Exhibit 99.1

As used herein, unless otherwise indicated, (i) “the company,” “we,” “our,” “us” or similar terms refer collectively to Sanchez Energy Corporation and its operating subsidiaries; (ii) the “Cotulla acquisition” refers to the transactions contemplated by the purchase and sale agreement we entered into with Hess Corporation on March 18, 2013, which closed on May 31, 2013; (iii) the “Cotulla assets” refers to the assets acquired in the Cotulla acquisition; (iv) “SEP I” refers to Sanchez Energy Partners I, LP, a Delaware limited partnership; (v)“SEP Holdings III” refers to SEP Holdings III, LLC, a Delaware limited liability company and wholly owned subsidiary of the company, which we acquired from SEP I concurrently with the closing of our initial public offering in December 2011; and (vi) “SEP I Assets” refers to the assets we acquired through our acquisition of the limited liability company interests in SEP Holdings III.

Our estimated proved reserve information as of March 31, 2013 are based on reports prepared by Ryder Scott Company, L.P. (‘‘Ryder Scott’’), our independent reserve engineers. The March 31, 2013 information includes our reserves and, unless otherwise stated, the reserves acquired in the Cotulla acquisition. Unless otherwise stated, all references herein to reserves, acreage, operational and production information as of March 31, 2013 or later are pro forma for the Cotulla acquisition. A glossary of some of the oil and natural gas terms used herein may be found under “Glossary of Selected Oil and Natural Gas Terms” in our latest annual report on Form 10-K. PV-10 as presented herein is a supplemental measure not required by, or presented in accordance with, accounting principles generally accepted in the United States, or GAAP.  Please see “Reconciliation of PV-10 to Standardized Measure” herein for a discussion of PV-10 and a reconciliation to the standardized measure.

Our Core Properties

Eagle Ford Shale

Our primary focus is the black oil and volatile oil areas of the Eagle Ford Shale in South Texas, one of the fastest growing and most prolific unconventional shale trends in North America. According to RigData’s Land Rig Newsletter, the drilling rig count in the Eagle Ford Shale grew 390% from 42 rigs in March 2010 to 206 rigs in March 2013. Based on a recent study by the Society of Petroleum Engineers, the aerial extent of the trend is thought to be approximately 11 million acres.

The following table provides information regarding our proved reserves by area as of March 31, 2013:

We and our predecessor entities have a long history in the Eagle Ford Shale where we have assembled approximately 139,000 net leasehold acres with an average working interest of approximately 88%. Using approximately 80 acre well-spacing and assuming 80% of acreage is drillable for each area, except for the Palmetto area which assumes 90% of acreage is drillable, we believe there could be up to 1,525 gross (1,330 net) locations for potential future drilling. We also believe that down-spacing in our areas of operation will provide additional recoveries of oil in place and could materially increase our total inventory of drilling locations. Consistent with other operators in this area, we perform multi-stage hydraulic fracturing up to 30 stages on each well depending upon the length of the lateral section. For the year 2013, we plan to invest substantially all of our capital budget in the Eagle Ford Shale.

In our Marquis area, we have approximately 56,345 net operated acres, the majority of which are in southwest Fayette and northeast Lavaca Counties, Texas with a 100% working interest. We believe that our Marquis acreage lies in the volatile oil window where we anticipate drilling, completion and facilities costs on our acreage to be between $9.0 million and $11.0 million per well based on our historical well costs and publicly available information. We have drilled nine horizontal wells that had a range of average initial 24-hour production rates between 205 and 1,377 boe/d. We have identified up to 555 gross and net locations based on 80 acre well-spacing for potential future drilling on our Marquis acreage. We have recently completed a 60 acre well-spacing test in the western Prost area of our Marquis area. For 2013, we plan to spend approximately $180 million to drill 18 gross (18 net) wells in our Marquis area.

