NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. ORGANIZATION AND BASIS OF PRESENTATION

Organization

      Sanchez Production Partners LP, a Delaware limited partnership (“SPP”, “we”, “us”, “our” or the “Partnership”), is an oil and gas ex ploration and production limited partnership focused on the acquisition, development and production of oil and natural gas properties and other integrated assets . SPP completed its initial public offering on November 20, 2006, as Constellation Energy Partners LLC (“CEP” or the “Company”). In August 2013, Sanchez Energy Partners I, LP (“SEP I”), an affiliate of Sanchez Oil & Gas Corporation (“SOG”) , contributed certain oil and natural gas properties in Texas and Louisiana to CEP in exchange for equity interests in CEP. On May 8, 2014, the Company and SP Holdings, LLC (the “Manager”) , the sole member of our general partner, entered into a Shared Services Agreement (the “Services Agreement”) pursuant to which the Manager agreed to provide services that the Partnership requires to operate its business, including overhead, technical, administrative, marketing, accounting, operational, information systems, financial, compliance, insurance and acquisition, disposition and financing services.  The Services Agreement became effective as of July 1, 2014. CEP’s name was subsequently changed to Sanchez Production Partners LLC and on March 6, 2015, the Company’s unitholders approved the conversion of Sanchez Production Partners LLC to a Delaware limited partnership and the name was changed to Sanchez Production Partners LP .   T he Manager owns the general partner of SPP and all of SPP’s incentive distribution rights. Our common units are currently listed on the NYSE MKT under the symbol “SPP.”

        SOG is a private company engaged in the management of oil and natural gas properties on behalf of its related companies, with whom it has various service agreements encompassing a wide range of activities, including, but not limited to, management, administrative and operational services. SEP I and SP Holdings, LLC are related to SOG through services agreements, and SOG owns a 0.5% general partner interest in SEP I.   Our proved reserves are currently located in the Cherokee Basin in Oklahoma and Kansas, the Woodford Shale in the Arkoma Basin in Oklahoma, the Central Kansas Uplift in Kansas, the Eagle Ford Shale in South Texas and in other areas of Texas and Louisiana .  

Basis of Presentation

These unaudited condensed consolidated financial statements include the accounts of SPP and our wholly-owned subsidiaries.  All intercompany accounts and transactions have been eliminated in consolidation.  We operate our oil and natural gas properties as one business segment: the exploration, development and production of oil and natural gas.  Our management evaluates performance based on one business segment as there are not different economic environments within the operation of our oil and natural gas properties.

These unaudited condensed consolidated financial statements have been prepared pursuant to the rules of the Securities and Exchange Commission (“SEC”).  Certain information and footnote disclosures, normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”), have been condensed or omitted pursuant to those rules and regulations.  We believe that the disclosures made are adequate to make the information presented not misleading.  In the opinion of management, all adjustments, consisting only of normal recurring adjustments, necessary to fairly state the financial position, results of operations and cash flows with respect to the interim condensed consolidated financial statements have been included.  The results of operations for the interim periods are not necessarily indicative of the results for the entire year. 

These unaudited condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto of the Company and our subsidiaries included in our Annual Report on Form 10-K for the year ended December 31, 2014, which was filed with the SEC on March 5, 2015.

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the condensed consolidated financial statements and accompanying footnotes.  These estimates and the underlying assumptions affect the amounts of assets and liabilities reported, disclosures about contingent assets and liabilities and reported amounts of revenues and expenses.  The estimates that are particularly significant to our financial statements include estimates of our reserves of oil, natural gas and natural gas liquids (“NGLs”); future cash flows from oil and natural gas properties; depreciation, depletion and amortization; asset retirement obligations; certain revenues and operating expenses; fair values of commodity derivatives and fair values of assets and liabilities.  As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use.  These estimates and assumptions are based on management’s best estimates and judgment.  Management evaluates its estimates and assumptions on an on-going basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances.  Such estimates and assumptions are adjusted when facts and circumstances dictate.  As future events and their effects cannot be determined with precision, actual results

could differ from the estimates.  Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.

