UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10‑Q

(Mark One)

ma
☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, ~~2018~~2019
OR
☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 1‑35372

Sanchez Energy Corporation

(Exact name of registrant as specified in its charter)


Delaware (State or other jurisdiction of incorporation or organization)	45‑3090102 (I.R.S. Employer Identification No.)
1000 Main Street, Suite 3000 Houston, Texas (Address of principal executive offices)	77002 (Zip Code)

(713) 783‑8000

(Registrant’s telephone number, including area code)

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the Registrant has submitted electronically ~~and posted on its corporate Web site, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ pursuant to Rule 405 of Regulation S T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit ~~and post~~ such files). Yes ☒ No ☐

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non‑accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b‑2 of the Exchange Act.

				Emerging growth company ☐
Large accelerated filer ☐	Accelerated filer ☒	Non‑accelerated filer ☐ (Do not check if a smaller reporting company)	Smaller reporting company ☐	Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b‑2 of the Exchange Act). Yes ☐ No ☒

Securities registered pursuant to Section 12(b) of the Act:


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
N/A	N/A	N/A

Number of shares of Registrant’s common stock, par value $0.01 per share, outstanding as of May ~~7, 2018: 85,172,408~~3, 2019: 99,828,591

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Sanchez Energy Corporation

Form 10‑Q

For the Quarterly Period Ended March 31, ~~2018~~2019

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	PART I
Item 1.	Financial Statements	10
	Condensed Consolidated Balance Sheets as of March 31, ~~2018~~2019 (Unaudited) and December 31, ~~2017~~2018	10
	Condensed Consolidated Statements of Operations for the Three Months Ended March 31, ~~2018~~2019 and ~~2017~~2018 (Unaudited)	11
	Condensed Consolidated ~~Statement~~Statements of Stockholders’ Equity (Deficit) for the Three Months Ended March 31, 2019 and 2018 (Unaudited)	12
	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, ~~2018~~2019 and ~~2017~~2018 (Unaudited)	13
	Notes to the Condensed Consolidated Financial Statements (Unaudited)	14
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	5638
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	6849
Item 4.	Controls and Procedures	7051
	PART II
Item 1.	Legal Proceedings	7152
Item 1A.	Risk Factors	7152
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	7152
Item 3.	Defaults Upon Senior Securities	7152
Item 4.	Mine Safety Disclosures	7153
Item 5.	Other Information	7153
Item 6.	Exhibits	7254
SIGNATURES		7355

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CAUTIONARY NOTE REGARDING FORWARD‑LOOKING STATEMENTS

This Quarterly Report on Form 10‑Q contains “forward‑looking statements” within the meaning of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this Quarterly Report on Form 10‑Q that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward‑looking statements. These statements are based on certain assumptions we made based on management’s experience, perception of historical trends and technical analyses, current conditions, anticipated future developments and other factors believed to be appropriate and reasonable by management. When used in this Quarterly Report on Form 10‑Q, words such as “will,” “potential,” “believe,” “estimate,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “plan,” “predict,” “forecast,” “budget,” “guidance,” “project,” “profile,” “model,” “strategy,” “future” or their negatives or the statements that include these words or other words that convey the uncertainty of future events or outcomes, are intended to identify forward‑looking statements, although not all forward‑looking statements contain such identifying words. In particular, statements, express or implied, concerning our future operating results and returns or our ability to replace or increase reserves, increase production, or generate income or cash flows, service our debt and other obligations and repay or otherwise refinance such obligations when due or at maturity, operational and commercial benefits of our partnerships, expected benefits from acquisitions, ~~including the Comanche Acquisition ( as defined in Note 4, “Acquisitions and Divestitures” of Part I, Item 1. Financial Statements)~~ and our strategic relationship with Sanchez Midstream Partners LP ~~(f/k/a Sanchez Production Partners LP)~~ (“SNMP”) are forward‑looking statements. Forward‑looking statements are not guarantees of performance. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control. Although we believe that the expectations reflected in our forward‑looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Important factors that could cause our actual results to differ materially from the expectations reflected in the forward‑looking statements include, among others:

the timing and extent of changes in prices ~~for,~~of, and demand for, crude oil and condensate, natural gas liquids (“NGLs”), natural gas and related commodities;

our ability to successfully execute our business and financial strategies;

our ability to comply with the financial and other covenants in our debt instruments, to service and repay our debt, and to address our liquidity needs, particularly if commodity prices remain volatile and/or depressed;

the extent to which we are able to engage in successful strategic alternatives to improve our balance sheet and satisfy our obligations under our debt instruments;

the extent to which we are able to pursue drilling plans and acquisitions that are successful in maintaining and economically developing our acreage, producing and replacing reserves and achieving anticipated production levels;

our ability to successfully integrate our various acquired assets into our operations, realize the benefits of those acquisitions, fully identify and address existing and potential issues or liabilities and accurately estimate reserves, production and costs with respect to such assets;

the extent to which we are able to continue as a going concern;

our ability to access the credit and capital markets to obtain financing on terms we deem acceptable, if at all, and to otherwise satisfy our capital expenditure, debt service and other funding requirements through internally generated cash flows, asset sales and other activities;

the extent to which our listing in the over-the-counter market rather than on a national securities exchange will impair our access to the equity markets and ability to obtain financing;

our ability to utilize the services, personnel and other assets of Sanchez Oil & Gas Corporation (“SOG”) pursuant to an existing services agreement (the “Services Agreement”);

~~our ability to replace the reserves we produce through drilling and property acquisitions;~~

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~~the realized benefits of the acreage acquired in our various acquisitions, including the Comanche Acquisition,~~SOG’s ability to attract and retain personnel and other ~~assets and liabilities assumed in connection therewith;~~

~~our ability~~resources to ~~successfully integrate our various acquired assets, including assets acquired in~~perform its obligations under the Comanche Acquisition, into our operations, fully identify existing and potential problems with respect to such assets and accurately estimate reserves, production and costs with respect to such assets;Services Agreement;

the realized benefits of our partnerships and joint ventures, including our transactions with SNMP and our partnership with affiliates of The Blackstone Group, L.P. (“Blackstone”);

~~the realized benefits of our transactions with SNMP;~~

~~the extent to which our drilling plans are successful in economically developing our acreage, producing reserves and achieving anticipated production levels;~~

the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may, therefore, be imprecise;

the effectiveness of our internal control over financial reporting;

the extent to which we can optimize reserve recovery and economically develop our ~~plays~~properties utilizing horizontal and vertical drilling, advanced completion technologies, hydraulic stimulation and ~~hydraulic fracturing;~~other techniques;

the availability, proximity and capacity of, and costs associated with, gathering, processing, compression and transportation facilities;

our ability to successfully execute our hedging strategy and the resulting realized prices therefrom;

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the availability, creditworthiness and performance of our counterparties, including financial institutions, operating partners and other parties;

the extent to which requests for credit assurances from our contractual counterparties could have a material adverse effect on our business, financial condition and results of operations;

the extent to which minimum volume commitments or “take-or-pay” obligations in excess of our oil and natural gas deliveries to, or transportation needs from, our contractual counterparties due to reduced activity levels or otherwise could have a material adverse effect on our business, financial condition and results of operations;

results of litigation filed against us or other legal proceedings or out-of-court contractual disputes to which we are party;

competition in the oil and natural gas exploration and production industry ingenerally and with respect to the marketing of ~~crude~~ oil, natural gas and NGLs, ~~and for the~~ acquisition of leases and properties, attraction and retention of employees and other personnel, procurement of equipment, materials and services and, related thereto, the availability and cost of employees and other personnel, equipment, materials and services;

the extent to which our ~~ability to compete with other companies in the~~production, revenue and cash flow from operating activities are derived from oil and natural gas ~~industry;~~assets which are concentrated in a single geographic area;

developments in oil‑producing and natural gas‑producing countries, the actions of the Organization of Petroleum Exporting Countries (“OPEC”) and other factors affecting the supply and pricing of oil and natural gas;

the extent to which third parties operate our oil and natural gas properties successfully and economically;

our ability to ~~access~~manage the ~~credit~~financial risks where we share with more than one party the costs of drilling, equipping, completing and ~~capital markets~~operating wells, including with respect to ~~obtain financing on terms we deem acceptable, if at all,~~the Comanche Assets (as defined in “Item 1. Financial Statements - Note 14. Stockholders’ and ~~to otherwise satisfy our capital expenditure and other funding requirements;~~Mezzanine Equity”);

the ~~availability, proximity~~use of competing energy sources, the development of alternative energy sources and ~~capacity~~potential economic implications and other effects therefrom;

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the extent to which we incur uninsured losses and liabilities or losses and liabilities in excess of ~~and costs associated with, gathering, processing, compression and transportation facilities;~~our insurance coverage, including losses related to sabotage, terrorism or other malicious intentional acts (including cyber-attacks) that disrupt operations;

the impact of, and changes in, government policies, laws and regulations, including tax laws and regulations, environmental laws and regulations relating to air emissions, waste disposal, hydraulic fracturing and access to and use of water, laws and regulations imposing conditions and restrictions on drilling and completion operations and laws, regulations, restrictions and ~~regulations~~guidelines with respect to derivatives, hedging activities and ~~hedging activities;~~

our ability to effectively integrate acquired crude oil and natural gas properties into our operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and costs with respect to such properties;

~~the extent to which our crude oil and natural gas properties operated by others are operated successfully and economically;~~

~~the use of competing energy sources, the development of alternative energy sources and potential economic implications and other effects therefrom;~~

~~unexpected results of litigation filed against us;~~

~~the extent to which we incur uninsured losses and liabilities or losses and liabilities in excess of our insurance coverage;~~commercial lending standards; and

the other factors described under “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Part II, Item 1A. Risk Factors” and elsewhere in this Quarterly Report on Form 10‑Q and in our other public filings with the Securities and Exchange Commission (the “SEC”).

In light of these risks, uncertainties and assumptions, the events anticipated by our forward‑looking statements may not occur, and, if any of such events do, we may not have correctly anticipated the timing of their occurrence or the extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of our forward‑looking statements. Any forward‑looking statement speaks only as of the date on which such statement is made, and we undertake no obligation to correct or update any forward‑looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

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GLOSSARY OF SELECTED OIL AND NATURAL GAS TERMS

The following includes a description of the meanings of some of the oil and natural gas industry terms used in this Quarterly Report on Form 10‑Q. The definitions ~~“analogous reservoir,”~~ “development costs,” “development project,” “development well,” “economically producible,~~” “estimated ultimate recoveries,” “exploratory well,~~” “field,” “possible reserves,” “probable reserves,” “production costs,” “proved area,” “reservoir,” “resources,” and “unproved properties” have been excerpted from the applicable definitions contained in Rule 4‑10(a) of Regulation S‑X.

American Petroleum Institute (“API”) gravity: A system of classifying oil based on its specific gravity, whereby the greater the gravity, the lighter the oil.

~~analogous reservoir:~~ Analogous reservoirs, as used in resource assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, analogous reservoir refers to a reservoir that shares all of the following characteristics with the reservoir of interest: (i) the same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) the same environment of deposition; (iii) similar geologic structure; and (iv) the same drive mechanism.

~~basin:~~ ~~A large depression on the earth’s surface in which sediments accumulate.~~

Bbl: One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

~~Bcf:~~ ~~One billion cubic feet of natural gas.~~

~~black oil:~~ ~~A quality of oil with an API gravity of 15-45° with a gas‑to‑oil ratio of 200-900 cubic feet per barrel or less.~~

Boe: One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe of oil.

Boe/d: One Boe per day.

~~btu:~~Btu: One British thermal unit, the quantity of heat required to raise the temperature of a one‑pound mass of water by one degree Fahrenheit.

completion: The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

condensate: A liquid hydrocarbon with an API gravity of 50-100°.

developed acreage: The number of acres that are allocated or assignable to producing wells or wells capable of production.

development costs: Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and natural gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to: (i) gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves; (ii) drill and equip development wells, development‑type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly; (iii) acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems; and (iv) provide improved recovery systems.

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development project: A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

development well: A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

differential: An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.

dry hole: A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.

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economically producible: The term economically producible, as it relates to a resource, means a resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.

~~estimated ultimate recoveries~~: ~~The sum of reserves remaining as of a given date and cumulative production as of that date.~~

~~exploitation:~~ ~~A development or other project that may target proven or unproven reserves (such as probable or possible reserves), but that generally has a lower risk than that associated with exploration projects.~~

~~exploratory well:~~ ~~A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.~~

field: An area consisting of a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. The field name refers to both the surface and the underground productive formations.

gross acres or gross wells: The total acres or wells, as the case may be, in which we have a working interest.

horizontal ~~drilling:~~development: A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

independent exploration and production company: A company whose primary line of business is the exploration and production of ~~crude~~ oil and natural gas.

~~LLS:~~ ~~Louisiana light sweet crude.~~

~~MBbl:~~MBbls: One thousand ~~Bbl.~~Bbls.

MBoe: One thousand Boe.

Mcf: One thousand cubic feet of natural gas.

~~MMBbl:~~MMBbls: One million ~~Bbl.~~Bbls.

MMBoe: One million Boe.

~~MMbtu:~~MMBtu: One million British thermal units.

MMcf: One million cubic feet of natural gas.

net acres or net wells: Gross acres or wells, as the case may be, multiplied by our working interest ownership percentage.

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net production: Production that is owned by us less royalties and production due others.

~~net revenue interest:~~ ~~A working interest owner’s gross working interest in production less the royalty, overriding royalty, production payment and net profits interests.~~

NGLs: The combination of ethane, propane, butane, natural gasolines and other components that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

NYMEX: New York Mercantile Exchange.

operator: The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.

possible reserves: Additional reserves that are less certain to be recovered than probable reserves.

probable reserves: Additional reserves that are less certain to be recovered than proved reserves but that, in sum with proved reserves, are as likely as not to be recovered.

production costs: Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities.

~~productive well:~~ ~~A well that produces commercial quantities of hydrocarbons, exclusive of its capacity to produce at a reasonable rate of return.~~

proved area: The part of a property to which proved reserves have been specifically attributed.

proved developed reserves: Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

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proved developed non-producing reserves: Reserves that are expected to be recovered from completion intervals which are open at the time of the estimate but which have not yet started producing, wells which were shut-in for market conditions or pipeline connections, or wells not capable of production for mechanical reasons; reserves that are expected to be recovered from zones in existing well which will require additional completion work or future re-completion prior to start production.

proved oil and natural gas reserves: The estimated quantities of oil, natural gas and NGLs that geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

~~proved undeveloped reserves:~~PUDs: Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

realized price: The cash market price less all expected quality, transportation and demand adjustments.

recompletion: The action of reentering an existing wellbore to redo or repair the original completion in order to increase the well’s productivity.

reserve: That part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination.

reservoir: A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

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resources: Resources are quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered unrecoverable. Resources include both discovered and undiscovered accumulations.

spacing: The distance between wells producing from the same reservoir. Spacing is often expressed in terms of ~~acres~~feet (e.g., ~~75 acre~~600 foot well-spacing) and is often established by regulatory agencies.

~~standardized measure:~~ The present value of estimated future after tax net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Standardized measure does not give effect to derivative transactions.

trend: A geographic area with hydrocarbon potential.

undeveloped acreage: Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

unproved properties: Properties with no proved reserves.

volatile oil: A quality of oil with an API gravity of 42-55° with a gas‑to‑oil ratio of 900-3,500 cubic feet per barrel.

~~wellbore:~~ ~~The hole drilled by the bit that is equipped for oil or natural gas production on a completed well. Also called well or borehole.~~

working interest: An interest in an oil and natural gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.

~~workover:~~ ~~Operations on a producing well to restore or increase production.~~

WTI: West Texas Intermediate ~~crude.~~oil.

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PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

Sanchez Energy Corporation

Condensed Consolidated Balance Sheets ~~(Unaudited)~~

(in thousands, except par value and share amounts)


	March 31,		December 31,		March 31,		December 31,
	2018		2017		2019		2018
ASSETS						(Unaudited)
Current assets:
Cash and cash equivalents	$	550,044	$	184,434	$	200,698	$	197,613
Oil and natural gas receivables		86,018		101,396		79,022		87,222
Joint interest billings receivables		20,715		22,569		20,367		33,263
Accounts receivable - related entities		4,823		4,491		9,286		6,099
Fair value of derivative instruments		12,019		16,430		1,372		15,714
Other current assets		12,852		21,478		27,813		33,070
Total current assets		686,471		350,798		338,558		372,981
Oil and natural gas properties, on the basis of successful efforts accounting:
Proved oil and natural gas properties		3,278,731		3,130,407		3,817,836		3,792,431
Unproved oil and natural gas properties		399,144		398,605		317,377		328,643
Total oil and natural gas properties		3,677,875		3,529,012		4,135,213		4,121,074
Less: Accumulated depreciation, depletion, amortization and impairment		(1,558,802)		(1,501,553)		(1,827,245)		(1,761,949)
Total oil and natural gas properties, net		2,119,073		2,027,459		2,307,968		2,359,125

Other assets:
Fair value of derivative instruments		8,778		1,428		6,667		12,102
Investments (Investment in SNMP measured at fair value of $23.5 million and $25.2 as of March 31, 2018 and December 31, 2017, respectively)		37,312		38,462
Right of use assets, net						322,230		—
Investments (includes investment in SNMP measured at fair value of $4.9 million and $3.9 million as of March 31, 2019 and December 31, 2018, respectively)						18,181		16,664
Other assets		52,208		52,488		52,959		59,088
Total assets	$	2,903,842	$	2,470,635	$	3,046,563	$	2,819,960
LIABILITIES AND STOCKHOLDERS' EQUITY
LIABILITIES AND STOCKHOLDERS' DEFICIT
Current liabilities:
Accounts payable	$	10,688	$	14,994	$	11,863	$	32,382
Other payables		84,688		81,970		124,802		74,628
Accrued liabilities:
Capital expenditures		98,819		85,340		15,252		61,970
Other		76,131		84,794		90,819		102,728
Fair value of derivative instruments		73,997		56,190		22,843		706
Short term debt		23,996		23,996		245		304
Short term lease liabilities						102,508		—
Other current liabilities		105,938		115,244		23,826		75,581
Total current liabilities		474,257		462,528		392,158		348,299
Long term debt, net of premium, discount and debt issuance costs		2,366,495		1,930,683		2,396,151		2,395,408
Asset retirement obligations		37,030		36,098		47,122		46,175
Fair value of derivative instruments		20,272		17,474		3,090		366
Long term lease liabilities						222,315		—
Other liabilities		39,209		65,480		653		21,407
Total liabilities		2,937,263		2,512,263		3,061,489		2,811,655
Commitments and contingencies (Note 17)
Mezzanine equity:
Preferred units ($1,000 liquidation preference, 500,000 units authorized, issued and outstanding as of March 31, 2018 and December 31, 2017)		433,442		427,512
Stockholders' equity:
Preferred stock ($0.01 par value, 15,000,000 shares authorized; 1,838,985 shares issued and outstanding as of March 31, 2018 and December 31, 2017 of 4.875% Convertible Perpetual Preferred Stock, Series A; 3,527,830 shares issued and outstanding as of March 31, 2018 and December 31, 2017 of 6.500% Convertible Perpetual Preferred Stock, Series B)		53		53
Common stock ($0.01 par value, 150,000,000 shares authorized; 85,172,408 and 83,984,827 shares issued and outstanding as of March 31, 2018 and December 31, 2017, respectively)		858		845
Preferred units ($1,000 liquidation preference, 500,000 units authorized, issued and outstanding as of March 31, 2019 and December 31, 2018)						472,361		452,828
Stockholders' deficit:
Preferred stock ($0.01 par value, 15,000,000 shares authorized; 780,432 and 1,838,985 shares issued and outstanding as of March 31, 2019 and December 31, 2018, respectively, of 4.875% Convertible Perpetual Preferred Stock, Series A; 2,511,013 and 3,527,830 shares issued and outstanding as of March 31, 2019 and December 31, 2018, respectively, of 6.500% Convertible Perpetual Preferred Stock, Series B)						32		53
Common stock ($0.01 par value, 300,000,000 shares authorized; 99,794,460 and 87,328,424 shares issued and outstanding as of March 31, 2019 and December 31, 2018, respectively)						1,007		881
Additional paid-in capital		1,366,283		1,362,118		1,371,450		1,367,427
Accumulated deficit		(1,834,057)		(1,832,156)		(1,859,776)		(1,812,884)
Total stockholders' deficit		(466,863)		(469,140)		(487,287)		(444,523)
Total liabilities and stockholders' deficit	$	2,903,842	$	2,470,635	$	3,046,563	$	2,819,960

The accompanying notes are an integral part of these condensed consolidated financial statements.

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Sanchez Energy Corporation

Condensed Consolidated Statements of Operations (Unaudited)

(in thousands, except per share amounts)


	Three Months Ended				Three Months Ended
	March 31,				March 31,
	2018		2017*		2019		2018
REVENUES:
Oil sales	$	155,392	$	73,276	$	128,028	$	155,392
Natural gas liquid sales		49,305		27,100		40,500		49,305
Natural gas sales		41,729		33,467		43,049		41,729
Sales and marketing revenues		4,802		—		5,145		4,802
Total revenues		251,228		133,843		216,722		251,228
OPERATING COSTS AND EXPENSES:
Oil and natural gas production expenses		71,948		37,998		80,955		71,948
Exploration expenses		33		352		1,270		33
Sales and marketing expenses		4,173		—		4,931		4,173
Production and ad valorem taxes		13,469		6,524		13,050		13,469
Depreciation, depletion, amortization and accretion		59,248		26,404		67,481		59,248
Impairment of oil and natural gas properties		948		1,845		3,930		948
General and administrative expenses		22,420		67,465		20,483		22,420
Total operating costs and expenses		172,239		140,588		192,100		172,239
Operating income (loss)		78,989		(6,745)
Operating income						24,622		78,989
Other income (expense):
Interest income		742		357		622		742
Other income		3,428		10,535		826		3,428
Gain on sale of oil and natural gas properties		—		4,344
Interest expense		(43,920)		(33,025)		(44,553)		(43,920)
Earnings from equity investments		—		435
Net gains (losses) on commodity derivatives		(44,054)		38,881
Total other income (expense)		(83,804)		21,527
Income (loss) before income taxes		(4,815)		14,782
Income tax benefit		—		953
Net income (loss)		(4,815)		15,735
Net losses on commodity derivatives						(48,423)		(44,054)
Total other expense						(91,528)		(83,804)
Loss before income taxes						(66,906)		(4,815)
Income tax expense						436		—
Net loss						(67,342)		(4,815)
Less:
Preferred stock dividends		(3,987)		(3,987)		(2,516)		(3,987)
Preferred unit dividends and distributions		(9,908)		(16,466)		(12,500)		(9,908)
Preferred unit amortization		(5,930)		(1,710)		(7,033)		(5,930)
Net loss attributable to common stockholders	$	(24,640)	$	(6,428)	$	(89,391)	$	(24,640)

Net loss per common share - basic and diluted	$	(0.30)	$	(0.09)	$	(0.98)	$	(0.30)
Weighted average number of shares used to calculate net loss attributable to common stockholders - basic and diluted		80,919		69,659		91,663		80,919

*Financial information for 2017 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.