In our recently acquired Cotulla area, we have approximately 44,461 net acres in Dimmit, Frio, LaSalle and Zavala Counties, Texas with an average working interest of approximately 90%. We believe that our Cotulla acreage lies in the black oil and volatile oil window where we anticipate drilling, completion and facilities costs on our acreage to be between $7.0 million and $9.0 million per well based on our historical well costs and publicly available information. We have 53 gross wells on our acreage producing an estimated average of approximately 4,950 boe/d for the month of May 2013. We

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have identified up to 445 gross (400 net) locations based on 80 acre well-spacing for potential future drilling in our Cotulla area. For 2013, we plan to spend approximately $75 million to drill 11 gross (9.7 net) wells in our Cotulla area.

In our Maverick area, we have approximately 28,289 net operated acres in Zavala and Frio Counties, Texas with an average working interest of approximately 87%. We believe that our Maverick acreage lies in the black oil window, where we anticipate drilling, completion and facilities costs on our acreage to be between $5.5 million and $6.5 million per well based on our historical well costs and publicly available information. We have drilled ten gross horizontal wells that had a range of average initial 24-hour production rates between 214 and 931 boe/d. We have also drilled four vertical wells that had average initial 24-hour rates between 94 and 264 boe/d. We have identified up to 315 gross (275 net) locations based on 80 acre well-spacing for potential future drilling on our Maverick acreage. For 2013, we plan to spend approximately $10 million to drill 2 gross (2 net) wells in our Maverick area.

In our Palmetto area, we have approximately 9,695 net acres in Gonzales County, Texas with an average working interest of approximately 48%. We believe that our Palmetto acreage lies in the volatile oil window where we anticipate drilling, completion and facilities costs on our acreage to be between $7.5 million and $11.0 million per well based on our historical well costs and publicly available information. We have participated in the drilling of 25 gross wells on our acreage that had an average initial 24-hour production rates between 370 and 3,139 boe/d. We have identified up to 210 gross (100 net) locations based on 80 acre well-spacing for potential future drilling in our Palmetto area. We recently completed a five-well pilot program from a single pad to test 40 acre well-spacing in our southern portion of the Palmetto area, and Ryder Scott has given us 80 acre well-spaced proved undeveloped locations in the same area in its December 31, 2012 and March 31, 2013 reserve reports. For 2013, we plan to spend approximately $170 million to drill 34 gross (17.0 net) wells in our Palmetto area.

Other

In addition to our Eagle Ford Shale acreage, we have approximately 700 net acres in the Haynesville Shale in Natchitoches Parish, Louisiana, which are operated by Chesapeake Energy Corporation. The majority of our Haynesville leases are held by production, giving us and our partners the option to accelerate drilling should natural gas prices increase. Furthermore, we have amassed approximately 82,000 net acres in northern Montana which we believe may be prospective for the Heath, Three Forks and Bakken Shales. Our lease terms in northern Montana are for five years with options in 2013 and 2014 to renew for another five years at $10 per acre, which we do not anticipate exercising. We do not anticipate spending any capital expenditures in these areas in 2013.

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The following table presents summary data for each of our primary project areas as of March 31, 2013 and our revised drilling capital expenditure budget for 2013:

(1)                                 Total identified drilling locations are calculated using 80 acre well-spacing and assumes 80% of acreage is drillable for each area, except for the Palmetto area which assumes 90% of acreage is drillable.

(2)                                 In our Palmetto area, we have 109 gross (54.5 net) locations that are classified as proved undeveloped at March 31, 2013. We intend to drill all of those proved undeveloped locations within the next five years.

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Estimated Proved Reserves

The following table presents historical and pro forma estimated net proved oil and natural gas reserves attributable to our properties and the standardized measure amounts associated with the estimated proved reserves attributable to our properties on a pro forma basis for the Cotulla acquisition as of March 31, 2013 and on a historical basis as of December 31, 2012, 2011 and 2010. The data are based on reserve reports prepared by Ryder Scott, our independent reserve engineers. The standardized measure amounts shown in the table are not intended to represent the current market value of our estimated oil and natural gas reserves.

(1)                                 Our estimated net proved reserves and related standardized measure were determined using index prices for oil and natural gas, without giving effect to commodity derivative contracts, held constant throughout the life of our properties. The prices are based on the average prices during the 12-month period prior to the ending date of the period covered, determined as the unweighted arithmetic average of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, and are adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price realized at the wellhead. For a description of our commodity derivative contracts, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations — Costs and Operating Expenses — Commodity Derivative Transactions” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates — Derivative Instruments” in our latest quarterly report on Form 10-Q and annual report on Form 10-K.