Reclassifications

Certain reclassifications have been made to the prior period to conform to the current period presentation.  These reclassifications had no effect on total assets, total liabilities, total unitholders’ equity, net income or net cash provided by or used in operating, investing or financing activities.

Recent Accounting Pronouncements

From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (“FASB”), which are adopted by us as of the specified effective date.  Unless otherwise discussed, management believes that the impact of recently issued standards, which are not effective, will not have a material impact on our condensed consolidated financial statements upon adoption.

In April 2015, FASB issued Accounting Standards Update (“ASU”) No. 2015-03, “Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs.” This guidance is intended to more closely align the presentation of debt issuance costs under U.S. GAAP with the presentation requirements under International Financial Reporting Standards.  Under this new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as a separate asset as previously presented.  This guidance is effective for fiscal years and interim periods beginning after December 15, 2015.  The guidance is to be applied retrospectively to each prior period presented.  Early adoption is permitted.  The effects of this accounting standard on our financial position, results of operations and cash flows are not expected to be material.

In February 2015, the FASB issued an ASU No. 2015-02, “Consolidation (Topic 810): Amendments to the Consolidation Analysis” to improve consolidation guidance for certain types of legal entities. The guidance modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities (“VIEs”) or voting interest entities, eliminates the presumption that a general partner should consolidate a limited partnership, affects the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships, and provides a scope exception from consolidation guidance for certain money market funds. These provisions are effective for annual reporting periods beginning after December 15, 2015, and interim periods within those annual periods, with early adoption permitted. These provisions may also be adopted using either a full retrospective or a modified retrospective approach. We are currently assessing the impact that adopting this new accounting guidance will have on our consolidated financial statements and footnote disclosures, but we do not expect the impact to be material.

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).”  This guidance outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance.  This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized.  The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods and services.  The new guidance is effective for fiscal years and interim periods beginning after December 15, 2017.  Early adoption is not permitted.  The guidance may be applied retrospectively to each prior period presented or retrospectively with the cumulative effect recognized as of the date of initial application.  We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements, but do not expect the impact to be material.

Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Partnership’s financial position, results of operations and cash flows.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Our significant accounting policies are consistent with those discussed in our Annual Report on Form 10-K for the year ended December 31, 201 4 .

Cash

All highly liquid investments with original maturities of three months or less are considered cash.  Checks-in-transit are included in our consolidated balance sheets as accounts payable or as a reduction of cash, depending on the type of bank account the checks were drawn on.  There were no checks-in-transit reported in accounts payable at June 30 , 2015 and December 31, 2014.

Restricted  Cash

Restricted cash, as of   June 30 , 2015 and December 31, 2014, of $ 0.6 million and $1.7 million, respectively, was being held in escrow.  The balance as of June 30 , 2015 is related to a vendor dispute, and will remain in the escrow account until the dispute has been resolved. 

Accounts Receivable, Net

Our accounts receivable are primarily from purchasers of oil and natural gas and counterparties to our financial instruments.  Oil receivables are generally collected within 30 days after the end of the month.  Natural gas receivables are generally collected within 60 days after the end of the month.  We review all outstanding accounts receivable balances and record a reserve for amounts that we expect will not be fully recovered.  Actual balances are not applied against the reserves until substantially all collection efforts have been exhausted.  At June 30 , 2015 and December 31, 2014, we had an allowance for doubtful accounts receivable of $0.4 million and $0.2 million, respectively.         

3. ACQUISITIONS AND DIVESTITURE S

Eagle Ford Acquisition

On March 31, 2015, we completed an acquisition of wellbore interests in certain producing oil and natural gas properties in Gonzales County, Texas (the “Eagle Ford properties,” and such acquisition, the “Eagle Ford acquisition”) located in the Eagle Ford Shale in Gonzales County, Texas from Sanchez Energy Corporation (“SN”) for a purchase price of $85 million, subject to normal and customary closing adjustments.  The effective date of the transaction was January 1, 2015. The acquisition included initial conveyed working interests and net revenue interests for each property which escalate on January 1 for each year from 2016 through 2019, at which point, SPP’s interests in the Eagle Ford properties will stay constant for the remainder of the respective lives of the assets. 