The accompanying notes are an integral part of these condensed consolidated financial statements.

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Sanchez Energy Corporation

Condensed Consolidated ~~Statement~~Statements of Stockholders’ Equity ~~for the Three Months Ended March 31, 2018~~ (Deficit)

(Unaudited)

(in thousands)


	Series A			Series B						Additional				Total		Series A			Series B						Additional				Total
	Preferred Stock			Preferred Stock			Common Stock			Paid-in		Accumulated		Stockholders'		Preferred Stock			Preferred Stock			Common Stock			Paid-in		Accumulated		Stockholders'
	Shares	Amount		Shares	Amount		Shares	Amount		Capital		Deficit		Deficit		Shares	Amount		Shares	Amount		Shares	Amount		Capital		Deficit		Deficit
BALANCE, December 31, 2017	1,839	$	18	3,528	$	35	83,985	$	845	$	1,362,118	$	(1,832,156)	$	(469,140)	1,839	$	18	3,528	$	35	83,985	$	845	$	1,362,118	$	(1,832,156)	$	(469,140)
Adoption of accounting standards	—		—	—		—	—		—		—		22,739		22,739	—		—	—		—	—		—		—		22,739		22,739
Issuance of common stock	—		—	—		—	100		1		565		—		566	—		—	—		—	100		1		565		—		566
Dividends on Series A and Series B Preferred stock	—		—	—		—	805		8		3,979		(3,987)		—	—		—	—		—	805		8		3,979		(3,987)		—
Dividends on SN UnSub preferred units	—		—	—		—	—		—		—		(12,500)		(12,500)
Distributions - SN UnSub preferred units	—		—	—		—	—		—		—		2,592		2,592
Accretion of discount on SN UnSub preferred units	—		—	—		—	—		—		—		(5,930)		(5,930)
Dividends on SN UnSub Preferred Units																—		—	—		—	—		—		—		(12,500)		(12,500)
Distributions - SN UnSub Preferred Units																—		—	—		—	—		—		—		2,592		2,592
Accretion of discount on SN UnSub Preferred Units																—		—	—		—	—		—		—		(5,930)		(5,930)
Restricted stock awards, net of forfeitures	—		—	—		—	283		4		(4)		—		—	—		—	—		—	283		4		(4)		—		—
Stock-based compensation	—		—	—		—	—		—		(375)		—		(375)
Non-cash stock-based compensation																—		—	—		—	—		—		(375)		—		(375)
Net loss	—		—	—		—	—		—		—		(4,815)		(4,815)	—		—	—		—	—		—		—		(4,815)		(4,815)
BALANCE, March 31, 2018	1,839	$	18	3,528	$	35	85,173	$	858	$	1,366,283	$	(1,834,057)	$	(466,863)	1,839	$	18	3,528	$	35	85,173	$	858	$	1,366,283	$	(1,834,057)	$	(466,863)

																Series A			Series B						Additional				Total
																Preferred Stock			Preferred Stock			Common Stock			Paid-in		Accumulated		Stockholders'
																Shares	Amount		Shares	Amount		Shares	Amount		Capital		Deficit		Deficit
BALANCE, December 31, 2018																1,839	$	18	3,528	$	35	87,329	$	881	$	1,367,427	$	(1,812,884)	$	(444,523)
Adoption of accounting standards																—		—	—		—	—		—		—		42,499		42,499
Dividends on Series A and Series B Preferred stock																—		—	—		—	7,898		79		3,908		(2,516)		1,471
Dividends on SN UnSub Preferred Units																—		—	—		—	—		—		—		(12,500)		(12,500)
Accretion of discount on SN UnSub Preferred Units																—		—	—		—	—		—		—		(7,033)		(7,033)
Restricted stock awards, net of forfeitures																—		—	—		—	(270)		(1)		1		—		—
Exchange of preferred stock for common stock																(1,059)		(11)	(1,017)		(10)	4,837		48		(27)		—		—
Non-cash stock-based compensation																—		—	—		—	—		—		141		—		141
Net loss																—		—	—		—	—		—		—		(67,342)		(67,342)
BALANCE, March 31, 2019																780	$	7	2,511	$	25	99,794	$	1,007	$	1,371,450	$	(1,859,776)	$	(487,287)

The accompanying notes are an integral part of these condensed consolidated financial statements.

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Sanchez Energy Corporation

Condensed Consolidated Statements of Cash Flows (Unaudited)

(in thousands)


	Three Months Ended				Three Months Ended
	March 31,				March 31,
	2018		2017*		2019		2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(4,815)	$	15,735
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Net loss					$	(67,342)	$	(4,815)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		59,248		26,404		67,481		59,248
Impairment of oil and natural gas properties		948		1,845		3,930		948
Gain on sale of oil and natural gas properties		—		(4,344)
Stock-based compensation expense (benefit)		(1,273)		23,032		273		(1,273)
Net (gains) losses on commodity derivative contracts		44,054		(38,881)
Net cash settlement received (paid) on commodity derivative contracts		(19,651)		1,267
Net losses on commodity derivative contracts						48,423		44,054
Net cash settlements received (paid) on commodity derivative contracts						218		(19,651)
Gain on other derivatives		(336)		(685)		(276)		(336)
(Gain) loss on investments		1,150		(8,864)		(1,517)		1,150
Loss on other assets						858		—
Amortization of deferred gain on Western Catarina Midstream Divestiture		(5,929)		(5,929)		—		(5,929)
Amortization of debt issuance costs		6,714		2,497		3,154		6,714
Accretion of debt discount, net		281		159		416		281
Deferred taxes		—		(953)
Earnings from equity investments		—		(435)
Distributions from equity investments		—		412
Changes in operating assets and liabilities:
Accounts receivable		12,984		(9,634)		22,185		12,984
Other current assets		8,626		(2,025)
Accounts payable		(4,306)		7,373
Accounts receivable - related entities		(332)		(69)		(3,187)		(332)
Other assets		374		—
Other payables		2,718		929		48,472		2,718
Accrued liabilities		(3,525)		(8,529)		(14,662)		(3,525)
Other current liabilities		(12,411)		(12,993)		(28,174)		(12,411)
Net cash provided by (used in) operating activities		84,519		(13,688)
Other assets and liabilities, net						(14,094)		4,694
Net cash provided by operating activities						66,158		84,519

CASH FLOWS FROM INVESTING ACTIVITIES:
Payments for oil and natural gas properties		(135,907)		(87,722)
Payments for other property and equipment		(173)		(7,491)
Proceeds from sale of oil and natural gas properties		—		7,032
Capital expenditures for oil and natural gas properties						(64,788)		(135,907)
Acquisition of oil and natural gas properties		2,834		(1,039,127)		—		2,834
Payments for investments		—		(101)
Payments for purchases of other assets, net						(361)		(173)
Proceeds from sale of other assets						4,967		—
Net cash used in investing activities		(133,246)		(1,127,409)		(60,182)		(133,246)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		539,865		190,000		—		539,865
Repayment of borrowings		(99,087)		—		(2,886)		(99,087)
Issuance of common stock		—		135,942
Issuance of preferred units		—		500,000
Issuance costs related to preferred units		—		(21,043)
Financing costs		(11,940)		(23,873)		—		(11,940)
Preferred dividends paid		(3,987)		—		—		(3,987)
Cash paid to tax authority for employee stock-based compensation awards		(606)		(795)		(5)		(606)
Preferred unit distribution		(9,908)		(16,466)
Net cash provided by financing activities		414,337		763,765
Preferred unit dividends and distributions paid						—		(9,908)
Net cash provided by (used in) financing activities						(2,891)		414,337

Increase (decrease) in cash and cash equivalents		365,610		(377,332)
Increase in cash and cash equivalents						3,085		365,610
Cash and cash equivalents, beginning of period		184,434		501,917		197,613		184,434
Cash and cash equivalents, end of period	$	550,044	$	124,585	$	200,698	$	550,044

NON-CASH INVESTING AND FINANCING ACTIVITIES:
Change in asset retirement obligations	$	174	$	8,349	$	—	$	174
Change in accrued capital expenditures	$	13,479	$	17,993		(46,719)		13,479
ROU assets obtained in exchange for operating lease obligations						347,845		—
SUPPLEMENTAL DISCLOSURE:
Cash paid for taxes	$	—	$	—
Cash paid for interest	$	37,869	$	35,598	$	56,054	$	37,869

*Financial information for 2017 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.

The accompanying notes are an integral part of these condensed consolidated financial statements.

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

Note 1. Organization and Business

Sanchez Energy Corporation (together with our consolidated subsidiaries, “Sanchez Energy,” the “Company,~~” “SN,~~” “we,” “our,” “us” or similar terms), a Delaware corporation formed in August 2011, is an independent exploration and production company focused on the acquisition and development of ~~U.S. onshore unconventional~~ oil and natural gas resources ~~with a current focus~~in the onshore United States. We are currently focused on the horizontal development of significant resource potential from the Eagle Ford Shale in South ~~Texas. We~~Texas, and we also hold another producing properties and undeveloped acreage, ~~position~~including in the Tuscaloosa Marine Shale (“TMS”) in Mississippi and Louisiana which offers potential future development opportunities. As of March 31, ~~2018,~~2019, we have assembled approximately ~~487,000~~466,000 gross (264,000 net) leasehold acres ~~(285,000 net acres)~~ in the Eagle Ford ~~Shale. In addition,~~Shale, where we plan to invest the majority of our 2019 capital budget. We continually evaluate opportunities to ~~grow~~manage our ~~acreage~~overall portfolio, which may include the acquisition of additional properties in the Eagle Ford Shale or other producing areas and, ~~our producing assets through acquisitions.~~from time to time, the divestiture of non-core assets. Our successful acquisition of such ~~assets~~properties will depend on the ~~opportunities~~circumstances and the financing alternatives available to us at the time we consider such opportunities. However, at this time we are primarily focused on lowering cash costs across our business and reducing our financial leverage, with an objective of maximizing our liquidity position and improving our balance sheet. We ~~have included definitions~~are also pursuing a number of ~~some~~strategic alternatives to better align our capital structure with the current low commodity price environment; however, we cannot provide any assurances that any of these alternatives will be completed on terms acceptable to us, on a timely basis, or at all. In addition, the market for acquisition and divestiture of oil and natural gas ~~terms used in~~assets has slowed significantly, and this ~~Quarterly Report on Form 10‑Q~~reduced transaction activity level, combined with continued challenging conditions in the ~~“Glossary~~credit and capital markets, among other reasons, may make it difficult for us to complete divestitures of ~~Selected Oil and Natural Gas Terms.”~~non-core assets or pursue other strategic alternatives.

Note 2. Basis of Presentation and Summary of Significant Accounting Policies

The accompanying condensed consolidated financial statements are unaudited and were prepared from the Company’s records. The condensed consolidated financial statements were prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP” or “U.S. GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. The Company derived the condensed consolidated balance sheet as of December 31, ~~2017~~2018 from the audited financial statements filed in its Annual Report on Form 10-K for the fiscal year ended December 31, ~~2017~~2018 (the ~~“2017~~“2018 Annual Report”). Because this is an interim period filing presented using a condensed format, it does not include all of the disclosures required by U.S. GAAP. These condensed consolidated financial statements should be read in connection with the consolidated financial statements and notes thereto included in the ~~2017~~2018 Annual Report, which contains a summary of the Company’s significant accounting policies and other disclosures. In the opinion of management, these financial statements include the adjustments and accruals, all of which are of a normal recurring nature, which are necessary for a fair presentation of the results for the interim periods. These interim results are not necessarily indicative of results to be expected for the entire year.

As of March 31, ~~2018,~~2019, the Company’s significant accounting policies are consistent with those discussed in Note 2, “Basis of Presentation and Summary of Significant Accounting Policies,” in the notes to the Company’s consolidated financial statements contained in the ~~2017~~2018 Annual ~~Report.~~Report with the addition of the following:

Leases

The Company determines if a contractual arrangement is a lease at inception. Operating leases are included in right of use (“ROU”) assets, short term lease liabilities and long term lease liabilities in the condensed consolidated balance sheets.

ROU assets represent the Company’s right to use an underlying asset for the lease term, and lease liabilities represent the Company’s obligation to make lease payments arising from the lease. Operating lease ROU assets and lease liabilities are recognized at commencement date based on the present value of lease payments over the lease term. As most of the Company’s leases do not provide an implicit rate, the Company’s estimated incremental borrowing rate

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based on the information available at commencement date is used in determining the present value of lease payments, and the implicit rate is used when readily determinable. The operating lease ROU asset also includes any lease payments made and excludes lease incentives. Lease expense for lease payments is recognized on a straight-line basis over the lease term. The Company gives consideration to various factors, including the terms of the Company’s outstanding debt instruments, publicly available data for instruments with similar characteristics and other information, together with internally generated estimates, assumptions and judgment to determine the Company’s incremental borrowing rate.

We have lease agreements with lease and non-lease components, which are accounted for as a single lease component.

Principles of Consolidation

The Company’s condensed consolidated financial statements include the accounts of the Company and its subsidiaries. All intercompany balances and transactions have been eliminated.

Use of Estimates

The accompanying consolidated financial statements are prepared in conformity with U.S. GAAP, which requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserves and related cash flow estimates used in the depletion and impairment of proved oil and natural gas properties, the evaluation of unproved properties for impairment, the fair value of commodity derivative contracts, embedded derivatives and asset retirement obligations, accrued oil and natural gas revenues and expenses and the allocation of general and administrative ~~(“G&A”)~~ expenses. Actual results could differ materially from those estimates.

~~Table of Contents~~

Recent Accounting Pronouncements

In ~~August 2017,~~ June 2018, the ~~Financial Accounting Standards Board (“FASB”)~~ FASB issued ~~Accounting Standards Update (“ASU”) 2017-12 “Derivatives and Hedging (Topic 815): Targeted~~ASU 2018-07 “Compensation - Stock Compensation (ASC 718) - Improvements to Nonemployee Share-Based Payment Accounting, ~~for Hedging Activities,~~” which ~~changes~~expands the ~~recognition~~scope of ASC 718, Compensation – Stock Compensation, to include share-based payment transactions for acquiring goods and ~~presentation requirements~~services from nonemployees. We adopted this ASU effective January 1, 2019, which resulted in our remeasurement of ~~hedge accounting, including eliminating~~ the ~~requirement~~value of our outstanding unvested awards as of January 1, 2019 and changed the way we value our equity-classified equity awards going forward. Adoption of the standard did not have a material impact on our condensed consolidated financial statements.

In June 2016, the FASB issued ASU 2016-13 “Financial Instruments - Credit Losses (ASC 326): Measurement of Credit Losses on Financial Instruments.” This ASU modifies the impairment model to ~~separately measure and report hedge ineffectiveness, and presenting all items that affect earnings~~utilize an expected loss methodology in place of the currently used incurred loss methodology, which will result in the ~~same income statement line item as the hedged item. The ASU also provides new alternatives for applying hedge accounting.~~ more timely recognition of losses, if applicable. This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, ~~2018. The Company~~2019, and earlier adoption is permitted. We are currently in the process of evaluating the impact of adoption of this guidance on ~~its~~our condensed consolidated financial statements.

~~In January 2017, the FASB issued ASU 2017-01 “Business Combinations (Topic 805) - Clarifying the Definition~~Table of a Business,” which provides a new framework for determining whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2017.The Company adopted this ASU on January 1, 2018, using a prospective method; the clarified definition of a business will be applied by the Company to transactions executed subsequent to the effective date.Contents

In November 2016, the FASB issued ASU 2016-18 “Statement of Cash Flows (Topic 230): Restricted Cash,” which requires companies to include cash and cash equivalents that have restrictions on withdrawal or use in total cash and cash equivalents on the statement of cash flows. This ASU is now effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2017.~~The adoption of ASU 2016-18 did not have an impact on the Company’s unaudited condensed consolidated statement of cash flows.~~

In October 2016, the FASB issued ASU 2016-16 “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory,” which eliminates a current exception in U.S. GAAP to the recognition of the income tax effects of temporary differences that result from intra-entity transfers of non-inventory assets. The intra-entity exception is being eliminated under the ASU. The standard is required to be applied on a modified retrospective basis and is now effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2017. The adoption of ASU 2016-16 did not have an impact on the Company’s unaudited condensed consolidated financial statements and related disclosures.

In August 2016, the FASB issued ASU 2016-15 “Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments”. This ASU is intended to clarify the presentation of cash receipts and payments in specific situations. The amendments in this ASU are effective for financial statements issued for annual periods beginning after December 15, 2017. The Company adopted this ASU on January 1, 2018, using a retrospective method. The adoption of ASU 2016-15 did not have an impact on the Company’s unaudited condensed consolidated statement of cash flows.

In February 2016, the FASB issued ASU 2016-02 “Leases ~~(Topic~~(ASC 842),” effective for annual and interim periods for public companies beginning after December 15, 2018, with a modified retrospective approach to be used for implementation. The standard updates the previous lease guidance by requiring the recognition of a ~~right-to-use~~ROU asset and lease liability on the statement of financial position for all leases with lease terms of more than 12 months. The lease liability represents the discounted obligation to make future minimum lease payments and the corresponding ~~right-of-use~~ROU asset onrepresents the ~~balance sheet~~lessee’s right to use, or control the use of, a specified asset for ~~most leases.~~the lease term. Recognition, measurement and presentation of expenses and cash flows arising from a lease will depend on classification as an operating or a finance ~~or operating~~ lease. The Company ~~has several operating leases as further discussed in Note 17, “Commitments and Contingencies,” which will be impacted by the new rules under this standard. The Company will not early adopt~~adopted this standard ~~and will apply the revised lease rules for our interim and annual reporting periods starting~~effective January 1, 2019. ~~The Company is currently evaluating~~We elected the ~~impact~~package of ~~these rules on its financial statements and has started the assessment process by evaluating the population of leases~~practical expedients permitting us to not reassess under the revised definition. The Company is also in the process of implementing a lease accounting software to properly account for lease data upon adoption. The adoption of this standard will result in an increase in the assets and liabilities on the Company’s condensed consolidated balance sheets. The quantitative impacts of the new standard ~~are dependent~~our prior conclusions regarding lease identification, lease classification and initial direct costs, the practical expedient to not separate lease and non-lease components for all of our existing lessee arrangements, and to elect an accounting policy to not apply the recognition requirements of Topic 842 to our short term leases. We did not elect the practical expedient for use of hindsight in determining the lease term and assessing impairment of our ROU assets. Adoption of Topic 842 resulted in the recognition of ROU assets and lease liabilities for operating leases on the ~~active leases at~~balance sheet and the ~~time of adoption. As a result, the evaluation~~derecognition of the deferred gain previously recorded on a sale-leaseback transaction as a cumulative effect ~~of the new standards will extend over future periods.~~adjustment to retained earnings on January 1, 2019. Amounts recognized at January 1, 2019 for operating leases were as follows (in thousands):


	December 31,		Adjustments due		January 1,
	2018		to Topic 842		2019
ROU assets	$	—	$	344,472	$	344,472
Short term lease liabilities		—		99,693		99,693
Other current liabilities		75,581		(23,720)		51,861
Long term lease liabilities		—		246,746		246,746
Other long term liabilities		21,407		(20,745)		662
Accumulated deficit		(1,812,884)		42,499		(1,770,385)

~~In May 2014,~~No impact was recorded to the ~~FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606).” In March, April, May and December~~condensed consolidated statement of ~~2016, the FASB issued rules clarifying several aspects of the new revenue~~

~~Table of Contents~~

recognition standard. The new guidance is effective for fiscal years and interim periods beginning after December 15, 2017. 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 standard also requires more detailed disclosuresoperations related to the ~~nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. See Note 18. “Revenue Recognition” for discussion of the Company’s~~ adoption of ~~the new standard.~~ Topic 842.

Note 3. ~~Change in Accounting Principle~~Leases

~~During~~We determine if an arrangement is a lease at inception. To the fourth quarter of 2017, the Company voluntarily changed its method of accounting for oil and natural gas exploration and development activities from the full cost method to the successful efforts method. Accordingly, financial information for prior periods has been recast to reflect retrospective application of the successful efforts method. In general, under successful efforts, exploration expenditures suchextent that we determine an arrangement represents a lease, we classify that lease as exploratory dry holes, exploratory geological and geophysical costs, delay rentals, unproved impairments, and exploration overhead are charged against earnings as incurred, versus being capitalized under the full cost method of accounting. The successful efforts method also provides for the assessment of potential property impairments under FASB Accounting Standards Codification 360 “Property, Plant and Equipment” by comparing the net carrying value of oil and natural gas properties with associated projected undiscounted pre-tax future net cash flows. If the expected undiscounted pre-tax future net cash flows are lower than the unamortized capitalized costs, the capitalized cost is reduced to fair value. Under the full cost method of accounting,an operating lease or a ~~write-down would be required if the net carrying value of oil and natural gas properties exceeds a full cost “ceiling,” using an unweighted arithmetic average of commodity prices in effect~~finance lease. We currently do not have any finance leases. We capitalize our operating leases on the first day of each of the previous 12 months. In addition, gains or losses, if applicable, are generally recognized on the dispositions of oil and natural gas property and equipment under the successful efforts method, as opposed to an adjustment to the net carrying value of the remaining assets under the full cost method. Our consolidated financial statements have been recast to reflect these differences for all periods presented, including the Condensed Consolidated Balance Sheets, Condensed Consolidated Statements of Operations, Condensed Consolidated Statements of Stockholders’ Equity, Condensed Consolidated Statements of Cash Flows and related information in Notes 3, 4, 6, 12, 13, 14, 16 and 19.

~~The following table presents the effects of the change to the successful efforts method in the condensed~~our consolidated balance sheet ~~(in thousands):~~through a ROU asset and a corresponding lease liability. ROU assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. Short term leases that have an initial term of one year or less are not capitalized but are disclosed below. Short term lease costs exclude expenses related to leases with a lease term of one month or less.

Changes to Condensed Consolidated Balance Sheet
March 31, 2017

Under Full Cost

Changes

As Reported Under Successful Efforts
Oil and natural gas properties:

Proved oil and natural gas properties

$
4,077,686

$
(1,324,878)

$
2,752,808
Unproved oil and natural gas properties

466,868

(6,705)

460,163
Total oil and natural gas properties

4,544,554

(1,331,583)

3,212,971
Less: Accumulated depreciation, depletion, amortization and impairment

(2,769,126)

1,381,319

(1,387,807)
Total oil and natural gas properties, net

1,775,428

49,736

1,825,164
Total assets

$
2,078,560

$
49,736

$
2,128,296

Current liabilities:

Other current liabilities

$
17,273

$
8,907

$
26,180
Total current liabilities

172,557

8,907

181,464
Other liabilities

63,506

22,639

86,145
Total liabilities

2,156,133

31,546

2,187,679
Accumulated deficit

(1,822,912)

18,190

(1,804,722)
Total stockholders' equity (deficit)

(481,502)

18,190

(463,312)

Our operating leases are reflected as operating lease ROU assets, short term operating lease liabilities and long term operating lease liabilities on our consolidated balance sheet. Operating lease ROU assets and liabilities are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term. In addition to the present value of lease payments, the operating lease ROU asset also includes any lease payments made to the lessor prior to lease commencement less any lease incentives and initial direct costs incurred. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term.