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(2)                                 One boe is equal to six mcf of natural gas or one bo of oil or NGLs based on a rough energy equivalency. This is a physical correlation and does not reflect a value or price relationship between the commodities.

(3)                                 PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved crude oil and natural gas reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash inflows and using the twelve-month unweighted arithmetic average of the first-day-of-the-month price for each of the preceding twelve months. PV-10 differs from the standardized measure because it does not include the effect of future income taxes. For a reconciliation of our standardized measure to PV-10, see “Reconciliation of PV-10 to Standardized Measure” below.

(4)                                 Our 2010 PV-10 and standardized measure are equivalent because we were not subject to entity level taxation prior to completion of our IPO in December 2011.

(5)                                 Standardized measure is calculated in accordance with Statement of Financial Accounting Standards No. 69, Disclosures About Oil and Gas Producing Activities, as codified in ASC Topic 932, Extractive Activities — Oil and Gas. For further information regarding the calculation of the standardized measure, see “Supplementary Information on Oil and Natural Gas Exploration, Development and Production Activities (Unaudited)” included in the financial statements included in our latest annual report on Form 10-K.

The data in the table above represents estimates only. Oil, NGLs and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil, NGLs and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil, NGLs and natural gas that are ultimately recovered. For a discussion of risks associated with internal reserve estimates, please read “Risk Factors — Our estimated reserves and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our estimated reserves” in our latest annual report on Form 10-K.

Future prices realized for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The standardized measure amounts shown above should not be construed as the current market value of our estimated oil and natural gas reserves. The 10% discount factor used to calculate standardized measure, which is required by FASB pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

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Development of Proved Undeveloped Reserves

None of our proved undeveloped reserves at March 31, 2013 are scheduled to be developed on a date more than five years from the date the reserves were initially booked as proved undeveloped. Historically, our drilling and development programs were substantially funded from capital contributions, cash flow from operations and the issuance of equity securities. Based on our current expectations of our cash flows and drilling and development programs, which includes drilling of proved undeveloped locations, we believe that we can fund the drilling of our current inventory of proved undeveloped locations and our expansions and extensions in the next five years from our cash on hand combined with cash flow from operations, expected increases to our borrowing capacity under our credit facilities and possible issuance of debt or equity securities.

For more information about our historical costs associated with the development of proved undeveloped reserves, please read “Supplementary Information on Oil and Natural Gas Exploration, Development and Production Activities (Unaudited)” included in the financial statements included in our latest annual report on Form 10-K.

Estimated Probable and Possible Reserves

Unless otherwise specifically identified in this offering memorandum, the summary data with respect to our estimated reserves has been prepared by our independent reserve engineers in accordance with rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities.

The reserve estimates at March 31, 2013 presented in the table below are based on a report prepared by Ryder Scott, our independent reserve engineers. For more information regarding our independent reserve engineers, please see “— Qualifications of Responsible Technical Persons” in our latest annual report on Form 10-K. The information in the following table does not give any effect to or reflect our commodity derivative instruments.

Estimates of probable reserves are inherently imprecise. When producing an estimate of the amount of oil and natural gas that is recoverable from a particular reservoir, an estimated quantity of probable reserves is an estimate of those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Estimates of probable reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors.

When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

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Estimates of possible reserves are also inherently imprecise. When producing an estimate of the amount of oil and natural gas that is recoverable from a particular reservoir, an estimated quantity of possible reserves is an estimate that might be achieved, but only under more favorable circumstances than are likely. Estimates of possible reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors.

When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. Possible reserves may be assigned to areas of a reservoir adjacent to probable reserve where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir. Possible reserves also include incremental quantities associated with a greater percentage of recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(1)                                 Our estimated net proved, probable and possible reserves and related PV-10 at March 31, 2013 were determined using index prices for oil and natural gas, without giving effect to commodity derivative contracts, held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months were $92.63/bo for oil, $38.71/bbl for NGLs and $2.95/mmbtu for natural gas. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price realized at the wellhead. As of March 31, 2013, the average realized prices for oil, NGLs and natural gas were $104.44 per bo, $30.41 per bbl and $2.95 per mcf, respectively.