The adjusted purchase price of $83.4 million was funded at closing with net proceeds from the private placement of 10,625,000 newly created Class A Preferred Units (the “Preferred Units”) which were issued for a cash purchase price of $1.60 per unit, resulting in gross proceeds to SPP of $17.0 million, the issuance of 1,052,632 common units (approximately 105,263 common units after adjusting for reverse unit split) to SN, borrowings under the Partnership’s Credit Agreement (as defined in Note 7, “Long-Term Debt”), and available cash. The total purchase price was allocated to the assets purchased and liabilities assumed based upon their fair values on the date of acquisition as follows (in thousands):

Pro Forma Operating Results

        The following pro forma combined results for the three and six months ended June 30, 2015 and 2014 reflect the consolidated results of operations of the Partnership as if the Eagle Ford acquisition and related financing had occurred on January 1, 2014. The pro forma information includes adjustments primarily for revenues and expenses from the acquired properties, depreciation, depletion, amortization and accretion, interest expense and debt issuance cost amortization for acquisition debt, and paid-in-kind units issued in connection with the preferred units.

        The unaudited pro forma combined financial statements give effect to the events set forth below:

         • The Eagle Ford acquisition completed on March 31, 2015.

         • The increase in borrowings under the Credit Agreement to finance a portion of the Eagle Ford acquisition, and the related   

            adjustments to interest expense.

         • Issuance of Class A Preferred Units to finance a portion of the Eagle Ford acquisition, and the related adjustments to preferred 

           paid-in-kind distributions.  

         • Issuance of common units to finance a portion of the Eagle Ford acquisition and the related effect on net income (loss) per 

           common unit (in thousands, except per unit amounts).

(1)   Amounts adjusted for 1-for-10 reverse split completed August 3, 2015.  See Note 13.

The unaudited pro forma combined financial information is for informational purposes only and is not intended to represent or to be indicative of the combined results of operations that the Partnership would have reported had the Eagle Ford acquisition and related financings been completed as of the date set forth in this unaudited pro forma combined financial information and should not be taken as indicative of the Partnership’s future combined results of operations. The actual results may differ significantly from that reflected in the unaudited pro forma combined financial information for a number of reasons, including, but not limited to, differences in assumptions used to prepare the unaudited pro forma combined financial information and actual results.

Post-Acquisition Operating Results

The amounts of revenue and excess o f revenues over direct operating expenses included in the Partnership’s condensed consolidated statements of operations for the three and six months ended June 30, 2015, for the Eagle Ford acquisition are shown in the table that follows.  Direct operating expenses include lease operating expenses and production and ad valorem taxes (in thousands):

4. FAIR VALUE MEASUREMENTS

  Measurements of fair value of derivative instruments are classified according to the fair value hierarchy, which prioritizes the inputs to the valuation techniques used to measure fair value. Fair value is the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are classified and disclosed in one of the following categories:

        Level 1:     Measured based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Active markets are considered those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

        Level 2:     Measured based on quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that can be valued using observable market data. Substantially all of these inputs are observable in the marketplace throughout the term of the derivative instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace.

        Level 3:     Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). The valuation models used to

value derivatives associated with the Partnership's oil and natural gas production are primarily industry standard models that consider various inputs including: (a) quoted forward prices for commodities, (b) time value, and (c) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Although third party quotes are utilized to assess the reasonableness of the prices and valuation techniques, there is not sufficient corroborating evidence to support classifying these assets and liabilities as Level 2.

        Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Management's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

The following tables summarize the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of June 30 , 2015 and December 31, 2014 (in thousands):

The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2014 (in thousands):

As of June 30, 2015 and December 31, 2014, the estimated fair value of cash and cash equivalents, accounts receivable, other current assets and current liabilities approximated their carrying value due to their short-term nature.