Nature of Leases

We lease property including corporate and field offices and facilities, vehicles, field equipment, and midstream gathering and processing facilities to support our operations. A more detailed description of our significant lease types is included below.

Midstream Gathering and Processing Facilities

We engage in various types of transactions with midstream entities to gather and/or process our products leveraging integrated systems and facilities wholly owned by the midstream counterparty. Under certain of these arrangements, we utilize substantially all of the underlying gathering system or processing facility capacity and we have, therefore, concluded that those underlying assets meet the definition of an identified asset. These contracts have non-

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~~The following table presents the effects~~cancellable lease terms of approximately 4 to 17 years and continue thereafter on a renewable basis subject to termination by either party with notice. Consequently, certain of our gathering and/or processing contracts represent an operating lease of the ~~change~~underlying midstream system or facilities with a lease term that equals the primary non-cancellable contract term.

Real Estate

We rent space from third parties for our corporate and field office locations and lease acreage for general corporate purposes. Our office and acreage lease agreements are structured with non-cancellable lease terms of 3 to 10 years. We have concluded that these agreements represent operating leases with a lease term that equals the primary non-cancellable contract term. Upon completion of the primary term, both parties have substantive rights to terminate the lease.

Field Equipment and Vehicles

We enter into daywork contracts for drilling rigs with third parties to support our drilling activities. Our drilling rig arrangements are typically structured with a term that is in effect until drilling operations are completed on a specified well or well pad in accordance with the development plan. Upon mutual agreement with the contractor, we typically have the option to extend the contract term for additional wells or well pads by providing thirty days’ notice prior to the end of the original contract term. We have concluded that our drilling rig arrangements represent an operating lease with lease terms of 5 to 15 months. For those arrangements with terms of less than one year, we have determined those arrangements to be short term operating lease. Due to the continuously evolving nature of our drilling schedules and the potential volatility in commodity prices in an annual period, our strategy to enter into shorter term drilling rig arrangements allows us the flexibility to respond to changes in our operating and economic environment. We exercise our discretion in choosing to extend or not extend contracts on a rig-by-rig basis depending on the conditions present at the time the contract expires. At the time of contract commencement, we have determined we cannot conclude with reasonable certainty if we will choose to extend the contract beyond its original term. Pursuant to the successful efforts method inof accounting, our net share of these costs are capitalized as part of oil and natural gas properties on the ~~statement of consolidated operations (in thousands, except per share amounts):~~

Changes to the Condensed Consolidated Statement of Operations
For the three months ended March 31, 2017

Under Full Cost

Changes

As Reported Under Successful Efforts
Oil and natural gas production expenses

$
40,225

$
(2,227)

$
37,998
Exploration expenses

—

352

352
Depreciation, depletion, amortization and accretion

33,206

(6,802)

26,404
Impairment of oil and natural gas properties

—

1,845

1,845
Gain on sale of oil and natural gas properties

5,143

(799)

4,344
Net income

9,702

6,033

15,735
Net income allocable to participating securities

—

—

—
Net loss attributable to common stockholders

$
(12,461)

$
6,033

$
(6,428)

Net loss per common share - basic and diluted

$
(0.18)

$
0.09

$
(0.09)

~~The following table presents the effects of the change to the successful efforts method in the statement of consolidated cash flows (in thousands):~~

Changes to the Condensed Consolidated Statement of Cash Flows
For the three months ended March 31, 2017


Under Full Cost

Change

As reported Under Successful Efforts
Net income

$
9,702

$
6,033

$
15,735
Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation, depletion, amortization and accretion

33,206

(6,802)

26,404
Impairment of oil and natural gas properties

—

1,845

1,845
Gain on sale of oil and natural gas properties

(5,143)

799

(4,344)
Amortization of deferred gain on Catarina Midstream Sale

(3,702)

(2,227)

(5,929)
Net cash used in operating activities

(13,336)

(352)

(13,688)
Payments for oil and natural gas properties

(88,074)

352

(87,722)
Net cash used in investing activities

(1,127,761)

352

(1,127,409)
Net cash provided by financing activities

763,765

—

763,765
Decrease in cash and cash equivalents

(377,332)

—

(377,332)
Cash and cash equivalents, beginning of period

501,917

—

501,917
Cash and cash equivalents, end of period

$
124,585

$
—

$
124,585

balance sheet as incurred.

~~Note 4. Acquisitions~~We rent compressors from third parties to facilitate the downstream movement of our production from our drilling operations to market. Our compressor arrangements typically have non-cancellable lease terms of 12 to 24 months and ~~Divestitures~~continue thereafter on a month-to-month basis subject to termination by either party with thirty days’ notice. We have concluded that our compressor arrangements represent operating leases with a lease term that equals the primary non-cancellable contract term. Upon completion of the primary term, both parties have substantive rights to terminate the lease.

We rent our vehicle fleet for our drilling and operations personnel. Our vehicle agreements have non-cancellable lease terms of 18 months. We have concluded that our vehicle agreements represent operating leases with a lease term that equals the primary non-cancellable contract term. Upon completion of the primary term, both parties have substantive rights to terminate the lease.

Significant Judgments

Discount Rate

Our ~~acquisitions~~leases typically do not provide an implicit rate. Accordingly, we are ~~accounted for under~~required to use our estimated incremental borrowing rate in determining the ~~acquisition method~~present value of ~~accounting in accordance with ASC Topic 805, “Business Combinations” (“ASC Topic 805”). A business combination may result in the recognition of a gain or goodwill~~lease payments based on the ~~measurement~~information available at commencement date. Our estimated incremental borrowing rate reflects a reasonable projection of the ~~fair value~~interest that we would expect to pay to borrow, on a collateralized basis, over a similar term, an amount equal to the lease payments in a similar economic environment. The Company gives consideration to various factors, including the terms of the ~~assets acquired at~~Company’s outstanding debt instruments, publicly available data for instruments with similar characteristics and other information, together with internally generated estimates, assumptions and judgment to determine the acquisition date as compared to the fair value of consideration transferred, adjusted for purchase price adjustments. The initial accounting for acquisitions may not be complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates. The results of operations of the properties acquired in our acquisitions have been included in the condensed consolidated financial statements since the closing dates of the acquisitions.

Company’s incremental borrowing rate.

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~~Javelina Disposition~~

Practical Expedients and Accounting Policy Elections

~~On September 19, 2017,~~Certain of our lease arrangements include lease and non-lease components. For all existing asset classes with multiple component types, we have utilized the ~~Company, through its wholly owned subsidiary, SN Cotulla Assets, LLC (“SN Cotulla”), sold approximately 68,000 undeveloped net acres located~~practical expedient to not separate lease and non-lease components. Accordingly, we account for the lease and non-lease components in an arrangement as a single lease component.

In addition, for all existing asset classes, we have elected an accounting policy to not apply the ~~Eagle Ford Shale~~recognition requirements of Topic 842 to our short term leases. Accordingly, we recognize lease payments related to our short term leases in ~~LaSalle~~our statement of operations, which has not changed from our prior recognition.

The following are components of our lease expense for the three months ended March 31, 2019, the majority of which are included in oil and Webb Counties, Texas to Vitruvian Exploration IV, LLC for approximately $105 million in cash, after preliminary closing adjustments (the “Javelina Disposition”). Consideration received from the Javelina Disposition was based on an August 1, 2017 effective date and is subject to normal and customary post-closing adjustments. The Company recorded a gain of approximately $73.7 millionnatural gas production expenses on the ~~Javelina Disposition.~~condensed consolidated statement of operations (in thousands):


	Three Months Ended
	March 31, 2019
Operating lease expense	$	25,431
Short term and variable lease expense		8,431
Total lease expense	$	33,862

Operating lease cost(1)	$	2,124
Short term and variable lease cost(1)		1,662
Total lease cost	$	3,786

~~Marquis Disposition~~

(1)

Represents capital expenditures related to the use of drilling rigs for the three months ended March 31, 2019 which are capitalized as part of oil and natural gas properties on our condensed consolidated balance sheets.

Other information related to our operating leases are as follows (in thousands, except lease term and discount rate):

On June 15, 2017, the Company, through its wholly owned subsidiary, SN Marquis LLC, sold approximately 21,000 net acres primarily located in the Eagle Ford Shale in Fayette and Lavaca Counties, Texas to Lonestar Resources US, Inc. (“Lonestar”) for approximately $44 million in cash, after preliminary closing adjustments, and approximately $6.0 million in Lonestar’s Series B Convertible Preferred Stock, valued as of the closing date, which subsequently converted into 1.5 million shares of Lonestar’s Class A Common Stock (the “Marquis Disposition”). The consideration received from the Marquis Disposition was based on a January 1, 2017 effective date and is subject to other normal and customary post-closing adjustments. Assets conveyed pursuant to the Marquis Disposition consist of net proved reserves of approximately 2.7 MMBoe (100% developed) and net production of approximately 1,750 Boe per day from 104 gross (65 net) wells. The Company did not record any gains or losses as a result of the Marquis Disposition.


	Three Months Ended
	March 31, 2019
Operating cash flows from operating leases	$	33,862
Investing cash flows from operating leases		3,786
ROU assets obtained in exchange for operating lease obligations		347,845
Amortization of ROU assets		(25,614)

Weighted average remaining lease term (years)		3.5
Weighted average discount rate		10.0%

~~Comanche Acquisition~~

OnAs of March 1, 2017, the Company, through two of its subsidiaries, SN EF UnSub, LP (“SN UnSub”) and SN EF Maverick, LLC (“SN Maverick”), along with Gavilan Resources, LLC (“Gavilan”), an entity controlled by The Blackstone Group, L.P., completed the acquisition of approximately 318,000 gross (155,000 net) acres comprised of 252,000 gross (122,000 net) Eagle Ford Shale acres and 66,000 gross (33,000 net) acres of deep rights only, which includes the Pearsall Shale, representing an approximate 49% average working31, 2019, minimum future payments, including imputed interest, ~~therein (the “Comanche Assets”) from Anadarko E&P Onshore LLC and Kerr-McGee Oil and Gas Onshore LP (together, “Anadarko”)~~ for approximately $2.1 billion in cash (the “Comanche Acquisition”). Pursuant to the purchase and sale agreement entered into in connection with the Comanche Acquisition, (i) SN UnSub paid approximately 37% of the purchase price (including through a $100 million cash contribution from other Company entities) and (ii) SN Maverick paid approximately 13% of the purchase price. In the aggregate, SN UnSub and SN Maverick acquired half of the 49% working interest in the Comanche Assets (approximately 50% and 0%, respectively, of the estimated total proved developed producing reserves (PDPs), 20% and 30%, respectively, of the estimated total proved developed non-producing reserves (PDNPs), and 20% and 30%, respectively, of the total proved undeveloped reserves (PUDs)) (“SN Comanche Assets”). Pursuant to the purchase and sale agreement, Gavilan paid 50% of the purchase price and acquired the remaining half of the 49% working interest in and to the Comanche Assets (and approximately 50% of the estimated total PDPs, PDNPs and PUDs). The Comanche Assetsour long term operating leases under ASC 842 are primarily located in the Western Eagle Ford and are contiguous with our existing acreage, significantly expanding our asset base and production. The effective date of the Comanche Acquisition was July 1, 2016. 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):

Proved oil and natural gas properties

$
781,789

Unproved properties

263,471

Other assets acquired

6,702

Fair value of assets acquired

1,051,962

Asset retirement obligations

(8,289)

Fair value of net assets acquired

$
1,043,673


2019	$	98,692
2020		112,584
2021		79,885
2022		59,660
2023		26,258
Thereafter		8,616
Total lease payments		385,695
Less: Imputed interest		60,873
Present value of lease liabilities	$	324,822

In addition, as is common in our industry, we are party to certain gathering agreements that obligate us to deliver a specified volume of production over a defined time horizon. In particular, we, as the operator, on behalf of ourselves and the other working interest partners, are party to two gathering agreements that require us to deliver variable monthly quantities through 2034. Gross volumes under these contracts peak at approximately 63,000 Bbl per day (approximately 14,800 Bbl per day net) of crude oil and condensate in 2020 and 430,000 Mcf per day (approximately 101,400 Mcf per day net) of natural gas in 2022, and then decrease annually thereafter through the end of

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~~the contracts. We are currently meeting~~

As of December 31, 2018, undiscounted minimum future payments for our ~~minimum volume commitments~~long term operating leases under ~~these contracts and expect to continue to fulfill these obligations based on our anticipated development plan for the Comanche Assets.~~ASC 840 were as follows (in thousands):

~~Cotulla Disposition~~

On December 14, 2016, SN Cotulla Assets, LLC (“SN Cotulla”), a wholly-owned subsidiary of the Company, completed the initial closing of the sale of certain oil and natural gas interests and associated assets located in Dimmit County, Frio County, LaSalle County, Zavala County and McMullen County, Texas (the “Cotulla Assets”) to Carrizo (Eagle Ford) LLC (“Carrizo Eagle Ford”), pursuant to a purchase and sale agreement dated October 24, 2016 by and among SN Cotulla, the Company for the limited purposes set forth therein, Carrizo Eagle Ford and Carrizo Oil and Gas for the limited purposes set forth therein, for an adjusted purchase price of approximately $153.5 million, subject to normal and customary post-closing adjustments (the “Cotulla Disposition”). The assets sold included estimated net proved reserves as of the effective date of June 1, 2016 of approximately 6.9 MMBoe. Proved developed reserves are estimated to account for approximately 90% of the total net proved reserves. As of the effective date, the Cotulla Assets consisted of approximately 15,000 net acres with 112 gross (93 net) wells producing approximately 3,000 Boe/d. During 2017, two additional closings occurred and final settlement adjustments were made resulting in total aggregate consideration of approximately $167.4 million.

Typically, the sale or disposition of oil and natural gas properties results in a gain or loss being recorded as the difference between the proceeds received and the net capitalized costs of the oil and natural gas properties, unless the sale or disposition does not cause a significant change in the relationship between costs and the estimated quantities of proved reserves. In circumstances where treating a sale like a normal retirement does not result in a significant change in the relationship between costs and the estimated quantities of proved reserves, the proceeds are applied to reduce net capitalized costs. The Company determined that adjustments to capitalized costs for the Cotulla Disposition would cause a significant change in the relationship between costs and the estimated quantities of proved reserves. Upon the initial closing of the Cotulla Disposition, the Company recorded a gain of approximately $85.3 million. As a result of subsequent closings of the Cotulla Disposition, the Company recorded additional gains of $4.3 million and $6.0 million during the three months ended March 31, 2017 and June 30, 2017, respectively.


2019	$	100,640
2020		84,472
2021		52,499
2022		31,682
2023		11,631
Thereafter		8,467
Total lease payments	$	289,391

Note 4. Revenue Recognition

Revenue from Contracts with Customers

We account for revenue from contracts with customers in accordance with ASC 606. The unit of account in ASC 606 is a performance obligation, which is a promise in a contract to transfer to a customer either a distinct good or service (or bundle of goods or services) or a series of distinct goods or services provided over a period of time. ASC 606 requires that a contract’s transaction price, which is the amount of consideration to which an entity expects to be entitled in exchange for transferring promised goods or services to a customer, is to be allocated to each performance obligation in the contract based on relative standalone selling prices and recognized as revenue when (point in time) or as (over time) the performance obligation is satisfied.

ASC 606 provides additional clarification related to principal versus agent considerations. We enter into marketing agreements with our non-operating partners to market and sell their share of production to third parties. We have determined that we act as an agent in such arrangements and account for such arrangements on a net basis.

Certain of our contracts for the sale of commodities meet the definition of a derivative. We have elected the normal purchases and normal sales scope exception as provided by ASC 815, Derivatives and Hedging, and account for such contracts in accordance with ASC 606.

Disaggregation of Revenue

We recognized revenue of $216.7 million and $251.2 million for the three months ended March 31, 2019 and 2018, respectively. We disaggregate revenue in our income statement based on product type, and we further disaggregate our revenue related to sales and marketing activities.

In selecting the disaggregation categories, we considered a number of factors, including disclosures presented outside the financial statements, such as in our earnings release and investor presentations, information reviewed internally for evaluating performance, and other factors used by the Company or the users of its financial statements to evaluate performance or allocate resources. As such, we have concluded that disaggregating revenue by product type appropriately depicts how the nature, amount, timing and uncertainty of revenue and cash flows are affected by economic factors.

Oil, Natural Gas, and NGL Revenues

We recognize revenue from the sale of oil, natural gas and NGLs in the period that the performance obligations are satisfied. Our performance obligations are primarily comprised of the delivery of oil, natural gas or NGLs at a delivery point. Each barrel of oil, barrel of NGL, MMBtu of natural gas or other unit of measure is separately identifiable and represents a distinct performance obligation to which the transaction price is allocated. Performance obligations are satisfied at a point in time once control of the product has been transferred to the customer through delivery of oil, natural gas and NGLs.

We sell oil at market based prices with adjustments for location and quality. Under our oil sales contracts, we transfer control of the product to the purchaser at the delivery point and recognize revenue based on the contract price. The costs to transport the oil are recorded as oil and natural gas production expenses.

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Under our natural gas sales contracts, we deliver natural gas to the purchaser at an agreed upon delivery point. Natural gas is transported from our wellheads to delivery points specified under sales contracts. To deliver natural gas to these points, third parties gather, process and transport our natural gas. We maintain control of the natural gas during gathering, processing and/or transportation. We transfer control of the product at the delivery point and recognize revenue based on the contract price. The costs to gather, process and transport the natural gas are recorded as oil and natural gas production expenses.

NGLs, which are extracted from natural gas through processing, are either sold by us directly to the customer or are sold by the processor under our processing contracts. For NGLs sold by us directly, we transfer control of the product to the purchaser at the delivery point and recognize revenue based on the contract price. The costs we incur to process and transport NGLs are recorded as oil and natural gas production expenses. For NGLs sold by the processor, our processing contracts provide that we transfer control to the processor at the tailgate of the processing plant and we recognize revenue based on the price received from the processor.

Our contracts with customers typically require payment for oil and condensate, natural gas and NGL sales within 30 days following the calendar month of delivery. The sales of oil and condensate, natural gas and NGLs typically include variable consideration that is based on pricing tied to local indices adjusted for differentials and volumes delivered in the current month. Revenues include estimates for the two most recent months using published commodity price indices and volumes supplied by field operators.

Sales and Marketing Revenue

Beginning in 2018, we entered into commodity purchase transactions with certain third parties and then subsequently sold the purchased commodity as separate revenue streams. We believe an opportunity exists, from time to time, to participate in additional economic benefits and operational efficiencies in support of our upstream activities by purchasing and reselling production from others, to a limited extent, in order to utilize existing firm transportation arrangements. We retain control of the purchased hydrocarbons prior to delivery to the purchaser. The Company has concluded that we are the principal in these arrangements and therefore we recognize revenue on a gross basis as Sales and Marketing Revenues within our consolidated statement of operations, with costs to purchase and transport the commodity presented as Sales and Marketing Expenses in our consolidated statement of operations. Contracts to sell the third-party hydrocarbons are the same contracts as those for which we sell our produced hydrocarbons, and as such, we do not recognize this revenue any differently than our oil, natural gas and NGL revenue discussed previously.

Remaining Performance Obligations

Several of our sales contracts contain multiple performance obligations as each barrel of oil, barrel of NGL, MMBtu of natural gas or other unit of measure is separately identifiable. For these contracts, we have taken the optional exception under ASC 606-10-50-14A(b) which is available only for wholly unsatisfied performance obligations for which the criteria in ASC 606-10-32-40 have been met. Under this exception, neither estimation of variable consideration nor disclosure of the transaction price allocated to the remaining performance obligations is required. Revenue is alternatively recognized in the period that control of the commodity is transferred to the customer and the respective variable component of the total transaction price is resolved.

For forms of variable consideration that are not associated with a specific volume and thus do not meet the allocation exception, estimation is required. Examples of such variable consideration consist of deficiency payments, late payment fees, truck rejection charges, inflation adjustments and imbalance penalties; however, these items are immaterial to our condensed consolidated financial statements and/or have a low probability of occurrence. As significant reversals of revenue due to this variability are not probable, no estimation is required.

Contract Balances

Under our sales contracts, we invoice customers after our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our contracts do not give rise to contract assets or liabilities under ASC 606. At March 31, 2019 and December 31, 2018, our receivables from contracts with customers were $79 million and $87.2 million, respectively.

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Note 5. Cash and Cash Equivalents

As of March 31, ~~2018~~2019 and December 31, ~~2017,~~2018, cash and cash equivalents consisted of the following (in thousands):


	March 31,		December 31,		March 31,		December 31,
	2018		2017		2019		2018
Cash at banks	$	125,647	$	135,363	$	39,733	$	66,426
Cash equivalents		424,397		49,071
Money market funds						160,965		131,187
Total cash and cash equivalents	$	550,044	$	184,434	$	200,698	$	197,613

Our cash includes funds held in deposit accounts with highly rated banks, and our cash equivalents include funds held in stable and highly liquid money market accounts with major financial institutions.

Note 6. Oil and Natural Gas Properties

The Company’s oil and natural gas properties are accounted for using the successful efforts method of accounting. All direct costs and certain indirect costs associated with the acquisition, successful exploration and development of oil and natural gas properties are capitalized. Once evaluated, these costs, as well as the estimated costs to retire the assets, are included in the amortization base and amortized to depletion expense using the units‑of‑production method. Depletion is calculated based on estimated proved oil and natural gas reserves. The sale or disposition of oil and natural gas properties results in a gain or loss unless the sale or disposition does not cause a significant change in the relationship between costs and the estimated quantities of proved reserves in which case the proceeds are applied to reduce net capitalized costs.

~~Depreciation, depletion and amortization~~—Depreciation, depletion and amortization (“DD&A”) is provided using the units‑of‑production method based upon estimates of proved reserves of oil, natural gas and NGLs and conversion of production of the same to a common unit of measure based upon the relative energy content of each hydrocarbon. The Company groups its oil and natural gas properties with a common geological structure or stratigraphic condition (“common operating field”) in accordance with ASC 932 “Extractive Activities – Oil and Gas” for purposes of computing DD&A, assessing proved property impairments and accounting for asset dispositions. All capitalized costs of

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oil and natural gas properties are amortized using the units‑of‑production method based on proved reserves. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined. Once the assessment of unproved properties is complete and when major development projects are evaluated, the costs previously excluded from the amortization base are transferred to proved oil and natural gas properties and amortization begins. All other non-oil and natural gas assets are stated at historical cost, net of impairments, and are depreciated using the straight-line method over their respective useful lives.