(2)                                 In addition to the estimated proved reserve report dated March 31, 2013, Ryder Scott provided us with a probable and possible reserve report as of March 31, 2013 for the Palmetto and Marquis areas. Probable and possible reserves included in the report totaled 12 mmboe and $57.6 million in

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additional PV-10 value. Of these reserves, 84% were attributed to our Palmetto area and 16% were attributed to our Marquis area, and 5,614 mbo and 4,140 mbo were classified as oil, 3,174 mmcf and 2,484 mmcf were classified as natural gas and 694 mbo and 517 were classified as NGLs, respectively. Estimates of probable and possible reserves that may potentially be recoverable through additional drilling or recovery techniques are by nature more uncertain than estimates of proved reserves and accordingly are subject to substantially greater risk of not actually being realized by us. All of our probable and possible reserves are classified as undeveloped.

(3)                                 One boe is equal to six mcf of natural gas or one bo of oil or NGLs based on a rough energy equivalency. This is a physical correlation and does not reflect a value or price relationship between the commodities.

(4)                                 PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved crude oil and natural gas reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash inflows and using the twelve-month unweighted arithmetic average of the first-day-of-the-month price for each of the preceding twelve months. PV-10 differs from the standardized measure because it does not include the effect of future income taxes. For a reconciliation of our standardized measure to PV-10, see “Reconciliation of PV-10 to Standardized Measure” below.

Reconciliation of PV-10 to Standardized Measure

PV-10 is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure on a pre-tax basis. PV-10 is equal to the standardized measure at the applicable date, before deducting future income taxes, discounted at 10%. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the standardized measure. Our PV-10 measure and the standardized measure do not purport to present the fair value of our oil and natural gas reserves.

The following table provides a reconciliation of PV-10 to the standardized measure for our pro forma proved, probable and possible reserves as of March 31, 2013 and for our historical proved reserves as of December 31, 2012, 2011 and 2010:

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(1)                                 Standardized measure is calculated in accordance with Statement of Financial Accounting Standards No. 69, Disclosures About Oil and Gas Producing Activities, as codified in ASC Topic 932, Extractive Activities — Oil and Gas. For further information regarding the calculation of the standardized measure, see “Supplementary Information on Oil and Natural Gas Exploration, Development and Production Activities (Unaudited)” included in the financial statements in our latest annual report on Form 10-K.

Production, Revenues and Price History

The following table sets forth information regarding combined net production of oil and natural gas and certain price and cost information attributable to our properties for each of the periods presented, both on a historical basis and on a pro forma basis for the Cotulla acquisition:

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(1)                                 Excludes the impact of oil derivative instruments.

(2)                                 For the year ended December 31, 2012, general and administrative excludes non-cash stock-based compensation expense of approximately $25.5 million, or $54.49 per boe. Pro forma for the twelve months ended March 31, 2013, general and administrative excludes non-cash stock-based compensation expense of approximately $24.7 million, or $10.99 per boe. We did not have any stock-based compensation expense for the prior periods presented.

Drilling Activities

The following table sets forth information with respect to wells drilled and completed during the periods indicated. The information should not be considered indicative of future performance, nor should

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a correlation be assumed between the number of productive wells drilled, quantities of reserves found or economic value.

The following table sets forth information at March 31, 2013 relating to the productive wells in which we owned a working interest as of that date. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we own an interest, and net wells are the sum of our fractional working interests owned in gross wells.

We brought 20 wells on-line in 2012, 6 wells during the first quarter of 2013 and now have a total of 102 wells on-line. We also had 18 wells in various stages of drilling, Completion or initial flow back as of May 31, 2013.

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Developed and Undeveloped Acreage

The following table sets forth information as of March 31, 2013 relating to our leasehold acreage. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary. As of March 31, 2013, approximately 26% of our acreage was held by production.