Fair Value on a Non-Recurring Basis

The Partnership follows the provisions of Accounting Standards Codification (“ASC”) Topic 820-10 for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs under the fair value hierarchy. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; (iv) estimated future cash flows; and (v) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Partnership’s management at the time of the valuation and are the most sensitive and subject to change.   Our purchase price allocation for the Eagle Ford acquisition is presented in Note 3, ‘‘Acquisitions and Divestitures.”   A reconciliation of the beginning and ending balances of the Partnership’s asset retirement obligations is presented in Note 8, ‘‘Asset Retirement Obligations.’’

Fair Value of Financial Instruments

Fair value guidance requires certain fair value disclosures, such as those on our debt and derivatives, to be presented in both interim and annual reports.  The estimated fair value amounts of financial instruments have been determined using available market information and valuation methodologies described below.

Credit Agreement – We believe that the carrying value of long-term debt for our Credit Agreement approximates its fair value because the interest rates on the debt approximate market interest rates for debt with similar terms.  The debt is classified as a Level 2 input in the fair value hierarchy and represents the amount at which the instrument could be valued in an exchange during a current transaction between willing parties.  Our Credit Agreement is discussed further in Note 7, “Long-Term Debt.”

        Derivative Instruments – The income valuation approach, which involves discounting estimated cash flows, is primarily used to determine recurring fair value measurements of our derivative instruments classified as Level 2 inputs.  Our commodity derivatives are valued using the terms of the individual derivative contracts with our counterparties, expected future levels of oil and natural gas prices and an appropriate discount rate.  Our interest rate derivatives are valued using the terms of the individual derivative contracts with our counterparties, expected future levels of the LIBOR interest rates and an appropriate discount rate.  We did not have any interest rate derivatives as of June 30, 2015. We prioritize the use of the highest level inputs available in determining fair value such that fair value measurements are determined using the highest and best use as determined by market participants and the assumptions that they would use in determining fair value.

5. DERIVATIVE AND FINANCIAL INSTRUMENTS

To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we periodically enter into derivative contracts with respect to a portion of our projected oil and natural gas production through various transactions that fix or modify the future prices to be realized.  These transactions are normally price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty.  These hedging activities are intended to support oil and natural gas prices at targeted levels and to manage exposure to oil and natural gas price fluctuations.  It is never our intention to enter into derivative contracts for speculative trading purposes.

Under ASC Topic 815, Derivatives and Hedging , all derivative instruments are recorded on the condensed consolidated balance sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date.  We will net derivative assets and liabilities for counterparties where we have a legal right of offset.  Changes in the derivatives’ fair values are recognized currently in earnings unless specific hedge accounting criteria are met.  We have not elected to designate any of our current derivative contracts as hedges; however, changes in the fair value of all of our derivative instruments are recognized in earnings and included in natural gas sales and oil and liquids sales in the condensed consolidated statements of operations.

As of June 30 , 2015, we had the following derivative contracts in place for the periods indicated, all of which are accounted for as mark-to-market activities:

                                                                               The following table sets forth a reconciliation of the changes in fair value of the Partnership’s commodity derivatives for the three months ended June 30, 2015 and the year ended December 31, 2014 (in thousands):

The effect of derivative instruments on our condensed consolidated statements of operations was as follows (in thousands):

Derivative instruments expose us to counterparty credit risk.  Our commodity derivative instruments are currently with three counterparties.  We generally execute commodity derivative instruments under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty.  If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net cash settled at the time of election. We include a measure of counterparty credit risk in our estimates of the fair values of derivative instruments. As of June 30, 2015 and December 31, 2014, the impact of non-performance credit risk on the valuation of our derivative instruments was not significant.

Hedges Novated in the Eagle Ford Acquisition

As a part of the Eagle Ford acquisition, we received by novation from the seller certain hedges covering approximately 95% ,   90% ,   85% ,   85% and 80% of estimated 2015, 2016, 2017, 2018 and 2019 oil and natural gas production from the acquired assets, respectively.  The counterparty for the hedges is a lender in the Partnership’s Credit Agreement. The Partnership is responsible for all future periodic settlements of these transactions .  As of June 30, 2015, the fair value of the hedges assumed resulted in a less than $0.1 million asset in our condensed consolidated balance sheet.