In arriving at depletion rates under the units‑of‑production method, the quantities of recoverable oil and natural gas reserves are established based on estimates made by internal and third party geologists and engineers, which require significant judgment as does the projection of future production volumes and levels of future costs. In addition, considerable judgment is necessary in determining the existence of proved reserves once a well has been drilled. All of these judgments may have significant impact on the calculation of depletion expense.

Impairment of Oil and Natural Gas Properties —Capitalized costs (net of accumulated DD&A and impairment) of proved oil and natural gas properties are subjected to an impairment test when facts and circumstances indicate that their carrying value may not be recoverable. We compare net capitalized costs of proved oil and natural gas properties to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect our estimation of future price volatility. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, using estimated discounted future net cash flows. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that management believes will impact realizable prices ~~of our oil and natural gas properties. We~~—We did not record a proved property impairment during the three months ended March 31, ~~2018 and 2017.~~2019 or 2018. Changes in production rates, levels of reserves, future development costs, and other factors will impact our actual impairment analyses in future periods.

Unproved Properties—Costs associated with unproved properties and properties under development are excluded from the amortization base until the properties have been evaluated. Additionally, the costs associated with leasehold acreage and wells currently drilling are also initially excluded from the amortization base. Unproved properties are identified on a project basis, with a project being an area in which significant leasehold interests are acquired within a contiguous area. Unproved properties are reviewed periodically by management and transferred into the amortization base when management determines that a project area has been evaluated through drilling operations or thorough geologic evaluation. If the results of an assessment indicate that the properties are impaired, the carrying amount of the identified unproved properties are reduced to their fair value. We recorded impairment of ~~$0.9~~$3.9 million and ~~$1.8~~$0.9 million to our unproved oil and natural gas properties for the three months ended March 31, ~~2018~~2019 and ~~2017,~~2018, respectively, due to acreage expirations from changes in the development plan.

Note 7. Debt

Debt as of March 31, 2018 consisted of (i) $171.5 million under the SN UnSub Credit Agreement (as defined below), which is non-recourse to SN and the other obligors on the 6.125% Notes (defined below), 7.75% Notes (defined below), 7.25% Senior Secured Notes (defined below) and the Credit Agreement (defined below) (“Non-Recourse to the Company”), as well as to the obligors under the SR Credit Agreement (defined below) and the Non-Recourse Subsidiary Term Loan (defined below), (ii) $600 million principal amount of 7.75% Notes maturing on June 15, 2021, (iii) approximately $4.1 million related to a 4.59% non-recourse subsidiary term loan due 2022 (the “Non-Recourse Subsidiary Term Loan”), which is Non-Recourse to the Company and to the obligors under the SN UnSub Credit Agreement and the SR Credit Agreement, (iv) $1.15 billion principal amount of 6.125% Notes maturing on January 15, 2023, (v) $500 million in principal amount of 7.25% Senior Secured maturing on February 15, 2023, subject to satisfaction of certain conditions, and (vi) approximately $24.0 million related to the SR Credit Agreement, which is Non-Recourse to the Company and to the obligors under the SN UnSub Credit Agreement and the Non-Recourse Subsidiary Term Loan.

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As of March 31, ~~2018,~~2019, and December 31, ~~2017,~~2018, the Company’s outstanding debt consisted of the following:


			Amount Outstanding						March 31,		December 31,
			(in thousands) as of				Interest Rate	Maturity Date	2019		2018
Short Term Debt:										(in thousands)
			March 31,		December 31,
SR Credit Agreement(1)(2)							Variable	-	$	245	$	304
Total short term debt									$	245	$	304
	Interest Rate	Original Maturity Date	2018		2017
Short-Term Debt
SR Credit Agreement(1)(2)	Variable	August 8, 2018	$	23,996	$	23,996
Total short-term debt			$	23,996	$	23,996

Long-Term Debt
Credit Agreement	Variable	February 14, 2023	$	—	$	50,000
Long Term Debt:
7.75% Notes							7.75%	June 15, 2021	$	600,000	$	600,000
SN UnSub Credit Agreement(1)	Variable	March 1, 2022		171,500		175,500	Variable	March 1, 2022		165,000		167,500
7.75% Notes	7.75%	June 15, 2021		600,000		600,000
4.59% Non-Recourse Subsidiary Term Loan(1)	4.59%	August 31, 2022		4,077		4,164	4.59%	August 31, 2022		3,721		3,803
SR Credit Agreement(1)							Variable	October 31, 2022		22,942		23,187
6.125% Notes	6.125%	January 15, 2023		1,150,000		1,150,000	6.125%	January 15, 2023		1,150,000		1,150,000
Credit Agreement(3)							Variable	February 14, 2023		—		—
7.25% Senior Secured Notes	7.25%	February 15, 2023		500,000		—	7.25%	February 15, 2023		500,000		500,000
				2,425,577		1,979,664				2,441,663		2,444,490
Unamortized discount on Additional 7.75% Notes				(2,900)		(3,126)				(1,996)		(2,222)
Unamortized premium on Additional 6.125% Notes				1,292		1,360				1,023		1,090
Unamortized discount on 7.25% Senior Secured Notes				(5,012)		—				(3,984)		(4,241)
Unamortized debt issuance costs				(52,462)		(47,215)				(40,555)		(43,709)
Total long-term debt			$	2,366,495	$	1,930,683
Total long term debt									$	2,396,151	$	2,395,408

(1)

~~These~~Represents debt instruments which are Non-Recourse to the Company.

(2)

~~Bears~~Incurred interest at a weighted-average ~~interest~~ rate of ~~5.359%~~approximately 6.0% and ~~5.122%~~6.8% for the three months ended March 31, ~~2018~~2019 and the ~~one month~~year ended December 31, ~~2017,~~2018, respectively.

(3)

A standby letter of credit in the amount of approximately $17.1 million was issued under the Credit Agreement on January 10, 2019 and incurred fees at a rate of 3.25% for the three months ended March 31, 2019. The letter of credit remains outstanding and is undrawn.

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The components of interest expense are (in thousands):


	Three Months Ended				Three Months Ended
	March 31,				March 31,
	2018		2017		2019		2018
Interest on SR Credit Agreement	$	(348)	$	—	$	(225)	$	(348)
Interest and commitment fees on Credit Agreement		(665)		(379)
Interest on SN UnSub Credit Agreement		(2,301)		(756)
Interest on Senior Notes		(33,564)		(29,234)		(38,297)		(33,564)
Interest and commitment fees on SN UnSub Credit Agreement						(2,283)		(2,301)
Interest on Non-Recourse Subsidiary Term Loan		(47)		—		(42)		(47)
Interest, commitment fees and letter of credit fees on Credit Agreement						(136)		(665)
Amortization of debt issuance costs		(6,714)		(2,497)		(3,154)		(6,714)
Amortization of discounts and premium on Senior Notes		(281)		(159)		(416)		(281)
Total interest expense	$	(43,920)	$	(33,025)	$	(44,553)	$	(43,920)

Credit Facilities

Third Amended and Restated Credit Agreement

On February 14, 2018, the Company ~~as borrower, and its existing restricted subsidiaries, as loan parties (the “Loan Parties”),~~ entered into a revolving credit facility, ~~represented by a Third Amended and Restated Credit Agreement dated as of February 14, 2018 with Royal Bank of Canada,~~ providing for a $25 million first-out senior secured working capital and letter of credit facility (the “Credit Agreement”), which amended and restated the Company’s previous credit facility in its entirety. Although pari passu in right of payment with the 7.25% Senior Secured Notes, the obligations under our amended and restated credit facility and specified hedging and cash management obligations have, pursuant to the terms of a collateral trust agreement, “first-out” status as to proceeds of the shared collateral and thus the 7.25% Senior Secured Notes are, to the extent of the value of the collateral, effectively junior to the obligations under our amended and restated credit facility and such specified hedging and cash management obligations. Availability under the

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~~Credit Agreement is at all times subject to customary conditions but, except in limited circumstances, not to satisfaction of any collateral coverage ratio or other maintenance covenants.~~ As of March 31, ~~2018,~~2019, there were no outstanding borrowings ~~and no letters of credit outstanding~~ under the Credit Agreement.

~~The Credit Agreement will mature~~ However, on January 10, 2019, a standby letter of credit was issued on our behalf by the earlier of (i) February 14, 2023 and (ii) the 91st day prior to the scheduled maturity of any “material indebtedness,” which is defined to include, without limitation, any indebtedness arising in connection with the Company’s 7.75% Notes, 6.125% Notes or the 7.25% Senior Secured Notes. The 7.75% Notes are scheduled to mature on June 15, 2021.

~~The Company’s obligations~~lender under the Credit Agreement are guaranteed by all of the Company’s restricted subsidiaries that guarantee the 7.25% Senior Secured Notes and, pursuant to the CTA (as defined below), are secured by priority liens on a first-out collateral proceeds payment priority basis in the ~~Shared Collateral (as defined below), subject only to permitted collateral liens.~~

At the Company’s election, interest on borrowings under the Credit Agreement may be calculated based on an ABR or an adjusted Eurodollar (LIBOR) rate, plus an applicable margin. The applicable margin is either 1.50% or 2.25% for ABR borrowings and either 2.50% or 3.25% for Eurodollar (LIBOR) borrowings and lettersamount of approximately $17.1 million. This letter of credit ~~if any, depending on the Company’s utilization of the availability under the Credit Agreement. The Company~~currently remains outstanding and is also required to pay a commitment fee of 0.50% per annum on any unused commitment amount. Interest on ABR borrowings and the commitment fee are generally payable quarterly. Interest on Eurodollar borrowings are generally payable at the end of the applicable interest period.undrawn.

The Credit Agreement contains various affirmative and negative covenants and events of default that limit the Company’s ability to, among other things, incur indebtedness, make restricted payments, grant liens and consolidate or merge. The Credit Agreement also provides for cross default between the Credit Agreement and the other material indebtedness of the Company and its restricted subsidiaries, in an aggregate principal amount in excess of $40 million. As of March 31, ~~2018,~~2019, the Company was in compliance with the covenants of the Credit Agreement.

~~From time~~ Without the restructuring of our current obligations under our existing outstanding debt and preferred stock instruments, we may have difficulties maintaining compliance with certain covenants under the Credit Agreement as commodity prices continue to ~~time, the agents, arrangers, book runners and lenders~~remain low. We could request a waiver of these covenant violations if necessary; however, there is no assurance a waiver would be granted. If a waiver were required but not granted, we would be in default under the Credit Agreement and ~~their affiliates have provided,~~the lender under the Credit Agreement could terminate the commitment thereunder, accelerate the repayment of debt and ~~may provide~~require cash collateralization of any letters of credit. Any acceleration of our debt obligations could result in a foreclosure on the ~~future, investment banking, commercial lending, hedging and financial advisory services to~~collateral securing the ~~Company and its affiliates in the ordinary course of business, for which they have received, or may in the future receive, customary fees and commissions for these transactions.~~debt.

SN UnSub Credit Agreement

On March 1, 2017, SN EF UnSub, ~~as borrower,~~LP (“SN UnSub”) entered into a credit agreement for a $500 million revolving credit facility ~~with JP Morgan Chase Bank, N.A. as the administrative agent and the lenders party thereto~~ with a maturity date of March 1, 2022 (the “SN UnSub Credit Agreement”). ~~The initial~~On December 10, 2018, as part of the most recent semi-annual redetermination, the borrowing base ~~amount~~ under the SN UnSub Credit Agreement was ~~$330 million. Additionally, the SN UnSub Credit Agreement provides for the issuance of letters of credit, generally limited~~decreased from $380 million to $315 million and may be further reduced in the aggregate to the lesser of $50 million and the total availability under the borrowing base. Availability under the SN UnSub Credit Agreement is at all times subject to customary conditions and the then applicablefuture. The next regularly scheduled borrowing base ~~which~~redetermination is ~~subject to periodic redetermination.~~ expected in the second quarter 2019.

As of March 31, ~~2018,~~2019, there were approximately ~~$171.5~~$165.0 million of borrowings and no letters of credit outstanding under the SN UnSub Credit Agreement.

~~Semi-annual redeterminations~~ Additionally, as of March 31, 2019 SN UnSub was in compliance with the ~~borrowing base are generally scheduled to occur in April and October of each year. On November 6, 2017, the borrowing base~~covenants of the SN UnSub Credit Agreement.

SR Credit Agreement

In 2017, we acquired SR Acquisition I, LLC (“SRAI”). On November 16, 2018, SRAI’s credit facility was amended and restated to convert the outstanding revolving loan to a term loan and extend the maturity date to October 31, 2022 (the “SR Credit Agreement”). As of March 31, 2019, there was approximately $23.2 million outstanding under the SR Credit Agreement, and SRAI was ~~reaffirmed at $330 million~~ in ~~conjunction~~compliance with the fall redetermination. The next regularly scheduled borrowing base redetermination is expected in the second quarter 2018. In addition, the borrowing base is subject to interim redetermination at the request of SN UnSub or the lenders based on, among other things, the lenders’ evaluation of SN UnSub’s and its subsidiaries’ oil and natural gas reserves. The borrowing base is also subject to reduction by 25%financial covenants of the amount of certain junior debt issuances other than the first $200 million of such debt and by reductions as a result of hedge terminations and asset dispositions that exceed 5% of the then-effective borrowing base, in addition to other customary adjustments.SR Credit Agreement.

The obligations under the SN UnSub Credit Agreement are guaranteed by all of SN UnSub’s existing and future subsidiaries and secured by a first priority lien on substantially all of SN UnSub’s assets and the assets of SN UnSub’s existing and future subsidiaries, including a first priority lien on all ownership interests in existing and future subsidiaries as well as a pledge of equity interests in SN UnSub held by SN EF UnSub Holdings, LLC (“SN UnSub

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Holdings”) and SN EF UnSub GP, LLC, the general partner of SN UnSub (the “SN UnSub General Partner”), in each case, subject to customary exceptions; provided, however, that the guarantee and first priority lien requirements do not extend to existing subsidiaries of SN UnSub designated as “unrestricted subsidiaries.” As of March 31, 2018, SN UnSub had no subsidiaries.

At SN UnSub’s election, borrowings under the SN UnSub Credit Agreement may be made on an ABR or a Eurodollar rate basis, plus an applicable margin. The applicable margin varies from 1.75% to 2.75% for ABR borrowings and from 2.75% to 3.75% for Eurodollar borrowings, depending on the utilization of the borrowing base. In addition, SN UnSub is also required to pay a commitment fee on the amount of any unused commitments at a rate of 0.50% per annum. Interest on ABR borrowings and the commitment fee are generally payable quarterly. Interest on the Eurodollar borrowings are generally payable at the applicable maturity date.

The SN UnSub Credit Agreement contains various affirmative and negative covenants and events of default that limit SN UnSub’s ability to, among other things, incur indebtedness, make restricted payments, grant liens, consolidate or merge, dispose of certain assets, make certain investments, engage in transactions with affiliates, enter into and maintain hedge transactions and make certain acquisitions.

The SN UnSub Credit Agreement also provides for an event of default upon a change of control and cross default between the SN UnSub Credit Agreement and other indebtedness of SN UnSub in an aggregate principal amount exceeding $25 million. Additionally, the SN UnSub Credit Agreement contains “separateness” covenants that require SN UnSub to comply with certain corporate formalities and transact with affiliates on an arms’ length basis and to indicate in the consolidated financial statements that SN UnSub and SN UnSub General Partner are separate entities apart from their respective security holders and affiliates and the assets and credit of SN UnSub and SN UnSub General Partner are not available to satisfy the debts and other obligations of such security holders and affiliates or any other person or entity. Furthermore, the SN UnSub Credit Agreement contains financial covenants that require SN UnSub to satisfy certain specified financial ratios, including (i) a current assets to current liabilities ratio of at least 1.0 to 1.0 as of the last day of each fiscal quarter and (ii) a net debt to consolidated EBITDA ratio of not greater than 4.0 to 1.0 for each test period, in each case commencing with the fiscal quarter ending June 30, 2017. As of March 31, 2018, the Company was in compliance with the covenants of the SN UnSub Credit Agreement.

From time to time, the agents, arrangers, book runners and lenders under the SN UnSub Credit Agreement and their affiliates have provided, and may provide in the future, investment banking, commercial lending, hedging and financial advisory services to SN UnSub and its affiliates in the ordinary course of business, for which they have received, or may in the future receive, customary fees and commissions for these transactions.

~~SR Credit Agreement~~

As of March 31, 2018, we had approximately $24 million in additional past due borrowings under an existing credit facility of an unrestricted subsidiary acquired as part of the SR Settlement (as defined in Note 12, “Related Party Transactions”) (the “SR Credit Agreement”), which debt is Non-Recourse to the Company and to the obligors on the SN UnSub Credit Agreement and the Non-Recourse Subsidiary Term Loan. Although the original maturity date of the SR Credit Agreement was August 7, 2018, on April 18, 2017, prior to the Company’s acquisition of Sanchez Resources, LLC (“Sanchez Resources”), the administrative agent and the lenders thereunder accelerated the obligations due under the SR Credit Agreement as a result of various defaults thereunder. If we do not repay the approximately $24 million in borrowings due under the SR Credit Agreement or successfully renegotiate the terms of such facility, then the administrative agent or the lenders under that facility could proceed against the collateral securing that debt, consisting of substantially all of Sanchez Resources’ assets (approximately 14,000 net acres). See Note 12, “Related Party Transactions.”

Senior Notes

7.75% Senior Notes Due 2021

On June 13, 2013, wethe Company completed a private offering of $400 million in aggregate principal amount of the 7.75% senior notes that will mature on June 15, 2021 (the “Original 7.75% Notes”). Interest on the notes is payable on June 15 and December 15 of each year. We received net proceeds from this offering of approximately $388 million, after deducting initial purchasers’ discounts and offering expenses, which we used to repay our then-outstanding

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indebtedness. The Original 7.75% Notes are senior unsecured obligations and are guaranteed on a joint and several senior unsecured basis by, with certain exceptions, substantially all of our existing and future subsidiaries.

On September 18, 2013, we issued an additional $200 million in aggregate principal amount of our 7.75% senior notes due 2021 (the “Additional 7.75% Notes” and, together with the Original 7.75% Notes, the “7.75% Notes”) in a private offering at an issue price of 96.5% of the principal amount of the Additional 7.75% Notes. We received net proceeds of $188.8 million (after deducting the initial purchasers’ discounts and offering expenses of $4.2 million) from the sale of the Additional 7.75% Notes. The Company also received cash for accrued interest from June 13, 2013 through the date of issuance of $4.1 million, for total net proceeds of $192.9 million from the sale of the Additional 7.75% Notes. The Additional 7.75% Notes were issued under the same indenture as the Original 7.75% Notes, and are, therefore, treated as a single class of securities under the indenture. We used the net proceeds from the offering to partially fund our acquisition of contiguous acreage in McMullen County, Texas with 13 gross producing wells completed in October 2013, a portion of the 2013 and 2014 capital budgets and for general corporate purposes.

The 7.75% Notes are senior unsecured obligations and rank equally in right of payment with all of our existing and future senior unsecured indebtedness. The 7.75% Notes rank senior in right of payment to our future subordinated indebtedness. The 7.75% Notes are effectively junior in right of payment to all of our existing and future secured debt (including under the Credit Agreement) to the extent of the value of the assets securing such debt. The 7.75% Notes are fully and unconditionally guaranteed (except for customary release provisions) on a joint and several senior unsecured basis by the subsidiary guarantors party to the indenture governing the 7.75% Notes. To the extent set forth in the indenture governing the 7.75% Notes, certain of our subsidiaries will be required to fully and unconditionally guarantee the 7.75% Notes on a joint and several senior unsecured basis in the future.

The indenture governing the 7.75% Notes, among other things, restricts our ability and our restricted subsidiaries’ ability to: (i) incur, assume, or guarantee additional indebtedness or issue certain types of equity securities; (ii) pay distributions on, purchase or redeem shares or purchase or redeem subordinated debt; (iii) make certain investments; (iv) enter into certain transactions with affiliates; (v) create or incur liens on their assets; (vi) sell assets; (vii) consolidate, merge or transfer all or substantially all of their assets; (viii) restrict distributions or other payments from the Company’s restricted subsidiaries; and (ix) designate subsidiaries as unrestricted subsidiaries.

We have the option to redeem all or a portion of the 7.75% Notes at any time on or after June 15, 2017 at the applicable redemption prices specified in the indenture plus accrued and unpaid interest. In addition, we may be required to repurchase the 7.75% Notes upon a change of control or if we sell certain of our assets.

On July 18, 2014, we completed an exchange offer of $600 million aggregate principal amount of the 7.75% Notes that had been registered under the Securities Act of 1933, as amended (the “Securities Act”), for an equal amount of the 7.75% Notes that had not been registered under the Securities Act.

6.125% Senior Notes Due 2023

On June 27, 2014, the Company completed a private offering of $850 million in aggregate principal amount of the 6.125% senior notes ~~due~~that will mature on January 15, 2023 (the “Original 6.125% Notes”). Interest on the notes is payable on July 15 and January 15 of each year. The Company received net proceeds from this offering of approximately $829 million, after deducting initial purchasers’ discounts and estimated offering expenses, which the Company used to repay all of the $100 million in borrowings outstanding under its previous credit facility and to finance a portion of the purchase price of ~~our acquisition of 106,000 net contiguous acres in Dimmit, LaSalle and Webb Counties, Texas (the “~~Catarina Acquisition”). We used the remaining proceeds from the offering to fund a portion of the remaining 2014 capital budget and for general corporate purposes. The Original 6.125% Notes are the senior unsecured obligations of the Company and are guaranteed on a joint and several senior unsecured basis by, with certain exceptions, substantially all of the Company’s existing and future subsidiaries.

On September 12, 2014, we issued an additional $300 million in aggregate principal amount of our 6.125% senior notes due 2023 (the “Additional 6.125% Notes” and, together with the Original 6.125% Notes, the “6.125% Notes” and, together with the 7.75% Notes and the 7.25% Senior Secured Notes, the “Senior Notes”) in a private offering at an issue price of 100.75% of the principal amount of the Additional 6.125% Notes. We received net proceeds of $295.9 million, after deducting the initial purchasers’ discounts, adding premiums to face value of $2.3 million and deducting estimated offering expenses of $6.4 million. The Company also received cash for accrued interest from June

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27, 2014 through the date of the issuance of $3.8 million, for total net proceeds of $299.7 million from the sale of the Additional 6.125% Notes. The Additional 6.125% Notes were issued under the same indenture as the Original 6.125% Notes, and are, therefore, treated as a single class of securities under the indenture. We used a portion of the net proceeds from the offering to fund a portion of the 2014 capital budget and used the remainder of the net proceeds to fund a portion of the 2015 capital budget, and for general corporate purposes.