Excluding our Bakken acreage, as of March 31, 2013, we had leases representing 38,006 net acres (37,996 of which were in the Eagle Ford Shale) expiring in 2013, 7,884 net acres (7,882 of which were in the Eagle Ford Shale) expiring in 2014, and 56,933 net acres (all of which were in the Eagle Ford Shale) expiring in 2015 and beyond. We anticipate that our current and future drilling plans along with selected lease extensions will address the majority of our leases expiring in the Eagle Ford Shale in 2013. In addition, included in the acreage expiring in 2013 in the Eagle Ford Shale is a single lease for approximately 6,100 net acres, and a single well drilled to any depth producing commercial quantities of oil and gas will hold the lease, which we plan to drill in June 2013. Our 82,274 net acres in the Heath, Three Forks and Bakken Shales expire in 2013 and 2014 and we do not anticipate exercising the option we have to renew for another five years at $10 per acre.

Delivery Commitments

We have made commitments to certain refineries and other buyers to deliver a portion of our gas production. The total amount contracted to be delivered is approximately 40 billion cubic feet of gas through 2021. The price for these deliveries is set at the time of delivery of the product. We have more production capacity than the amounts committed and none of the commitments in any given year are material.

Liquidity and Hedging

We currently anticipate enough liquidity from cash on hand, cash flow from operations, completion of recently announced transactions and our first lien credit facility, including future growth in our borrowing base, to fund our operations through 2015 based on the current rig count.

Following our acquisition of the Cotulla properties, we expect to execute additional commodity derivative contracts in the future to ensure that our hedged volumes closely resemble historical levels.  Our ongoing hedging program targets having in place commodity derivative contracts covering approximately 50% of our annual production.  We may, however, from time to time hedge more or less than this amount.

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Selected Historical and Pro Forma Financial Data

The summary historical and pro forma financial data table below shows selected pro forma financial data as of and for the twelve months ended March 31, 2013, for the three months ended March 31, 2013 and 2012 and for the year ended December 31, 2012 and selected historical financial data as of March 31, 2013, for the three months ended March 31, 2013 and 2012 and as of and for each of the three years in the period ended December 31, 2012. The selected historical financial data as of March 31, 2013 and for the three months ended March 31, 2013 and 2012 are derived from our unaudited condensed consolidated historical financial statements and the selected historical financial data as of December 31, 2012, 2011 and 2010 and for the years ended December 31, 2012, 2011 and 2010 are derived from our audited historical financial statements.

The selected pro forma financial data are derived from our unaudited condensed consolidated historical financial statements, our audited historical financial statements and audited and unaudited financial statements relating to the Cotulla assets. The pro forma adjustments have been prepared as if certain transactions had taken place as of January 1, 2012, in the case of the pro forma statement of operations data, or as of March 31, 2013, in the case of the pro forma balance sheet data. These transactions include:

·                  The issuance and sale by us in a private offering to eligible purchasers of 4,500,000 shares of Series B Convertible Preferred Stock, which was completed March 27, 2013, and the application of the proceeds thereof to fund a portion of the purchase price for the Cotulla acquisition; and

·                  The Cotulla acquisition (including the borrowings related thereto incurred on May 30, 2013 under our first lien credit facility and the payment of the purchase price and expenses), which closed on May 31, 2013.

The selected pro forma financial data may not necessarily be indicative of the actual results of operations that might have occurred if we operated the Cotulla assets during the periods presented.

Our historical financial statements prior to December 19, 2011 have been prepared on a carve-out basis from the accounts of SEP I. The carved-out financial information includes all assets, liabilities and results of operations of the unconventional oil and natural gas properties and related assets contributed to us by SEP I for the periods prior to December 19, 2011. These historical financial statements prior to December 19, 2011 may not necessarily reflect our financial position, results of operations, and cash flows as if we had operated as a stand-alone public company during those periods. The historical financial data prior to December 19, 2011 reflect historical accounts attributable to the SEP I Assets on a “carve-out” basis, including allocated overhead from our predecessor in interest, for periods prior to our acquisition of the SEP I Assets on December 19, 2011 and do not reflect any estimate of additional overhead that we may incur as a separate company.

The selected financial data should be read together with the financial statements and related notes included in this current report on Form 8-K and our other filings with the SEC.

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