		17,031
Total liabilities	134,936		66,424
Members’ equity	—		106,823
Partners’ capital	34,843		—
Total members’ equity/partners’ capital	34,843		106,823
Total liabilities and members’ equity/partners’ capital	$	169,779	$	173,247

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Sanchez Production Partners LP

Reconciliation of Net Income (Loss) to Adjusted EBITDA

	Three Months Ended Sep. 30,						Nine Months Ended Sep. 30,
	2015			2014			2015			2014
	($ in thousands)						($ in thousands)
Reconciliation of Net Income (Loss) to Adjusted EBITDA:
Net income (loss)	$	7,795		$	5,655		$	(92,532	)	$	(2,295	)
Add:
Interest expense, net	672			511			2,440			1,569
Income tax expense	3			—			3			—
Depreciation, depletion and amortization	2,851			4,836			9,050			13,206
Asset impairments	937			43			84,664			237
Accretion expense	265			151			782			451
(Gain) loss on sale of assets	2			—			(111		)	(23		)
Unit-based compensation programs	75			86			2,463			1,216
(Gain) loss on mark-to-market activities	(12,305		)	(5,594		)	(1,671		)	5,318
Adjusted EBITDA (1)	$	295		$	5,688		$	5,088		$	19,679
	Three Months Ended June 30,
	2015			2014
	($ in thousands)
Reconciliation of Net Income (Loss) to Adjusted EBITDA:
Net loss	$	(10,341	)	$	(5,011	)
Add:
Interest expense, net	1,122			533
Depreciation, depletion and amortization	3,079			4,320
Asset impairments	862			45
Accretion expense	264			150
Gain on sale of assets	(54		)	(16		)
Unit-based compensation programs	396			1,029
Loss on mark-to-market activities	9,902			5,915
Adjusted EBITDA (1)	$	5,230		$	6,965

(1)Our Adjusted EBITDA should not be considered as an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, our Adjusted EBITDA may not be comparable to similarly titled measures of other companies.

We define Adjusted EBITDA as net income (loss) plus:

· interest (income) expense, net which includes:

· interest expense;

· interest expense net (gain) loss on interest rate derivative contracts; and

· interest (income);

· income tax expense (benefit);

· depreciation, depletion and amortization;

· asset impairments;

· accretion expense;

· (gain) loss on sale of assets;

· (gain) loss from equity investment;

· unit-based compensation programs; and

· (gain) loss on mark-to-market activities.

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EX-99.3

Exhibit 99.3

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 $