The 6.125% Notes are senior unsecured obligations and rank equally in right of payment with all of our existing and future senior unsecured indebtedness. The 6.125% Notes rank senior in right of payment to the Company’s future subordinated indebtedness. The 6.125% Notes are effectively junior in right of payment to all of the Company’s existing and future secured debt (including under the Credit Agreement) to the extent of the value of the assets securing such debt. The 6.125% Notes are fully and unconditionally guaranteed (except for customary release provisions) on a joint and several senior unsecured basis by the subsidiary guarantors party to the indenture governing the 6.125% Notes. To the extent set forth in the indenture governing the 6.125% Notes, certain of our subsidiaries will be required to fully and unconditionally guarantee the 6.125% Notes on a joint and several senior unsecured basis in the future.

The indenture governing the 6.125% Notes, among other things, restricts our ability and our restricted subsidiaries’ ability to: (i) incur, assume or guarantee additional indebtedness or issue certain types of equity securities; (ii) pay distributions on, purchase or redeem shares or purchase or redeem subordinated debt; (iii) make certain investments; (iv) enter into certain transactions with affiliates; (v) create or incur liens on their assets; (vi) sell assets; (vii) consolidate, merge or transfer all or substantially all of their assets; (viii) restrict distributions or other payments from the Company’s restricted subsidiaries; and (ix) designate subsidiaries as unrestricted subsidiaries.

The Company has the option to redeem all or a portion of the 6.125% Notes, at any time on or after July 15, 2018 at the applicable redemption prices specified in the indenture plus accrued and unpaid interest. The Company may also redeem the 6.125% Notes, in whole or in part, at a redemption price equal to 100% of their principal amount plus a make whole premium, together with accrued and unpaid interest and additional interest, if any, to the redemption date, at any time prior to July 15, 2018. The Company may also be required to repurchase the 6.125% Notes upon a change of control or if we sell certain Company assets.

On February 27, 2015, we completed an exchange offer of $1.15 billion aggregate principal amount of the 6.125% Notes that had been registered under the Securities Act for an equal amount of the 6.125% Notes that had not been registered under the Securities Act.

Pursuant to tripartite agreements by and among the Company, U.S. Bank National Association (“U.S. Bank”) and Delaware Trust Company (“Delaware Trust”), effective May 20, 2016, U.S. Bank resigned as the Trustee, Notes Custodian, Registrar and Paying Agent (“Trustee”) under the indentures of the 6.125% Notes and the 7.75% Notes and Delaware Trust was appointed as successor Trustee. No other changes to the indentures for the 6.125% Notes or the 7.75% Notes were made at the time of the change in Trustee.

7.25% Senior Secured First Lien Notes due 2023

On February 14, 2018, the Company ~~closed its~~completed a private offering to eligible purchasers of $500 million in aggregate principal amount of 7.25% senior secured first lien notes due 2023 (the “7.25% Senior Secured Notes”)~~. The 7.25% Senior Secured Notes were issued pursuant to~~ at an ~~indenture, dated as~~issue price of ~~February 14, 2018 (the “Indenture”), among the Company, the guarantors party thereto, Delaware Trust Company, as trustee, and Royal Bank of Canada, as collateral trustee.~~

~~The 7.25% Senior Secured Notes are guaranteed on a full, joint and several and senior secured basis by each~~99.0% of the Company’s existing domestic restricted subsidiaries and will be guaranteed by any future domestic restricted subsidiary, in each case, if and so long as such entity guarantees (or is an obligor with respect to) indebtedness (other than the 7.25% Senior Secured Notes) in excess of $10 million or under the Credit Agreement. The 7.25% Senior Secured Notes are secured by first-priority liens on substantially all of the Company’s and any subsidiary guarantor’s assets. The 7.25% Senior Secured Notes and the guarantees are, pursuant to a collateral trust agreement (the “CTA”), secured by first-priority liens on a “second-out” collateral proceeds payment priority basis and thus are effectively junior to any “first-out” obligations, including obligations under the Credit Agreement and obligations under any hedging arrangements and cash management arrangements permitted to be secured on a “first-out” basis under the Credit Agreement, to the extent of the value of the collateral securing such “first-out” obligations. The 7.25% Senior Secured

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Notes and the guarantees rank effectively senior to all of the Company’s existing and future senior unsecured indebtedness to the extent of the value of the collateral securing the 7.25% Senior Secured Notes and the guarantees.

The 7.25% Senior Secured Notes will mature on February 15, 2023, unless on October 10, 2022 either (i) some or all of the Company’s 6.125% Notes are still outstanding and have not been defeased or (ii) the Company or any of its restricted subsidiaries have any outstanding indebtedness that was used to purchase, repurchase, redeem, defease or otherwise acquire or retire for value the Company’s 6.125% Notes, and such indebtedness under this clause (ii) has a final maturity date that is earlier than May 17, 2023, in which case of either clause (i) or clause (ii), the 7.25% Senior Secured Notes will mature on October 14, 2022.

The 7.25% Senior Secured Notes are redeemable, in whole or in part, on or after February 15, 2020 at the redemption prices described in the Indenture, together with accrued and unpaid interest. At any time prior to February 15, 2020, the Company may redeem the 7.25% Senior Secured Notes, in whole or in part, at a redemption price equal to 100% of their principal amount plus a make whole premium, together with accrued and unpaid interest to the redemption date. In addition, the Company may redeem up to 35% of the 7.25% Senior Secured Notes prior to February 15, 2020 in an amount not greater than the net cash proceeds from one or more equity offerings at a redemption price equal to 107.25% of their principal amount, together with accrued and unpaid interest to the redemption date. If the Company sells certain of its assets or experiences specific kinds of changes of control, in certain circumstances it must offer to repurchase the 7.25% Senior Secured Notes.amount.

The Indenture restricts the Company’s ability, and the ability of the Company’s restricted subsidiaries, to: (i) incur additional indebtedness or issue preferred stock; (ii) pay dividends or make other distributions; (iii) make other restricted payments and investments; (iv) create liens; (v) incur restrictions on the ability of restricted subsidiaries to pay dividends or make certain other payments; (vi) sell assets, including capital stock of restricted subsidiaries; (vii) merge or consolidate with other entities; and (viii) enter into transactions with affiliates.

The 7.25% Senior Secured Notes and the guarantees are secured on a first-priority basis, subject in priority only to permitted collateral liens and to the prior rights of the Credit Agreement and other “first-out” obligations under the CTA, in the following assets of the Company and the subsidiary guarantors (the “Shared Collateral”): (i) substantially all of the Company’s and its restricted subsidiaries’ oil and natural gas properties with proved reserves, (ii) 100% of the equity interest of the Company’s restricted subsidiaries and any of their future direct material restricted subsidiaries; and (iii) substantially all of the Company’s and any guarantor’s other material personal property, but in each case excluding, among other things, deposit accounts, oil and natural gas properties with no proved reserves, equity interests in SN UnSub and other existing and future subsidiaries designated as “unrestricted subsidiaries.”

Note 8. Derivative Instruments

To reduce the impact of fluctuations in the price of oil, natural gas and NGLs on the Company’s business and results of operations, and to protect the economics of property acquisitions at the time of execution, the Company periodically enters into derivative contracts with respect to a portion of its projected oil and natural gas production through various transactions that fix or modify the future prices to be realized. The derivative contracts may include fixed-for-floating price swaps (whereby, on the settlement date, the Company will receive or pay an amount based on the difference between a pre-determined fixed price and a variable market price for a notional quantity of production), put options (whereby the Company pays a cash premium in order to establish a fixed floor price for a notional quantity of production and, on the settlement date, receives the excess, if any, of the fixed price floor over a variable market price), and costless collars (whereby, on the settlement date, the Company receives the excess, if any, of a variable market price over a fixed floor price up to a fixed ceiling price for a notional quantity of production). In addition, the Company periodically enters into call swaptions as a way to achieve greater downside price protection than offered under prevailing fixed-for-floating price swaps by agreeing to expand the notional quantity hedged or extend the notional quantity settlement period under a fixed-for floating price swap at the counterparty’s election on a designated date.

~~These hedging~~Hedging activities, which are governed by the terms of our Credit Agreement, ~~(as defined in Note 7, “Debt”),~~ the SN UnSub Credit Agreement and the terms of SN UnSub’s organizational documents, as applicable, are intended to support oil and natural gas prices at targeted levels and manage exposure to oil and natural gas price fluctuations. It is our policy to enter into derivative contracts only with counterparties that are creditworthy and competitive market participants. Any derivatives that are with ~~(x)~~(a) lenders, or affiliates of lenders, to the SN UnSub Credit Agreement, or ~~(y)~~(b) counterparties designated as secured with and under the Credit Agreement are, in each case,

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collateralized by the assets securing the applicable facility, and, therefore, do not currently require the posting of cash collateral. Any derivatives that are with (x) non-lender counterparties, as designated under the SN UnSub Credit Agreement, or (y) counterparties that are not designated as secured under the Credit Agreement are, in each case, unsecured and do not require the posting of cash or other collateral. As of March 31, 2019, all of our derivative contracts were with lenders, affiliates of lenders or other secured counterparties. It is never the Company’s intention to enter into derivative contracts for speculative trading purposes.

All of our derivatives are accounted for as mark-to-market activities. Under ASC 815, “Derivatives and Hedging,” these 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. The Company nets derivative assets and liabilities by commodity for counterparties where a legal right to such offset exists. Changes in the derivatives’ fair values are recognized in current earnings since the Company has elected not to designate its current derivative contracts as cash flow hedges for accounting purposes.

The following table presents derivative positions for the periods indicated as of March 31, ~~2018:~~2019:


	April 1 - December 31, 2018		2019		2020		April 1 - December 31, 2019		2020		2021
Oil positions:
Fixed-for-floating price swaps (NYMEX WTI):
Fixed price swaps (NYMEX WTI):
Hedged volume (Bbls)		6,070,024		3,149,000		599,400		2,339,000		1,055,560		216,000
Average price ($/Bbl)	$	52.38	$	51.91	$	54.31	$	51.89	$	55.36	$	57.10

Call swaptions (NYMEX WTI):
Option volume (Bbls)		—		730,000		—
Average price ($/Bbl)	$	—	$	55.00	$	—

Natural gas positions:
Fixed-for-floating price swaps (NYMEX Henry Hub):
Fixed price swaps (NYMEX Henry Hub):
Hedged volume (MMBtu)		52,489,900		17,644,000		3,862,500		13,105,000		6,893,150		1,440,000
Average price ($/MMBtu)	$	3.03	$	2.90	$	2.74	$	2.90	$	2.67	$	2.86

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The following table sets forth a reconciliation of the changes in fair value of the Company’s commodity derivatives for the three months ended March 31, ~~2018~~2019 and the year ended December 31, ~~2017~~2018 (in thousands):

Three Months Ended

Year Ended

March 31,

December 31,

2018

2017
Beginning fair value of commodity derivatives

$
(54,255)

$
(35,014)
Net losses on crude oil derivatives

(41,727)

(48,966)
Net gains (losses) on natural gas derivatives

(2,327)

42,764
Net settlements paid (received) on derivative contracts:

Crude oil

20,977

(11,807)
Natural gas

(1,326)

(1,232)
Ending fair value of commodity derivatives

$
(78,658)

$
(54,255)


	Three Months Ended		Year Ended
	March 31,		December 31,
	2019		2018
Fair value of commodity derivatives, beginning of period	$	21,194	$	(54,255)
Net losses on oil derivatives		(47,472)		(9,878)
Net losses on natural gas derivatives		(950)		(17,897)
Net settlements paid on commodity derivative contracts:
Oil		2,363		100,120
Natural gas		1,145		3,104
Fair value of commodity derivatives, end of period	$	(23,720)	$	21,194

Embedded Derivatives: In 2017, the Company entered into certain contracts for the purchase of sand ~~coiled tubing~~ and fractionation ~~stimulation~~ services that contain provisions that ~~are required to~~must be bifurcated from the contract and valued as derivatives. In the fourth quarter 2018, the Company amended certain of these contracts, removing the respective embedded derivative components, and as of March 31, 2019, all remaining embedded derivative contracts expired or had been terminated. The embedded derivatives ~~are~~were historically valued using a Monte Carlo simulation model which utilizes observable inputs, including the NYMEX WTI oil price and NYMEX Henry Hub natural gas price at various points in time. The Company ~~has~~ marked these derivatives to market ~~as of March 31, 2018~~ and, ~~2017. The Company incurred an approximate $0.1 million gain and a $0.7 million gain~~ as a result, recorded gains of approximately $0.3 million and $0.1 million for the three months ended March 31, ~~2018~~2019 and ~~2017,~~2018, respectively. Any gains or losses related to embedded derivatives are recorded as a component of other income (expense) in the ~~condensed~~ consolidated statement of operations.

Earnout Derivative: ~~As part of the Carnero Gathering Disposition (defined in Note 12, “Related Party Transactions”), we~~We are entitled to receive earnout payments from SNMP based on natural gas delivered above a threshold volume and a tariff at ~~Carnero Gathering’s (defined in Note 9, “Investments”)~~certain pipeline delivery points. These payments were deemed to be a ~~derivative; the~~derivative. The resulting earnout derivative was valued through the use of a Monte Carlo simulation

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model which utilized observable inputs, such as the earnout price and volume commitment, as well as unobservable inputs related to the weighted probabilities of various throughput scenarios.

The following table sets forth a reconciliation of the changes in fair value of the Company’s embedded and earnout derivatives for the three months ended March 31, 2019 and the year ended December 31, 2018, respectively (in thousands):

Three Months Ended

March 31,

2018

2017
Beginning fair value of other derivatives

$
(1,551)

$
—
Gain on embedded derivatives

63

685
Initial fair value of earnout derivatives

6,401

—
Gain on earnout derivatives

273

—
Ending fair value of other derivatives

$
5,186

$
685


	Three Months Ended		Year Ended
	March 31,		December 31,
	2019		2018
Fair value of other derivatives, beginning of period	$	5,550	$	(1,551)
Gain on embedded derivatives		308		1,243
Initial fair value of earnout derivative		—		6,401
Loss on earnout derivatives		(32)		(543)
Fair value of other derivatives, end of period	$	5,826	$	5,550

Balance Sheet Presentation

The Company nets derivative assets and liabilities by commodity for counterparties where legal right to such ~~offset~~netting exists. Therefore, the Company’s derivatives are presented on a net basis as “Fair value of derivative instruments” on the condensed consolidated balance sheets. The following information summarizes the gross fair values ~~of derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Company’s condensed consolidated balance sheets (in thousands):~~

March 31, 2018

Gross Amounts

Net Amounts

Gross Amount

Offset in the

Presented in the

of Recognized

Consolidated

Consolidated


Assets and Liabilities

Balance Sheets

Balance Sheets
Offsetting Derivative Assets:

Current asset

$
12,135

$
(116)

$
12,019
Long-term asset

9,134

(356)

8,778
Total asset

$
21,269

$
(472)

$
20,797
Offsetting Derivative Liabilities:

Current liability

$
74,113

$
(116)

$
73,997
Long-term liability

20,628

(356)

20,272
Total liability

$
94,741

$
(472)

$
94,269

December 31, 2017

Gross Amounts

Net Amounts

Gross Amount

Offset in the

Presented in the

of Recognized

Consolidated

Consolidated


Assets

Balance Sheets

Balance Sheets
Offsetting Derivative Assets:

Current asset

$
16,510

$
(80)

$
16,430
Long-term asset

2,100

(672)

1,428
Total asset

$
18,610

$
(752)

$
17,858
Offsetting Derivative Liabilities:

Current liability

$
56,270

$
(80)

$
56,190
Long-term liability

18,146

(672)

17,474
Total liability

$
74,416

$
(752)

$
73,664

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of derivative instruments, presenting the impact of offsetting derivative assets and liabilities on the Company’s consolidated balance sheets (in thousands):


	March 31, 2019
			Gross Amounts		Net Amounts
	Gross Amount		Offset in the		Presented in the
	of Recognized		Consolidated		Consolidated
	Assets and Liabilities		Balance Sheets		Balance Sheets
Offsetting Derivative Assets:
Current asset	$	1,778	$	(406)	$	1,372
Long term asset		6,724		(57)		6,667
Total asset	$	8,502	$	(463)	$	8,039
Offsetting Derivative Liabilities:
Current liability	$	23,249	$	(406)	$	22,843
Long term liability		3,147		(57)		3,090
Total liability	$	26,396	$	(463)	$	25,933


	December 31, 2018
			Gross Amounts		Net Amounts
	Gross Amount		Offset in the		Presented in the
	of Recognized		Consolidated		Consolidated
	Assets and Liabilities		Balance Sheets		Balance Sheets
Offsetting Derivative Assets:
Current asset	$	16,302	$	(588)	$	15,714
Long term asset		12,178		(76)		12,102
Total asset	$	28,480	$	(664)	$	27,816
Offsetting Derivative Liabilities:
Current liability	$	1,294	$	(588)	$	706
Long term liability		442		(76)		366
Total liability	$	1,736	$	(664)	$	1,072

Note 9. Investments

~~On June 15, 2017,~~A subsidiary of the Company ~~received~~owns 1,500,000 shares of ~~Lonestar’s Series B Convertible Preferred Stock as part of the consideration for the Marquis Disposition. The Series B Convertible Preferred Stock converted into Lonestar~~ Class A Common Stock ~~on November 3, 2017.~~of Lonestar Resources US Inc. (“Lonestar”). As of March 31, ~~2018,~~2019, this ownership represents approximately 6.1% of Lonestar’s outstanding shares of common stock. The Company accounts for the investment in Lonestar ~~is accounted for by the Company~~ as ~~investments~~an investment in equity securities measured at fair value in the condensed consolidated balance sheets at the end of each reporting period. The Company recorded gains related to the investment in Lonestar for the three months ended March 31, 2019 and 2018 of approximately $0.5 ~~million.~~million and $0.5 million, respectively. Any gains or losses related to the investment in Lonestar are recorded as a component of other income (expense) in the condensed consolidated statement of operations.

~~On June 14, 2017, SN Catarina, LLC (“SN Catarina”), a wholly owned~~A subsidiary of the Company completed the sale of its 10% undivided interest in the Silver Oak II Gas Processing Facility in Bee County, Texas (the “SOII Facility”) to a subsidiary of Targa Resources Corp. (“Targa”) with an effective date of June 1, 2017 for $12.5 million of cash (the “SOII Disposition”). On October 2, 2015, the Company, through SN Catarina, purchased from a subsidiary of Targa, a 10% undivided interest in the SOII Facility for a purchase price of $12.5 million. Targa owned the remaining undivided 90% interest in the SOII Facility, which is operated by Targa. Concurrently with the execution of the purchase and sale agreement for the SOII Facility, the Company entered into a firm gas processing agreement, whereby Targa began processing a firm quantity of 125,000 Mcf per day on March 1, 2016 until the in-service date of Carnero Gathering LLC’s (“Carnero Gathering”) Raptor Gas Processing Facility. The Company accounted for its interest in the SOII Facility as an equity method investment as Targa is the operator and majority interest owner of the SOII Facility. No gain or loss was recorded on the SOII Disposition. The Company recorded earnings of approximately $435 thousand from its equity interest in the SOII Facility for the three months ended March 31, 2017.

~~On March 1, 2017 (the “Effective Date”), pursuant to the Amended and Restated Limited Liability Company Agreement (the “LLC Agreement”)~~owns 100 Class A Units of Gavilan Resources Holdco, LLC (“GRHL” or “Gavilan Holdco”), GRHL authorized and issued a total of 100 Class A Units to SN Comanche Manager, LLC, a wholly owned unrestricted subsidiary of the Company (“SN Comanche Manager” or “Manager”). GRHL is the parent of Gavilan. SN Comanche Manager, as holder of the Class A Units, does not have voting rights with respect to GRHL except regarding amendments to the LLC Agreement that adversely affect the holders of Class A Units, approval of affiliate transactions, or as required by law. Twenty percentTranches representing 20% of the Class A Units vest on each of the first five anniversaries ~~of the Effective Date.~~from March 1, 2017. The Class A Units are entitled to distributions from Available Cash, as defined in and subject to the provisions of the ~~LLC Agreement.~~GRHL amended and restated limited liability company agreement. The Company accounts for the investment in GRHL as a cost method investment. As of March 31, ~~2018,~~2019, the carrying value of the investment in GRHL was $7.3 million, based on the estimated fair value as of March 1, 2017. In general, the fair value of a cost method investment is not evaluated unless circumstances are present that may have an adverse effect on the fair value. The Company has not identified any such circumstances as of March 31, 2018.million. The Company did not record any earnings or distributions from its ownership of the Class A Units for the period from ~~March~~January 1, ~~2017~~2018 through March 31, ~~2018.~~2019.

~~On November 22, 2016, a~~A subsidiary of the Company ~~purchased~~owns 2,272,727 ~~of SNMP’s~~ common units ~~for $25.0 million in a private placement.~~of SNMP. As of March 31, ~~2018,~~2019, this ownership represents approximately ~~15.0%~~12.5% of SNMP’s outstanding common units. ~~Rather than accounting for the investment under the equity method, the~~The Company elected the fair value option to account for its interest in ~~SNMP. The Company~~SNMP and records the equity investment ~~in SNMP~~ at fair value at the end of each reporting period. ~~The~~For the three months ended March 31, 2019 and 2018, the Company recorded ~~losses~~a gain of $1.0 million and a loss of $1.7

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million, respectively, related to the investment in ~~SNMP~~SNMP. In addition, for the three months ended March 31, 2019 and 2018, ~~of approximately $1.7 million. In addition,~~ the Company recorded dividend income of approximately $0.3 million and $1.0 million, respectively, from ~~the~~ quarterly ~~dividend~~distributions on the ~~investment in SNMP.~~SNMP common units. Any gains or losses and dividend income related to the investment in SNMP are recorded as a component of other income (expense) in the condensed consolidated statement of operations.

Note 10. Fair Value of Financial Instruments

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

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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. Substantially all of these inputs are observable in the marketplace throughout the term of the 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).

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.

Fair Value on a Recurring Basis

The following tables set forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, ~~2018~~2019 and December 31, ~~2017~~2018 (in thousands):


	As of March 31, 2018								As of March 31, 2019
	Active Market								Active Market
	for Identical		Observable		Unobservable		Total		for Identical		Observable		Unobservable		Total
	Assets		Inputs		Inputs		Carrying		Assets		Inputs		Inputs		Carrying
	(Level 1)		(Level 2)		(Level 3)		Value		(Level 1)		(Level 2)		(Level 3)		Value
Cash and cash equivalents:
Cash equivalents	$	424,397	$	—	$	—	$	424,397	$	160,965	$	—	$	—	$	160,965
Equity investment:
Equity investments:
Investment in SNMP		23,523		—		—		23,523		4,886		—		—		4,886
Investment in Lonestar		6,510		—		—		6,510		6,015		—		—		6,015
Oil derivative instruments:
Swaps		—		(85,497)		—		(85,497)		—		(24,501)		—		(24,501)
Call Swaptions		—		(4,888)		—		(4,888)
Gas derivative instruments:
Swaps		—		11,727		—		11,727		—		781		—		781
Other:
Embedded derivative instruments		—		(1,488)		—		(1,488)
Earnout derivative asset		—		—		6,674		6,674		—		—		5,826		5,826
Total	$	454,430	$	(80,146)	$	6,674	$	380,958	$	171,866	$	(23,720)	$	5,826	$	153,972

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	As of December 31, 2017								As of December 31, 2018
	Active Market								Active Market
	for Identical		Observable		Unobservable		Total		for Identical		Observable		Unobservable		Total
	Assets		Inputs		Inputs		Carrying		Assets		Inputs		Inputs		Carrying
	(Level 1)		(Level 2)		(Level 3)		Value		(Level 1)		(Level 2)		(Level 3)		Value
Cash and cash equivalents:
Cash equivalents	$	49,071	$	—	$	—	$	49,071	$	131,187	$	—	$	—	$	131,187
Equity investment:
Equity investments:
Investment in SNMP		25,227		—		—		25,227		3,909		—		—		3,909
Investment in Lonestar		5,955		—		—		5,955		5,475		—		—		5,475
Oil derivative instruments:
Swaps		—		(66,204)		—		(66,204)		—		20,608		—		20,608
Call Swaptions		—		(3,431)		—		(3,431)
Gas derivative instruments:
Swaps		—		15,380		—		15,380		—		586		—		586
Embedded derivative instruments:
Other:
Embedded derivative instruments		—		(1,551)		—		(1,551)		—		(308)		—		(308)
Earnout derivative asset										—		—		5,858		5,858
Total	$	80,253	$	(55,806)	$	—	$	24,447	$	140,571	$	20,886	$	5,858	$	167,315

(1)

Level 1 measurements are fair value measurements which use quoted market prices (unadjusted) in active markets for identical assets or liabilities. We use Level 1 inputs when available, as Level 1 inputs generally provide the most reliable evidence of fair value.

(2)

Level 2 measurements are fair value measurements which use inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly.

(3)

Level 3 measurements are fair value measurements which use unobservable inputs and require management to make certain assumptions in the determination of value.

Financial Instruments: The Level 1 instruments presented in the tables above consist of money market funds and time deposits included in cash and cash equivalents on the Company’s condensed consolidated balance sheets at March 31, ~~2018~~2019 and December 31, ~~2017.~~2018. The Company’s money market funds and time deposits represent cash equivalents ~~backed by the assets of high‑quality~~held with banks and financial institutions. The Company identified the money market funds and time deposits as Level 1 instruments, ~~due to the fact that these instruments~~as money market funds have daily liquidity, there are active markets for the underlying investments and quoted prices for the underlying investments can be ~~obtained~~obtained. and there are active markets for the underlying investments. In addition, the Level 1 instruments include the Company’s equity ~~investment in common units of SNMP as further discussed in Note 9, “Investments.” The investment~~investments in SNMP is being accounted for under the fair value option, included in investments on the Company’s balance sheet as of March 31, 2018. The Company identified the common units in SNMP as a Level 1 instruments due to the fact that SNMP is aand Lonestar which are publicly traded company on the NYSE American with daily quoted prices that can be easily obtained. The Level 1 instruments also include the Company’s investment in the common shares of Lonestar as further discussed in Note 9, “Investments.” The investment in the Lonestar common shares is being accounted for at fair value and included in investments on the Company’s balance sheet as of March 31, 2018. The Company identified the Lonestar common shares as Level 1 instruments due to the fact that Lonestar is a publicly traded company on the Nasdaq Global Market exchange, with daily quoted prices that can be readily obtained.companies.

The Company’s commodity derivative instruments consist of swaps ~~and call swaptions~~ as of March 31, ~~2018~~2019 and December 31, ~~2017~~2018 as shown in the table above. The fair values of the Company’s derivatives are based on third-party pricing models which utilize inputs that are either readily available in the public market, such as forward curves, or can be corroborated from active markets of broker ~~quotes. Swaps generally have observable inputs~~quotes, and ~~they~~therefore are classified as Level 2. Call Swaption derivatives have inputs which are observable, either directly or indirectly, using market data. As of March 31, 2018 and December 31, 2017, the Company believed that substantially all of the inputs required to calculate the fair value of swaps and call swaptions are observable in the marketplace throughout the term of these derivative instruments or supported by observable levels at which transactions are executed in the marketplace, and are, therefore, classified as Level 2. Derivative instruments are also subject to the risk that counterparties will be unable to meet their obligations. Such non-performance risk is considered in the valuation of the Company’s derivative instruments, but to date has not had a material impact on estimates of fair values. Significant changes in the quoted forward prices for commodities and changes in market volatility generally lead to corresponding changes in the fair value measurement of the Company’s derivative instruments.

There were no commodity derivative instruments classified as Level 3 as of March 31, ~~2018~~2019 or December 31, ~~2017.~~2018.

Embedded Derivatives: The Company consummated contracts for the purchase of sand, coiled tubing and fractionation stimulation services that contain provisions that are required to be bifurcated from the contract and valued as a derivative. The embedded derivatives are using a Monte Carlo model which utilizes observable inputs, ~~including the NYMEX WTI oil price and~~ ~~the NYMEX Henry Hub natural gas price at various points in time. As of March 31, 2018, the~~ ~~Company~~ believes that substantially all of the inputs required to calculate the embedded derivatives are observable in

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the marketplace throughout the term of these derivative instruments or supported by observable levels at which transactions are executed in the marketplace, and are, therefore, classified as Level 2 inputs. As

Table of ~~December 31, 2017, the~~ Company believed that substantially all of the inputs required to calculate the embedded derivatives were observable in the marketplace throughout the term of these derivative instruments or supported by observable levels at which transactions are executed in the marketplace, and were, therefore, classified as Level 2 inputs. ~~Changes in the inputs will impact the fair value measurement of the Company's embedded derivative contracts.~~Contents

Earnout Derivative: As part of the Carnero Gathering Disposition, we are entitled to receive earnout payments from SNMP based on natural gas delivered above a threshold volume and tariff at Carnero Gathering’s delivery points. These payments were deemed to be a ~~derivative; the resulting earnout~~ derivative ~~was valued through the use of a Monte Carlo simulation model~~ which ~~utilized~~utilize observable inputs such as the earnout price and volume commitment, as well as unobservable inputs related to the weighted probabilities of various throughput scenarios.

The following table sets forth a reconciliation of changes in the fair value of the Company’s earnout derivative instruments classified as Level 3 in the fair value hierarchy (in thousands):


					Three Months Ended		Year Ended
	March 31,				March 31,		December 31,
	2018		2017		2019		2018
Beginning balance	$	—	$	—	$	5,858	$	—
Initial fair value of earnout derivative		6,401		—		—		6,401
Gain on earnout derivative		273		—
Loss on earnout derivatives						(32)		(543)
Ending balance	$	6,674	$	—	$	5,826	$	5,858

Fair Value on a Non‑Recurring Basis

The Company follows the provisions of ASC 820-10 for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. Fair value measurements of assets acquired and liabilities assumed in business combinations are based on inputs that are not observable in the market and thus represent Level 3 inputs. The fair value of acquired properties is based on market and cost approaches. Our purchase price allocation for the Comanche Acquisition is presented in Note 4, “Acquisitions and Divestitures.” Liabilities assumed include asset retirement obligations existing at the date of acquisition. Asset retirement obligation estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions, the Company has designated these liabilities as Level 3. A reconciliation of the beginning and ending balances of the Company’s asset retirement obligations is presented in Note 11, “Asset Retirement Obligations.”

As previously stated, the Company follows the provisions of ASC 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 in the SR legal settlement are based on inputs that are not observable in the market and thus represent Level 3 inputs. The fair value of acquired properties is based on market and cost approaches. The allocation of fair value to the assets and liabilities assumed as part of the SR legal settlement is presented in Note 12, “Related Party Transactions.” Liabilities assumed include asset retirement obligations existing and short-term debt held by Sanchez Resources at the date of transfer. Asset retirement obligation estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions, the Company has designated these liabilities as Level 3. Additional discussion of the SR legal settlement can be found in Note 12, “Related Party Transactions.” A reconciliation of the beginning and ending balances of the Company’s asset retirement obligations is presented in Note 11, “Asset Retirement Obligations.”

In connection with the ~~exchange agreements entered into in February, May and August 2014~~voluntary conversions by ~~the Company with~~ certain holders of shares of the Company’s 4.875% Convertible Perpetual Preferred Stock, Series A (the “Series A Preferred Stock”) and 6.500% Convertible Perpetual Preferred Stock, ~~and~~ Series B (the “Series B Preferred ~~Stock,~~Stock”) into shares of the Company’s common stock in February and March 2019, the Company issued common stock according to the conversion rate ~~pursuant to each agreement~~established by the Certificates of Designations for the Series A Preferred Stock and ~~additional shares to induce the holders of the preferred stock to convert prior to the date the Company could mandate conversion. In addition, on November 20, 2015, a holder of our~~ Series B Preferred Stock, exercised its right to convert 4,500 shares of our Series B Preferred Stock, at the prescribed initial conversion rate of 2.337 shares of common stock per share of Series B Preferred Stock, in exchange for 10,517 shares of our common stock.as applicable. The fair value of the common stock issued is based on the price of the Company’s common stock on the date of issuance. There were no conversions of Series A Preferred Stock or Series B Preferred Stock into shares of the Company’s common stock during the three months ended March 31, ~~2018 and year ended December 31, 2017.~~2018. As there is an active market for the Company’s common stock, the Company has designated

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this fair value measurement as Level 1. ~~A detailed description of the Company’s common stock and preferred stock issuances and redemptions is presented in~~For further information, see Note 14, “Stockholders’ and Mezzanine Equity.”

The Company did not record a proved property impairment during the three months ended March 31, ~~2018 and 2017.~~2019 or 2018.

Fair Value of Other Financial Instruments

The carrying amounts of our oil and natural gas receivables, accounts payable and accrued liabilities approximate fair value due to their highly liquid nature. The registered 7.75% Notes are traded in an active market, and as such, are classified as Level 1 financial instruments. The estimated fair value of the 7.75% Notes was ~~$564~~$89.3 million as of March 31, ~~2018~~2019 and was calculated using quoted market prices based on trades of such debt as of that ~~date. The~~date, and the registered 6.125% Notes are traded in an active market, and as such, are classified as Level 1 financial instruments. The estimated fair value of the 6.125% Notes was ~~$841.7~~$166.8 million as of March 31, ~~2018~~2019 and was calculated using quoted market prices based on trades of such debt as of that date. The 7.25% Senior Secured Notes are classified as Level 1 financial instruments as they are traded in an active market under Rule 144A by institutional investors. The estimated fair value of the 7.25% Senior Secured Notes was ~~$504.1~~$402.5 million as of March 31, ~~2018.~~2019.

Note 11. Asset Retirement Obligations

The Company’s asset retirement obligations represent the present value of the estimated cash flows expected to be incurred to plug, abandon and remediate producing properties, excluding salvage values, at the end of their productive lives in accordance with applicable laws. Revisions in estimated liabilities during the period relate primarily to changes in estimates of asset retirement costs. Revisions in estimated liabilities can also include, but are not limited to, revisions of estimated inflation rates, changes in property lives, and the expected timing of settlement.

The changes in the asset retirement obligation for the three months ended March 31, ~~2018~~2019 and the year ended December 31, ~~2017~~2018 were as follows (in thousands):


	Three Months Ended		Year Ended		Three Months Ended		Year Ended
	March 31,		December 31,		March 31,		December 31,
	2018		2017		2019		2018
Abandonment liability, beginning of period	$	36,098	$	25,087	$	46,175	$	36,098
Liabilities incurred during period		332		4,968		—		1,965
Acquisitions		—		8,289
Divestitures		(158)		(3,538)		—		(158)
Revisions		—		(1,343)		—		5,077
Accretion expense		758		2,635		947		3,193
Abandonment liability, end of period	$	37,030	$	36,098	$	47,122	$	46,175

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Note 12. Related Party Transactions

~~SOG, headquartered in Houston, Texas, is a private full service oil~~Sanchez Oil and natural gas company engaged in the exploration and development of oil and natural gas primarily in the South Texas and onshore Gulf Coast areas on behalf of its affiliates, including the Company, pursuant to existing management service agreements. The Company refers to SOG and its affiliates (but excluding the Company) collectively as the “Sanchez Group.” Mr. Eduardo A. Sanchez and Ana Lee Sanchez Jacobs, immediate family members of the Executive Chairman of the Board, our Chief Executive Officer and an Executive Vice President of the Company, collectively with such individuals, either directly or indirectly, own 100% of the equity interests of SOG; these individuals, as well as Mr. Eduardo A. Sanchez and Ms. Ana Lee Sanchez Jacobs, are officers of SOG. In addition, Antonio R. Sanchez, Jr. is the sole member of the board of directors of SOG.Gas Corporation

The Company does not have any employees. On December 19, 2011 the Company entered into the Services Agreement with SOG pursuant to which specified employees of SOG provide certain services with respect to the Company’s business under the direction, supervision and control of SOG. Pursuant to this arrangement, SOG performs centralized corporate functions for the Company, such as general and administrative services, geological, geophysical and reserve engineering, lease and land administration, marketing, accounting, operational services, information

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technology services, compliance, insurance maintenance and management of outside professionals. The Company compensates SOG for the services at a price equal to SOG’s cost of providing such services, including all direct costs and indirect administrative and overhead costs (including the allocable portion of salary, bonus, incentive compensation and other amounts paid to persons that provide the services on SOG’s behalf) allocated in accordance with SOG’s regular and consistent accounting practices, including for any such costs arising from amounts paid directly by other members of the Sanchez Group on SOG’s behalf or borrowed by SOG from other members of the Sanchez Group, in each case, in connection with the performance by SOG of services on the Company’s behalf. The Company also reimburses SOG for sales, use or other taxes, or other fees or assessments imposed by law in connection with the provision of services to the Company (other than income, franchise or margin taxes measured by SOG’s net income or margin and other than any gross receipts or other privilege taxes imposed on SOG) and for any costs and expenses arising from or related to the engagement or retention of third-party service providers.

~~Salaries and associated benefits of SOG employees are~~Expenses allocated to the Company at a fixed rate that is reviewed at least annually and adjusted, if needed, based on a detailed analysis of actual time spent by the professional staff on Company projects and activities. General and administrative expenses such as office rent, utilities, supplies and other overhead costs, are allocated on the same fixed rate as thefrom SOG ~~employee salaries. Expenses allocated to the Company~~ for general and administrative expenses and oil and natural gas production expenses for the three months ended March 31, 2019 and 2018 were $17.9 million and ~~2017, are as follows (in thousands):~~$17.9 million, respectively.

Three Months Ended

March 31,

2018

2017
Administrative fees

$
17,332

$
13,990
Third-party expenses

552

1,532
Total included in general and administrative expenses and oil and natural gas production expenses

$
17,884

$
15,522

As of March 31, ~~2018~~2019 and December 31, ~~2017,~~2018, the Company had a net receivable from SOG and ~~other members~~its affiliates of ~~the Sanchez Group of $4.8~~$9.3 million and ~~$4.5~~$6.1 million, respectively, which are reflected as “Accounts receivable—related entities” in the condensed consolidated balance sheets. The net receivable as of March 31, ~~2018~~2019 and December 31, ~~2017~~2018 consists primarily of advances ~~paid~~ related to general and administrative and other costs paid to SOG.

Sanchez Midstream Partners

As of March 31, ~~2018~~2019 and December 31, ~~2017,~~2018, the Company had a net payable to SNMP of approximately ~~$3.9~~$3.3 million and ~~$9.8~~$3.9 million, respectively, that consists primarily of ~~the accrual for~~ fees associated with the gathering agreement signed with SNMP as part of the Company’s sale of SN Catarina’s interests in Catarina Midstream, LLC, a wholly-owned subsidiary of SN Catarina (the “Western Catarina Midstream Divestiture”), which is reflected in the “Accrued Liabilities - Other” account on the condensed consolidated balance sheets. On June 30, 2017, the gathering agreement was amended to, among other things, provide for an additional, incremental infrastructure fee payable to SNMP of $1.00 per barrel of water delivered by SNMP on or after April 1, 2017 through and including March 31, 2018, with no such fee being payable thereafter, and to eliminate certain late payment fees from SN Catarina to SNMP. On September 1, 2017, SN Catarina entered into an agreement with Seco Pipeline, LLC, (“Seco Pipeline”) a wholly owned subsidiary of SNMP, whereby Seco Pipeline transports certain quantities of natural gas on a firm basis for $0.22 per MMBtu delivered on or after September 1, 2017. This agreement had an initial term of one month that expired on September 30, 2017, but the agreement has continued month-to-month and will continue to do so until terminated by either party.

Antonio R. Sanchez, III, the son of Antonio R. Sanchez, Jr. and brother of Patricio D. Sanchez, is the Company’s Chief Executive Officer and is a member of the board of directors of both the Company and of the general partner of SNMP (“SNMP GP”). Patricio D. Sanchez, an Executive Vice President of the Company, is the President and Chief Operating Officer of SNMP GP and a director of SNMP GP. Eduardo A. Sanchez, the brother of Antonio R. Sanchez, III and Patricio D. Sanchez and the son of Antonio R. Sanchez, Jr., is a director of SNMP GP. Antonio R. Sanchez, Jr., the Executive Chairman of the Board of the Company, Antonio R. Sanchez, III, Eduardo A. Sanchez and Patricio D. Sanchez all directly or indirectly own certain equity interests in the Company, SNMP and SNMP GP. Antonio R. Sanchez, Jr., Antonio R. Sanchez, III, Eduardo A. Sanchez and Patricio D. Sanchez beneficially own

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~~approximately 0.71%, 2.30%, 2.34% and 2.71%, respectively, of the SNMP common units outstanding as of March 31, 2018 and, together with Ana Lee Sanchez Jacobs, indirectly own 100% of SNMP GP.~~

~~SNMP Unit Acquisition~~

~~On November 22, 2016, a subsidiary of the Company purchased 2,272,727 common units of SNMP for $25.0 million in a private placement (see Note 9, “Investments”).~~

~~SNMP Lease Option~~

On October 6, 2016, the Company and SN Terminal, LLC (the “SNT”), a wholly owned subsidiary of the Company, on the one hand, and SNMP, on the other hand, entered into a Purchase and Sale Agreement (the “Lease Option Purchase Agreement”) pursuant to which SNT sold and conveyed to SNMP an option to acquire a ground lease (the “Lease Option”) to which SNT was a party for a tract of land leased from the Calhoun Port Authority in Point Comfort, Texas. In addition, if the Company or any of its affiliates entered into an option to engage in the construction of or participation in a Project (as defined below) and/or received the benefit of an acreage dedication from an affiliate of the Company relating to a Project, then such option and/or acreage dedication would have also been assigned to SNMP, if SNMP exercised the Lease Option. SNMP would have paid SNT $1.00 if the Lease Option was exercised, along with $250,000 if SNMP or any other person affiliated with SNMP elected to construct, own or operate a marine crude storage terminal on or within five miles of the Port Comfort lease or participated as an investor in the same, within five miles thereof (a “Project”), or the Company or its affiliates conveyed an acreage dedication to or an option regarding a Project. On September 11, 2017, the Company, SNT and SNMP entered into an agreement that terminated the Lease Option.

~~Carnero Processing Disposition~~

On November 22, 2016, SN Midstream sold its membership interests in Carnero Processing, LLC (“Carnero Processing”) to SNMP for an initial payment of $55.5 million and the assumption by SNMP of remaining capital commitments to Carnero Processing, which were estimated at approximately $24.5 million (the “Carnero Processing Disposition”). The Company recorded a deferred gain of approximately $7.5 million included in “Other Liabilities” as a result of the firm gas processing agreement that remains between the Company and Targa. This deferred gain was to be amortized over the term of this firm gas processing agreement according to volumes processed through the Carnero Processing facility, however, upon adoption of ASC 606, this deferred gain was reversed and opening retained earnings was adjusted as of January 1, 2018. Refer to Note 18, “Revenue Recognition” for additional discussion.

~~Carnero Gathering Disposition~~

On July 5, 2016, SN Midstream sold its membership interests in Carnero Gathering to SNMP for an initial payment of approximately $37.0 million and the assumption by SNMP of remaining capital commitments to Carnero Gathering, estimated at approximately $7.4 million (the “Carnero Gathering Disposition”). The Company recorded a deferred gain of approximately $8.7 million included in “Other Liabilities” as a result of the firm gas gathering agreement that remains between the Company and Targa and a transportation services agreement between Targa and Carnero Gathering. This deferred gain was to be amortized over the term of this firm gas gathering agreement according to volumes processed through the Carnero Processing facility, however, upon adoption of ASC 606, this deferred gain was reversed and opening retained earnings was adjusted as of January 1, 2018. The Company recognized an earnout derivative asset related to the Carnero Gathering Disposition in the amount of $6.4 million upon adoption of ASC 606 which will be revalued at each reporting period. Refer to Note 8, “Derivative Instruments” for additional discussion of the earnout derivative asset and Note 18, “Revenue Recognition” for additional discussion of the impact of ASC 606.

~~SR Settlement~~

~~On August 11, 2017,~~ the Company, the plaintiffs and all named defendants entered into a Stipulation of Settlement (the “Stipulation”) reflecting the terms of the settlement of the derivative stockholder litigation entitled ~~In re Sanchez Energy Derivative Litigation~~, Consolidated C.A. No. 9132-VCG in the Court of Chancery of the State of Delaware (the “Court”), relating to the Company’s August 2013 purchase of working interests in the TMS from Sanchez Resources (the “SR Settlement”). On November 6, 2017, the Stipulation was approved by the Court and became final on December 20, 2017 with an effective date of November 29, 2017, pursuant to which, among other things: (i) the defendants (or their insurance companies) made a payment to the Company of an aggregate of $11.75 million ($5.2

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million, net of fees, expenses and other amounts); (ii) the sole member of Sanchez Resources transferred the equity of Sanchez Resources to us; (iii) Sanchez Resources transferred certain royalty interests in the TMS acreage held by Sanchez Resources to us, and (iv) Alan Jackson and Greg Colvin were removed from the Company’s compensation committee. Sanchez Resources and one of its subsidiaries is party to the SR Credit Agreement of which approximately $24.0 million is outstanding. See Note 7, “Debt” for additional discussion of the SR Credit Agreement. The credit facility is solely secured by substantially all of the assets of Sanchez Resources and/or its subsidiary, without recourse to SN or any of its other subsidiaries, consisting of approximately 14,000 net acres. The assets and liabilities underlying the equity interests transferred to the Company were recorded following the provisions of ASC 820 to measure nonfinancial assets and liabilities at fair value. The fair value measurements were based on market and cost approaches utilizing third-party market participant operating and development estimates. The assets and liabilities underlying the equity interests transferred to the Company were recorded at fair value on a preliminary basis as of the date of the transfer as follows (in thousands):

Proved oil and natural gas properties

$
17,719
Unproved properties

5,227
Other assets acquired

3,952
Fair value of assets acquired

26,898
Asset retirement obligations

(2,902)
Fair value of net assets acquired

$
23,996

~~Comanche Acquisition~~

On March 1, 2017, we closed the Comanche Acquisition and, in connection with the closing, entered into a number of transactions with Gavilan, GSO Capital Partners LP (“GSO”) and the Blackstone Warrantholders (as defined below), or their affiliates, which are related parties (see Note 4, “Acquisitions and Divestitures”), including (i) the SPA (defined below) with an investment vehicle owned by certain funds managed or advised by GSO (the “GSO Funds”) and a controlled affiliate of GSO, (ii) warrant agreements with the Blackstone Warrantholders, (iii) Registration Rights Agreements (as defined below) with the Blackstone Warrantholders and the GSO Funds, (iv) the Partnership Agreement (as defined below) with an entity controlled by an affiliate of GSO, and (v) the GP LLC Agreement (as defined below) with a controlled affiliate of GSO (see Note 14, “Stockholders’ and Mezzanine Equity”).

In addition, in connection with the closing of the Comanche Acquisition, we also entered into (i) separate standstill and voting agreements (the “Standstill Agreements”) with the Blackstone Funds (as defined below) and the GSO Funds, respectively, (ii) an eight-year (subject to earlier termination as provided for therein) joint development agreement (the “JDA”) with Gavilan, (iii) a shareholders agreement (the “Shareholders Agreement”) with Gavilan Holdco, (iv) a management services agreement (the “Management Services Agreement”) with Gavilan Holdco and SN Comanche Manager, and (v) certain marketing agreements with Gavilan.

Each Standstill Agreement (i) restricts the ability of each of Blackstone Capital Partners VII L.P. and Blackstone Energy Partners II L.P. (together, the “Blackstone Funds”) and the GSO Funds (and indirectly certain of their affiliates) to take certain actions relating to the acquisition of our securities or assets or participation in our management, (ii) contains a two year lock-up restricting dispositions of the Company’s common stock or the warrants to purchase the Company’s common stock, and (iii) contains an agreement to vote any voting securities of the Company in the same manner as recommended by our Board.

Pursuant to the Shareholders Agreement, Gavilan Holdco has the right, but not the obligation, to appoint one observer representative to be present at all regularly scheduled meetings of the full board of directors of the Company.

The JDA provides for the administration, operation and transfer of the jointly owned Comanche Assets, and further provides for the (i) establishment of an operating committee to control the timing, scope and budgeting of operations on the Comanche Assets (subject to certain exceptions) and (ii) designation of SN Maverick as operator of the Comanche Assets and certain other interests (subject to forfeiture in the event of certain default events); the JDA also provides for mechanics relating to division of assets and operatorship among the parties, contains restrictions on the indirect or direct transfer of the parties’ interests in the Comanche Assets, including certain tag-along rights and rights of first offer provisions, and provides Gavilan with certain drag-along rights in the event of certain sale transactions, subject to certain exceptions and potential alternative structures or asset divisions.

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Pursuant to the Management Services Agreement, the Manager serves as manager of Gavilan Holdco’s business and provides comprehensive general, administrative, business and financial services at a price equal to Manager’s actual cost of providing such services (including an “administrative fee” equal to 2% of SOG’s total G&A costs), continuing until the occurrence of one or more events giving Manager or Gavilan Holdco the right to terminate the agreement. At the closing of the Comanche Acquisition, Gavilan Holdco paid $1.0 million to Manager under the agreement. The Management Services Agreement provides that Manager may not bill more than $500,000 of G&A costs per month to Gavilan Holdco (subject to reasonable adjustments that are consistent with market terms as a result of an increase in actual G&A costs incurred, and based upon a reasonable allocation of such costs). We also entered into a back-to-back management arrangement between Manager and SOG, on substantially the same terms and conditions as the Management Services Agreement, pursuant to which Manager delegated to SOG, and SOG agreed to perform for and on behalf of Manager, Manager’s duties and obligations under such services agreement; Manager is required to remit amounts received directly from Gavilan Holdco to Manager, including the $1.0 million paid at closing to Manager, and to pay SOG the 2% administrative fee referred to above. In addition, we entered into a management services agreement between SOG and SN UnSub pursuant to which SOG serves as manager of SN UnSub’s oil and natural gas ~~properties~~gathering and provides comprehensive general, administrative, business and financial services at a price equal to SOG’s actual cost of providing such services (including an “administrative fee” equal to 2% of SOG’s total G&A costs), with an initial term expiring on March 1, 2024 (subject to earlier termination as provided therein), renewing automatically for additional one-year terms thereafter unless either SN UnSub or SOG delivers written notice to the other of its desire not to renew the term at least 180 days prior to such anniversary date. SOG may not bill G&A costs to SN UnSub in excess of $5 million per calendar year until March 1, 2019, or in excess of $10 million per calendar year thereafter.transportation services.

Pursuant to a crude oil production marketing agreement, a residue gas marketing agreement and a marketing agreement for NGLs between Gavilan and SN Maverick, Gavilan sells all of its production from the Comanche Assets to SN Maverick and SN Maverick purchases all such production from Gavilan, transports and sells such production and remits to Gavilan its proportionate share of the sale proceeds

Pursuant to the LLC Agreement of GRHL, GRHL authorized and issued a total of 100 Class A Units to SN Comanche Manager. SN Comanche Manager, as holder of the Class A Units, does not have voting rights with respect to GRHL except regarding amendments to the LLC Agreement that adversely affect the holders of Class A Units, approval of affiliate transactions, or as required by law. Twenty percent of the Class A Units vest on each of the first five anniversaries of the effective date of March 1, 2017. The holders of Class A Units are entitled to distributions from Available Cash, as defined in and subject to the provisions of the LLC Agreement. As of March 31, 2018, no distributions of Available Cash had been made to the Company.

Note 13. Accrued Liabilities and Other Current Liabilities

The following information summarizes accrued liabilities as of March 31, ~~2018~~2019 and December 31, ~~2017~~2018 (in thousands):


	March 31,		December 31,		March 31,		December 31,
	2018		2017		2019		2018
Capital expenditures	$	98,819	$	85,340	$	15,252	$	61,970
Other:
General and administrative costs		6,012		8,855
General and administrative expenses						17,551		19,460
Production taxes		4,765		5,084		4,563		5,157
Ad valorem taxes		3,864		84		4,711		445
Lease operating expenses		28,551		32,152		27,825		24,138
Interest payable		32,939		34,632		32,776		47,866
Other accrued liabilities		—		3,987		3,393		5,662
Total accrued liabilities	$	174,950	$	170,134	$	106,071	$	164,698

The following information summarizes other payables as of March 31, 2019 and December 31, 2018 (in thousands):


	March 31,		December 31,
	2019		2018
Revenue payable	$	120,124	$	71,296
Production tax payable		2,544		3,443
Other		2,134		(111)
Total other payables	$	124,802	$	74,628

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The following information summarizes other ~~payables as of March 31, 2018 and December 31, 2017 (in thousands):~~

March 31,

December 31,

2018

2017
Revenue payable

$
74,020

$
75,832
Production tax payable

3,492

2,774
Other

7,176

3,364
Total other payables

$
84,688

$
81,970

~~The following information summarizes other~~ current liabilities as of March 31, ~~2018~~2019 and December 31, ~~2017~~2018 (in thousands):


	March 31,		December 31,		March 31,		December 31,
	2018		2017		2019		2018
Operated prepayment liability	$	78,932	$	88,999	$	23,795	$	51,844
Deferred gain on Western Catarina Midstream Divestiture - short term		23,720		23,720		—		23,720
Phantom compensation payable - short term		3,286		2,525		31		17
Total other current liabilities	$	105,938	$	115,244	$	23,826	$	75,581

Note 14. Stockholders’ and Mezzanine Equity

~~Common Stock Offerings~~

On May 25, 2017, the Company entered into an equity distribution agreement with Citigroup Global Markets, Inc., BMO Capital Markets Corp., Capital One Securities, Inc., RBC Capital Markets, LLC and SunTrust Robinson Humphrey, Inc. and filed with the SEC a prospectus supplement to our shelf registration statement that allows us to issue from time to time shares of our common stock up to an aggregate gross amount of $75 million (the “2017 ATM”). Sales of our common stock, if any, under the 2017 ATM will be made by any method permitted by law deemed to be an “at the market” offering as defined under the Securities Act, including, without limitation, sales made directly on the New York Stock Exchange, on any other existing trading market for our shares of common stock or to or through a market maker or as otherwise agreed by the Company and the sales agent. As of March 31, 2018, we had not issued any shares of our common stock under the 2017 ATM.

On February 6, 2017, the Company completed an underwritten public offering of 10,000,000 shares of the Company's common stock at a price to the public of $12.50 per share ($11.7902 per share, net of underwriting discounts). The Company granted the underwriters a 30-day option to purchase up to an additional 1,500,000 shares of the Company’s common stock on the same terms, which was exercised in full and closed on February 6, 2017. The Company received net proceeds of approximately $135.9 million (after deducting underwriting discounts of approximately $7.8 million) from the sale of the shares of common stock.

Series A Preferred Stock ~~Offering~~

On September 17, 2012, the Company completed a private placement of 3,000,000 shares of Series A Preferred Stock, which were sold to a group of qualified institutional buyers pursuant to the Rule 144A exemption from registration under the Securities Act. The issue price of each share of the Series A Preferred Stock was $50.00. The Company received net proceeds from the private placement of $144.5 million, after deducting initial purchasers’ discounts and commissions and offering costs of $5.5 million.

Each share of Series A Preferred Stock is convertible at any time at the option of the holder thereof at an initial conversion rate of 2.325 shares of common stock per share of Series A Preferred Stock (which is equal to an initial conversion price of $21.51 per share of common stock) and is subject to specified adjustments. As of March 31, ~~2018,~~2019, based on the initial conversion price, approximately ~~4,275,640~~1,814,502 shares of common stock would be issuable upon conversion of all of the outstanding shares of the Series A Preferred Stock.

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The annual dividend on each share of Series A Preferred Stock is 4.875% on the liquidation preference of $50.00 per share and is payable quarterly, in arrears, on each January 1, April 1, July 1 and October 1, when, as and if declared by the ~~Board.~~Company’s board of directors (the “Board”). The Company may, at its option, pay dividends in cash and, subject to certain conditions, common stock or any combination thereof. Dividends are cumulative and, ~~as of~~beginning with the three month period ended March 31, ~~2018, all dividends~~2019, the Board determined to suspend the dividend on our Series A Preferred Stock. Dividends accumulated through that date ~~had~~have been paid. The dividends accrued for the period from January 1 to March 31, 2018, were declared by the Board and paid in cash to the Company’s paying agent on March 30, 2018 and distributed by the agent to holders on April 2, 2018.

Except as required by law or the Company’s Amended and Restated Certificate of Incorporation (the “Charter”), holders of the Series A Preferred Stock will have no voting rights unless dividends fall into arrears for six or more quarterly periods (whether or not consecutive). In that event and until such arrearage is paid in full, the holders of the Series A Preferred Stock and the holders of the Series B Preferred Stock, voting as a single class, will be entitled to elect two directors and the number of directors on the Board will increase by that same number.

At any time on or after October 5, 2017, the Company may at its option cause all outstanding shares of the Series A Preferred Stock to be automatically converted into common stock at the conversion price, if, among other conditions, the closing sale price (as defined) of the Company’s common stock equals or exceeds 130% of the conversion price for a specified period prior to the conversion.

If a holder elects to convert shares of Series A Preferred Stock upon the occurrence of certain specified fundamental changes, the Company will be obligated to deliver an additional number of shares above the applicable conversion rate to compensate the holder for lost option time value of the shares of Series A Preferred Stock as a result of the fundamental change.accrued.

Series B Preferred Stock ~~Offering~~

On March 26, 2013, the Company completed a private placement of 4,500,000 shares of Series B Preferred Stock. The issue price of each share of the Series B Preferred Stock was $50.00. The Company received net proceeds from the private placement of $216.6 million, after deducting placement agent’s fees and offering costs of $8.4 million.

Each share of Series B Preferred Stock is convertible at any time at the option of the holder thereof at an initial conversion rate of 2.337 shares of common stock per share of Series B Preferred Stock (which is equal to an initial conversion price of $21.40 per share of common stock) and is subject to specified adjustments. As of March 31, ~~2018,~~2019, based on the initial conversion price, approximately ~~8,244,539~~5,868,235 shares of common stock would be issuable upon conversion of all of the outstanding shares of the Series B Preferred Stock.

The annual dividend on each share of Series B Preferred Stock is 6.500% on the liquidation preference of $50.00 per share and is payable quarterly, in arrears, on each January 1, April 1, July 1 and October 1, when, as and if declared by the Board. The Company may, at its option, pay dividends in cash and, subject to certain conditions, common stock or any combination thereof. Dividends are cumulative and, ~~as of~~beginning with the three month period ended March 31, ~~2018, all dividends~~2019, the Board determined to suspend the dividend on our Series B Preferred Stock. Dividends accumulated through that date ~~had~~have been paid. The dividends accrued for the period from January 1 to March 31, 2018, were declared by the Board and paid in cash to the Company’s paying agent on March 30, 2018 and distributed by the agent to holders on April 2, 2018. accrued.

~~Except as required by law or the Charter, holders of the Series B~~ Preferred Stock ~~will have no voting rights unless dividends fall into arrears for six or more quarterly periods (whether or not consecutive). In that event and until such arrearage is paid in full, the holders~~Conversions

On February 12, 2019, 72,500 shares of ~~the Series B Preferred Stock and the holders of the~~ Series A Preferred Stock ~~voting as a single class, will be entitled to elect two directors and the number of directors on the Board will increase by that same number.~~

~~At any time on or after April 6, 2018, the Company may at its option cause all outstanding~~converted into 168,563 shares of ~~the Series B Preferred Stock to be automatically converted into~~our common stock at the conversion price, if, among other conditions, the closing sale price (as defined) of the Company’s common stock equals or exceeds 130% of the conversion price for a specified period prior to the conversion.

~~If a holder elects to convert~~and 245,832 shares of Series B Preferred Stock ~~upon~~converted into 574,510 shares of our common stock at the ~~occurrence~~election of ~~certain specified fundamental changes,~~ the ~~Company will be obligated~~holders thereof. From March 6 to ~~deliver an additional number~~March 8, 2019, 563,832 shares of Series A Preferred Stock converted into 1,310,914 shares ~~above~~of our common stock and 770,986 shares of Series B Preferred Stock converted into 1,801,798 shares of our common stock, at the ~~applicable~~election of the holders thereof. On March 26, 2019, 422,222 shares of Series A Preferred Stock converted into 981,667 shares of our common stock, at the election of the holders thereof.

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~~conversion rate to compensate~~

Through the ~~holder for lost option time value~~conversions, each of the ~~shares~~holders effectively waived their rights to any accrued and unpaid dividends thereon under the conversion terms set forth in Certificates of Designations for the Series A Preferred Stock and Series B Preferred Stock, as applicable. As a result, the Company has reduced its dividend accruals on its Series A Preferred Stock and Series B Preferred Stock for the three months ended March 31, 2019 by approximately $1.5 million as compared to the amount that would have been payable based on the number of ~~the fundamental change.~~shares outstanding prior to these conversions.

~~NOL Rights Plan~~SN UnSub Preferred Unit Issuance

On July 28, 2015, the Company entered into a net operating loss carryforwards rights plan (as amended, the “Rights Plan”) with Continental Stock Transfer & Trust Company, as rights agent. In connection therewith, the Board declared a dividend of one preferred share purchase right (“Right”) for each outstanding share of the Company’s common stock. The dividend was paid on August 10, 2015 to stockholders of record as of the close of business on August 7, 2015 (the “NOL Record Date”). In addition, one Right automatically attaches to each share of common stock issued between the NOL Record Date and such date as when the Rights become exercisable. On March 1, 2017, the Company, ~~amended~~through two of its subsidiaries, SN UnSub and SN EF Maverick, LLC (“SN Maverick”), along with Gavilan Resources, LLC (“Gavilan”), an entity controlled by The Blackstone Group, L.P., completed the ~~Rights Plan to, among other things, amend certain defined terms to account for~~acquisition of approximately 318,000 gross (155,000 net) acres comprised of 252,000 gross (122,000 net) Eagle Ford Shale acres and 66,000 gross (33,000 net) acres of deep rights only, which includes the ~~issuance of warrants and grant of shares of common stock to the GSO Funds and the issuance of warrants to the Blackstone Warrantholders in connection with the closing of the Comanche Acquisition.~~

~~Common Stock and Stock Warrants Issuance~~Pearsall Shale, representing an approximate 49% average working interest therein (the “Comanche Assets”) (the “Comanche Acquisition”).

At the closing of the Comanche Acquisition, pursuant to the Amended and Restated Securities Purchase Agreement (the “SPA”), and subject to the other terms and conditions provided therein: (i) the GSO Funds received 1,455,000 shares of the Company’s common stock and warrants to purchase 1,940,000 shares of the Company’s common stock at an exercise price of $10 per share, subject to customary anti-dilution adjustments; and (ii) Intrepid Private Equity V-A LLC (“Intrepid”) received 45,000 shares of the Company’s common stock and warrants to purchase 60,000 shares of the Company’s common stock at an exercise price of $10 per share, subject to customary anti-dilution adjustments. The warrants issued to the GSO Funds and Intrepid expire on March 1, 2032, in each case in accordance with the terms and conditions of the applicable warrant agreement.

Also at the closing of the Comanche Acquisition, the Company entered into (i) three separate warrant agreements to purchase an aggregate of 6,500,000 shares of the Company’s common stock with each of Gavilan Resources Holdings—A, LLC, Gavilan Resources Holdings —B, LLC, and Gavilan Resources Holdings—C, LLC (collectively, the “Blackstone Warrantholders”), that provide for a $10 exercise price per share to purchase the Company’s common stock, subject to customary anti-dilution adjustments. The warrants issued to the Blackstone Warrantholders expire on March 1, 2022 in accordance with the terms and conditions of the applicable warrant agreement.

~~The exercise price and the number of shares of the Company’s common stock for which a warrant is exercisable are subject to adjustment from time to time upon the occurrence of~~ certain ~~events including: (i) payment of a dividend~~funds managed or distribution to holders of shares of the Company’s common stock payable in the Company’s common stock, (ii) a subdivision, combination, or reclassification of the Company’s common stock, (iii) the distribution of any rights, options or warrants (excluding rights issued under the Rights Plan) to all holders of the Company’s common stock entitling them for a certain period of time to purchase shares of the Company’s common stock at a price per share less than the fair market value per share, and (iv) payment of a cash distribution to all holders of the Company’s common stock or a distribution to all holders of the Company’s common stock any shares of the Company’s capital stock, evidences of indebtedness, or any of assets or any rights, warrants or other securities of the Company. The warrant agreements also provide that, if the Company proposes a voluntary or involuntary dissolution, liquidation or winding up of the affairs of the Company, the holders of the warrants will receive the kind and number of other securities or assets which the holder would have been entitled to receive if the holder had exercised the warrant in full immediately prior to the time of such dissolution, liquidation or winding up and the right to exercise the warrant will terminate on the date on which the holders of record of the shares of common stock are entitled to exchange their shares for securities or assets deliverable upon such dissolution, liquidation or winding up.

In addition, the Company entered into separate registration rights agreements with the Blackstone Warrantholders, the GSO Funds, and Intrepid (collectively, the “Registration Rights Agreements”) The Registration Rights Agreements grant the parties certain registration rights for the shares of our common stock acquired by the parties, including the shares issuable upon the exercise of the warrants to purchase the Company’s common stock. The Registration Rights Agreements with the Blackstone Warrantholders and the GSO Funds provide that the Company will use its reasonable best efforts to prepare and file a shelf registration statement with the SEC to permit the public resale of all registrable securities covered by the applicable Registration Rights Agreement within 18 months of the date of the

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~~agreement and to cause such shelf registration statement to be declared effective no later than two years after the date of the agreement.~~

The Registration Rights Agreements include piggyback rights for the applicable holders, which provide that, if the Company proposes to file certain registration statements or supplements to certain effective registration statements for the sale of shares of the Company’s common stock in an underwritten offering for its own account or that of another person or both, then the Company is required to offer the holders the opportunity to include in such underwritten offering such number of registrable securities as each such holder may request, subject to certain cutback rights if the Company has been advised by the managing underwriter that the inclusion of registrable securities for sale for the benefit of the holders will have an adverse effect on the price, timing or distribution of the shares of common stock in the underwritten offering.

~~SN Comanche Manager, LLC Class A Preferred Unit Member~~

On the Effective Date, pursuant to the LLC Agreement, Gavilan Holdco authorized and issued a total of 100 Class A Units to SN Comanche Manager. GRHL is the parent of Gavilan. SN Comanche Manager, as holder of the Class A Units, does not have voting rights under the LLC Agreement except with respect to amendments to the LLC Agreement that adversely affect the holders of Class A Units, approval of affiliate transactions, or as required by law. Twenty percent of the Class A Units vest on each of the first five anniversaries of the Effective Date. The holders of Class A Units are entitled to distributions from Available Cash (as defined in the LLC Agreement) subject to the provisions of the LLC Agreement.

~~SN UnSub Preferred Unit Issuance~~

~~At the closing of the Comanche Acquisition, pursuant to the SPA and subject to the other terms and conditions provided therein, the~~ GSO ~~Funds~~Capital Partners L.P. purchased 485,000 preferred units of SN UnSub ~~for $485,000,000~~ and Intrepid Private Equity V-A LLC purchased 15,000 preferred units of SN UnSub ~~for $15,000,000~~ (in aggregate, the “SN UnSub Preferred Units”). The applicable parties entered into an amended and restated partnership agreement of SN UnSub (the “Partnership Agreement”) and an amended and restated limited liability company agreement of SN UnSub General Partner (the “GP LLC Agreement”).

~~Under the terms of the Partnership Agreement, holders of the~~ SN UnSub Preferred Units are entitled to receive distributions of 10.0% per annum, payable quarterly in cash, unless a cash payment is then prohibited by certain of SN UnSub’s debt agreements, in which case such distribution will be deemed to have been paid in kind. SN UnSub may not make distributions on the SN UnSub common units until the preferred units are redeemed in full.

The SN UnSub Preferred Units have priority over the common units, to the extent of the Base Return (as defined below), upon a liquidation, sale of all or substantially all assets, certain change of control and exit transactions.

SN UnSub may, from time to time and subject to the conditions set forth in the Partnership Agreement and the SN UnSub Credit Agreement, redeem SN UnSub Preferred Units at a purchase price per unit sufficient to achieve the greater of (i) the amount required to cause the return on investment with respect to each such SN UnSub Preferred Unit to be equal to the product of (x) 1.5 multiplied by (y) the purchase price per unit and (ii) the amount required to cause the internal rate of return with respect to each SN UnSub Preferred Unit to be equal to 14.0%, in each case inclusive of previous distributions made in cash (the “Base Return”). Partners holding a majority of the SN UnSub Preferred Units will have the option to request SN UnSub to redeem all of the preferred units for the Base Return at any time following the seventh anniversary of issuance or upon the occurrence of certain change of control transactions, as further described in the Partnership Agreement.

If (i) the SN UnSub Preferred Units are not timely redeemed by SN UnSub when required, (ii) SN UnSub fails, after March 1, 2018, to pay the holders of the SN UnSub Preferred Units a cash distribution in any two quarters, regardless of whether consecutive, and such failure is continuing, (iii) SN UnSub takes certain material actions without the consent of the holders of the SN UnSub Preferred Units, when required, (iv) certain events of default under SN UnSub and the Company’s credit agreements have occurred or (v) SN Maverick is removed as operator under the JDA under certain circumstances, then a controlled affiliate of GSO will be entitled to appoint a majority of the members of the board of directors of SN UnSub General Partner and may cause a sale of the assets or equity of SN UnSub in order to redeem the SN UnSub Preferred Units.

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~~The SN UnSub Preferred Units issued in March 2017~~ are accounted for as mezzanine equity in the condensed consolidated balance sheet consisting of the following as of March 31, ~~2018~~2019 and December 31, ~~2017,~~2018, respectively, (in thousands):

Three Months Ended

Year Ended

March 31,

December 31,

2018

2017
Mezzanine equity beginning balance

$
427,512

$
—
Private placement of SN UnSub Preferred Units

—

500,000
Discount

—

(90,527)
Accretion of Discount

5,930

18,039
Dividends accrued (1)

12,500

41,667
Dividends prepaid (3)

(2,592)

2,592
Distributions paid (2)

(9,908)

(44,259)
Total mezzanine equity

$
433,442

$
427,512


	Three Months Ended		Year Ended
	March 31,		December 31,
	2019		2018
Mezzanine equity, beginning balance	$	452,828	$	427,512
Accretion of discount		7,033		25,316
Dividends accrued		12,500		50,000
Dividends prepaid (1)		—		(2,592)
Dividends/distributions paid (1)		—		(47,408)
Mezzanine equity, ending balance	$	472,361	$	452,828

(1)

In accordance with the Partnership Agreement and SN UnSub Credit Agreement, cash distributions for the 10% dividend on the SN UnSub Preferred Units were prohibited through February 28, 2018, and thus, the dividends for the year ended December 31, 2017 were deemed to have been accrued and offset by the tax distributions paid.

~~(2)~~

Distributions paid in 2017 represent tax distributions from available cash to holders of the SN UnSub Preferred Units. The Partnership Agreement provides that tax distributions shall be treated as advances of any amounts holders of the SN UnSub Preferred Units are entitled to receive, and shall be offset against any amounts holders of SN UnSub Preferred Units are entitled to receive.

~~(3)~~

In 2017, tax distributions of approximately $2.6 million were paid in excess of the accrued dividend. The excess distribution was offset against a portion of the dividend accrued during the three months ended March 31, 2018.

Earnings (Loss) Per Share—The following table shows the computation of basic and diluted net loss per share for the three months ended March 31, ~~2018~~2019 and ~~2017~~2018 (in thousands, except per share amounts):


	Three Months Ended				Three Months Ended
	March 31,				March 31,
	2018		2017		2019		2018
Net income (loss) per common share - diluted	$	(4,815)	$	15,735
Net loss					$	(67,342)	$	(4,815)
Less:
Preferred stock dividends		(3,987)		(3,987)		(2,516)		(3,987)
Preferred unit dividends and distributions		(9,908)		(16,466)		(12,500)		(9,908)
Preferred unit amortization		(5,930)		(1,710)		(7,033)		(5,930)
Net loss allocable to participating securities(1)(2)		—		—
Net income allocable to participating securities(1)(2)						—		—
Net loss attributable to common stockholders	$	(24,640)	$	(6,428)	$	(89,391)	$	(24,640)
Weighted average number of unrestricted outstanding common shares used to calculate basic net loss per share		80,919		69,659
Weighted average number of unrestricted outstanding common shares used to calculate basic net income (loss) per share						91,663		80,919
Dilutive shares~~(4)~~(3)		—		—		—		—
Denominator for diluted earnings (loss) per common share		80,919		69,659		91,663		80,919
Net loss per common share - basic and diluted	$	(0.30)	$	(0.09)	$	(0.98)	$	(0.30)

(1)

The Company’s restricted shares of common stock are participating securities.

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(2)

For the three months ended March 31, ~~2018~~2019 and ~~2017,~~2018, no losses were allocated to participating restricted stock because such securities do not have a contractual obligation to share in the Company’s losses.

(3)

The three months ended March 31, 2019 excludes 2,745,391 shares of weighted average restricted stock and 11,331,798 shares of common stock resulting from an assumed conversion of the Series A Preferred Stock and Series B Preferred Stock from the calculation of the denominator for diluted earnings per common share as these shares were anti-dilutive. The three months ended March 31, 2018 excludes 1,287,113 shares of weighted average restricted stock and 12,520,179 shares of common stock resulting from an assumed conversion of the Series A Preferred Stock and Series B Preferred Stock from the calculation of the denominator for diluted earnings per common share as these shares were anti-dilutive.

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~~(4)~~

The three months ended March 31, 2017 excludes 1,477,299 shares of weighted average restricted stock and 12,520,179 shares of common stock resulting from an assumed conversion of the Series A Preferred Stock and Series B Preferred Stock from the calculation of the denominator for diluted earnings per common share as these shares were anti-dilutive.

Note 15. Stock‑Based Compensation

~~At the Annual Meeting of Stockholders of the Company held on May 24, 2016 (“2016 Annual Meeting”), the~~The Company’s ~~stockholders approved the Sanchez Energy Corporation~~ Third Amended and Restated ~~2011~~ Long Term Incentive Plan (the “LTIP”)~~. The Board had previously approved the LTIP on April 20, 2016, subject to stockholder approval.~~

The Company’s directors and consultants as well as employees of the Sanchez Group who provide services to the Company are eligible to participate in the LTIP. Awards to participants may be made in the form allows for grants of stock options, stock appreciation rights, restricted shares, phantom stock, other ~~stock-based~~stock based awards or ~~stock~~stack awards, or any combination thereof. The maximum shares of common stock that may be delivered with respect to awards under the LTIP shall be (i) 17,239,790 shares plus (ii) upon the issuance of additional shares of common stock from time to time after April 1, 2016, an automatic increase equal to the lesser of (A) 15% of such issuance of additional shares of common stock and (B) such lesser number of shares of common stock as determined by the Board or Compensation Committee; provided, however, that shares withheld to satisfy tax withholding obligations are not considered to be delivered under the LTIP. If any award is forfeited, cancelled, exercised, paid, or otherwise terminates or expires without the actual delivery of shares of common stock pursuant to such award (the grant of restricted stock is not a delivery of shares of common stock for this purpose), the shares subject to such award shall again be available for awards under the LTIP. There shall not be any limitation on the number of awards that may be paid in cash. Any shares delivered pursuant an award shall consist, in whole or in part, of shares of common stock newly issued by the Company, shares of common stock acquired in the open market, from any affiliate of the Company, or any combination of the foregoing, as determined by the Board or Compensation Committee in its discretion.

~~The LTIP is administered by~~Effective January 1, 2019, the Compensation Committee of the Board as appointed by the Board. Our Board may terminate or amend the LTIP at any time with respect to any shares for which a grant has not yet been made. Our Board has the right to alter or amend the LTIP or any part of the LTIP from time to time, including increasing the number of shares that may be granted, subject to stockholder approval as may be required by the exchange upon which the shares of common stock are listed at that time, if any. No change may be made in any outstanding grant that would materially reduce the benefits of the participant without the consent of the participant. The LTIP will expire upon its termination by the Board or, if earlier, when no shares remain available under the LTIP for awards. Upon termination of the LTIP, awards then outstanding will continue pursuant to the terms of their grants.

~~The~~ Company records stock-based compensation expense for awards granted ~~to its directors (for their services as directors)~~ in accordance with the provisions of ASU 2018-07 “Compensation - Stock Compensation (ASC 718) - Improvements to Nonemployee Share-Based Payment Accounting,” which expands the scope of ASC 718, ~~“Compensation—~~“Compensation – Stock ~~Compensation.” Stock-based~~Compensation”, to include share-based payment transactions for acquiring goods and services from nonemployees. Pursuant to this standard, stock-based compensation expense ~~for these awards~~ is based on the grant-date fair value ~~and recognized over the vesting period using the straight-line method.~~

~~Awards granted to employees~~ of ~~the Sanchez Group (including those employees of the Sanchez Group who also serve as the Company’s officers) and consultants in exchange for services are considered~~our stock awards to non-employees and the Company records stock-based compensation expense for these awards at fair value in accordance with the provisions of ASC 505-50, “Equity-Based Payments to Non-Employees.” For awards granted to non-employees, the Company records compensation expenses equal to the fair value of the stock-based award at the measurement date, which is determined to be the earlier of the performance commitment date or the service completion date. Compensation expense for unvested awards to non-employees is revalued at each period end and is amortized over the vesting period of the stock-based award. Stock-based payments are measured based on the fair value of the equity instruments granted, as it is more determinable than the value of the services rendered. For the restricted stock awards granted to non-employees, stock-based compensation expense is based on fair value re-measured at each reporting period and recognized over the vesting period using the straight-line method. ~~Compensation expense for these awards will be revalued at each period end until vested. Forfeitures~~As a result of ~~restricted stock awards granted to non-employees are accounted for as they are incurred.~~

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~~During the three months ended March 31, 2018,~~ASU 2018-07, the Company ~~issued approximately 0.5 million shares~~remeasured the value of restricted common stock pursuant to the LTIP to certain employees (including the Company’s officers) and consultants of SOG, with whom the Company has a services agreement. These shares of restricted common stock vest in equal annual amounts over a three-year period.

In February 2016 and April 2016, the Compensation Committee approved several new forms of agreement for use in equity awards pursuant to the LTIP. The new forms of agreements consist of two new forms of restricted stock award agreements, one of which provides for vesting in equal annual increments over a three year period from the grant date (the “Grant Date”) and the other of which provides for cliff vesting five years after the Grant Date or earlier if the common stock closing price equals or exceeds certain benchmarks as set forth in the form of agreement (the “Performance Accelerated Restricted Stock” or “PARS”), and two new forms of phantom stock agreements payable only in cash, one of which provides for vesting in equal annual increments over a three year period from the Grant Date (the “Phantom Stock”) and the other of which provides for cliff vesting five years after the Grant Date or earlier if the Company’s common stock closing price equals or exceeds certain benchmarks as set forth in the form of agreement (the “Performance Accelerated Phantom Stock” or “PAPS”). No PARS or PAPS were granted during the three months ended March 31, 2018.

The PARS, PAPS and Phantom Stock awards granted to certain employees of the Sanchez Group (including those employees of the Sanchez Group who also serve as the Company’s officers) and consultants in exchange for services are considered awards to non-employees and the Company records stock-based compensation expense for these awards at fair value in accordance with the provisions of ASC 718, “Compensation – Stock Compensation.” In accordance with the guidance, the inclusion of market performance acceleration conditions on PARS does not change the accounting classification as compared to the restricted stock without market performance acceleration conditions, as both are still classified as equity within the Company’s balance sheet. The Phantom Stock awards are required to be settled in cash by the Company and, per the guidance, should be classified as a liability. Compensation expense for theour outstanding unvested awards ~~is revalued at each period end and is amortized over the vesting period~~as of ~~the stock-based award using the straight-line method.~~January 1, 2019. This did not have a material impact on our financial statements.

During the three months ended March 31, ~~2018,~~2019, the Company did not issue any shares of restricted common stock pursuant to the LTIP.

During the three months ended March 31, 2019, the Company issued ~~approximately 1.2 million~~an immaterial number of shares of ~~Phantom Stock~~phantom stock pursuant to the LTIP to certain employees of SOG (including the Company’s officers), with whom the Company has a services agreement. These shares of ~~Phantom Stock~~phantom stock vest in equal annual amounts over a ~~three-year~~three year period.

On March 1, 2017, the Company’s Chief Executive Officer, Executive Chairman of the Board, President, and Chief Operating Officer entered into a new form of agreement for use in equity awards pursuant to the LTIP, for 245,234 target shares of the Company’s common stock, 245,234 target shares of the Company’s common stock, 245,234 target shares of the Company’s common stock, and 81,745 target shares of the Company’s common stock, respectively. The new form of agreement is a performance phantom stock agreement payable in shares of common stock (the “Performance Phantom Stock Agreement”). The shares granted pursuant to the Performance Phantom Stock Agreement (the “Performance Awards”) will vest (if any) in equal annual increments over a five-year period ranging from 0% to 200% of the target phantom shares granted based on the Company’s share price appreciation relative to the share price appreciation of the S&P Oil & Gas Exploration & Production Select Industry Index for each year in the five-year performance period beginning on January 1, 2017 and ending on December 31, 2021, subject each officer’s continuous service with the Company through each vesting date. For the ~~2017~~2018 performance period applicable to ~~these~~our performance phantom stock awards granted in 2017 (the “Performance Awards”), 0% of the target shares were be awarded.

~~The~~For the 2018 performance period applicable to our cash-settled performance-based phantom stock awards ~~are considered~~and stock-settled performance-based phantom stock awards granted in 2018 (together, the “PBPS Awards”), 71% of the target shares were awarded, equating to ~~non-employees~~419,430 cash-settled awards and ~~the Company records stock-based~~419,430 stock-settled awards. Stock-based compensation expense for these awards ~~at fair value~~was calculated in accordance with ~~the provisions of~~ ASC 718 “Compensation – Stock Compensation.” In accordance with the guidance, the Performance Awards are classified as equity within the Company’s balance sheet, as they are settled in shares of the Company’s common stock. The Performance Awards have graded-vesting features and ~~as such, the compensation expense for the unvested awards~~ is calculated using the graded-vesting method whereby the Company recognizes compensation expense over the requisite service period for each separately vesting tranche of the award as though they were, in substance, multiple awards. In addition, the estimated value of each tranche will be revalued at each period end andbeing amortized over the vesting period.

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The Company recognized the following stock-based compensation expense (in thousands) which is included in general and administrative expense in the condensed consolidated statements of operations:


	Three Months Ended				Three Months Ended
	March 31,				March 31,
	2018		2017		2019		2018
Restricted stock awards, directors	$	297	$	282	$	18	$	297
Restricted stock awards, non-employees		(204)		11,265		75		(204)
Performance awards		(468)		544		48		(468)
Phantom stock awards		(898)		10,941		132		(898)
Total stock-based compensation expense (benefit)	$	(1,273)	$	23,032	$	273	$	(1,273)

Based on the ~~$3.13~~$0.20 per share closing price of the Company’s common stock on March 31, ~~2018,~~2019, there was approximately ~~$13.9~~$0.5 million of unrecognized compensation cost related to the non‑vested restricted shares outstanding. The cost is expected to be recognized over an average period of approximately ~~1.93~~2.03 years.

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Based on the ~~$3.13~~$0.20 per share closing price of the Company’s common stock on March 31, ~~2018,~~2019, there was ~~approximately $0.3~~less than $0.1 million of unrecognized compensation cost related to the non‑vested ~~PARS~~performance accelerated restricted stock outstanding. The cost is expected to be recognized over an average period of approximately ~~3.04~~2.04 years.

Based on the ~~$3.13~~$0.20 per share closing price of the Company’s common stock on March 31, ~~2018,~~2019, there was approximately ~~$8.4~~$0.5 million of unrecognized compensation cost related to the non‑vested ~~PAPS~~performance accelerated phantom stock (“PAPS”) and ~~Phantom Stock~~phantom stock outstanding. The cost is expected to be recognized over an average period of approximately ~~2.62~~2.10 years.

Based on the estimated per share price of the Performance Awards on March 31, ~~2018,~~2019, there was ~~approximately $0.7~~less than $0.1 million of unrecognized compensation cost related to the Performance Awards. The cost is estimated to be recognized over a weighted average period of approximately ~~3.13~~2.73 years.

Based on the estimated per share price of the common stock underlying the PBPS Awards on March 31, 2019, there was approximately $0.3 million of unrecognized compensation cost related to the PBPS Awards. The cost is estimated to be recognized over a weighted average period of approximately 1.51 years.

A summary of the status of the non-vested shares for the three months ended March 31, ~~2018~~2019 and ~~2017~~2018 is presented below (in thousands):


	Three Months Ended				Three Months Ended
	March 31,				March 31,
	2018		2017		2019	2018
Non-vested common stock, beginning of period		4,897		6,527	5,024	4,897
Granted		480		1,794	—	480
Vested		(1,617)		(2,349)	(948)	(1,617)
Forfeited		(76)		—	(128)	(76)
Non-vested common stock, end of period		3,684		5,971	3,948	3,684

As of March 31, ~~2018,~~2019, approximately ~~8.6~~8.3 million shares ~~remain~~remained available for future issuance to participants under the LTIP.

A summary of the status of the non‑vested ~~Phantom Stock shares~~phantom stock and PAPS as of March 31, ~~2018~~2019 and ~~2017~~2018 is presented below (in thousands, except per share amounts):


	Three Months Ended				Three Months Ended
	March 31,				March 31,
	2018		2017		2019	2018
Non-vested phantom stock, beginning of period		3,589		3,912
Non-vested phantom stock and PAPS, beginning of period					5,126	3,589
Granted		1,178		1,795	7	1,178
Vested		(715)		(1,117)	(892)	(715)
Forfeited		(103)		—	(335)	(103)
Non-vested phantom stock, end of period		3,949		4,590
Non-vested phantom stock and PAPS, end of period					3,906	3,949

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Note 16. Income Taxes

The Company used a year-to-date effective tax rate method for recording income taxes for the ~~three-month~~three month periods ended March 31, ~~2018~~2019 and ~~2017.~~2018. This method is based on our ~~expectations~~determination at March 31, 2019 and 2018 ~~and 2017~~ that due to our valuation allowance position, the income tax provision does not materially change by using a year-to-date effective tax rate method as compared to an estimated full year annual effective tax rate method. Further, for the period ended March 31, 2018, a small change in our estimated ordinary income could ~~result~~have resulted in a large change in the estimated annual effective tax rate. We will use this year-to-date effective tax rate method each quarter until such time a return to the annualized effective tax rate method is deemed material or appropriate.

The ~~Company's~~Company’s effective tax rate for the three months ended March 31, 2019 and 2018 was (0.7%) and ~~2017 was~~ 0% ~~and (6.4)%~~, respectively. The difference between the statutory federal income taxes calculated using a U.S. Federal statutory

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corporate income tax rate of 21% and the Company’s effective tax ~~rate~~rates of (0.7%) and 0% for the three months ended March 31, 2019 and 2018, respectively, is related to the valuation allowance on deferred tax assets. The Company’s effective tax rate of (6.4)% for the three months ended March 31, 2017 is primarily related to the recording of certain deferred tax liabilities associated with the Comanche Acquisition that were recorded directly to equity, whereas the correlating movement in the valuation allowance was required to be recorded to income tax expense.

The Company provides for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in the financial statements in accordance with authoritative guidance for accounting for income taxes. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. In recording deferred income tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred income tax assets will be realized. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible. The Company believes that after considering all the available objective evidence, both positive and negative, historical and prospective, with greater weight given to historical evidence, management is not able to determine that it is more likely than not that the deferred tax assets will be realized and, therefore, has established a valuation allowance to reduce the deferred tax assets as of March 31, ~~2018.~~2019. The Company will continue to assess the valuation allowance against deferred tax assets considering all available information obtained in future reporting periods.

At March 31, ~~2018,~~2019, the Company had no material uncertain tax positions.

~~On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill~~

commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”) that significantly reforms the Internal Revenue Code of 1986, as amended (the “Code”). Among the many provisions included in the Tax Act is a provision to reduce the U.S. federal corporate income tax rate from 35% to 21% effective January 1, 2018.

We recognized the income tax effects of the Tax Act in accordance with Staff Accounting Bulletin No. 118, which provides SEC staff guidance for the application of ASC Topic 740, Income Taxes. The guidance allows for a measurement period of up to one year after the enactment date to finalize the recording of the related tax impacts. As such, our financial results reflect the provisional income tax effects of the Tax Act for which the accounting under ASC Topic 740 is incomplete, but a reasonable estimate could be determined. We did not identify any items for which the income tax effects of the Tax Act could not be reasonably estimated as of March 31, 2018.

We continue to assess the impact of the Tax Act on our business. Our provisional amounts may be adjusted due to changes in interpretations of the Tax Act, legislative action to address questions that arise because of the Tax Act, or changes in accounting standards for income taxes or related interpretations. Any updates or changes to provisional estimates will be reported in the reporting period in which any such adjustments are determined, which will be no later than the fourth quarter of 2018.

Note 17. Commitments and Contingencies

Shareholder Derivative Litigation

On August 29, 2018, a derivative action was filed in the Court of Chancery of the State of Delaware against certain of the Company’s directors (Armato et al. v. A.R. Sanchez, Jr. et al., No. 2018-0642, the “Derivative Action”). The complaint alleges breach of fiduciary duty, unjust enrichment and waste of corporate assets against directors of the Company based on purportedly excessive compensation of the Company’s non-employee directors. On October 22, 2018, the Company and defendant directors filed an answer to the Derivative Action. In their answer, the defendant directors denied any wrongdoing or liability in response to the allegations in the complaint. The Derivative Action remains in its preliminary stages. As a result, the Company is unable to reasonably predict an outcome of the Derivative Action or a timeframe for its resolution. The complaint does not specify damages sought.

From time to time, the Company may be involved in lawsuits or other legal proceedings that arise in the normal course of its business. Management cannot predict the ultimate outcome of such lawsuits or claims. Management does not currently expect the outcome of any of the known claims or proceedings to individually or in the aggregate have a material adverse effect on our results of operations or financial condition. We are not aware of any material governmental proceedings against us or contemplated to be brought against us.

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Catarina Drilling ~~Obligation~~Commitment

In ~~connection with~~ the Catarina ~~Acquisition, the undeveloped acreage~~area, we ~~acquired is subject to~~have a ~~continuous~~ drilling ~~obligation. Such drilling obligation~~commitment that requires us to drill (i) 50 wells in each ~~annual~~12-month period commencing on July 1, 2014 and (ii) at least one well in any consecutive ~~120-day~~120‑day period, in order to maintain rights to any future undeveloped acreage. Up to 30 wells drilled in excess of the minimum 50 wells in a given annual period can be carried over to satisfy part of the ~~50 well~~50-well requirement in the subsequent ~~annual drilling~~12-month period on a well-for-well basis. The lease also creates a customary security interest in the production therefrom in order to secure royalty payments to the lessor and other lease obligations. ~~Our current~~The Company has met all of its 50-well annual drilling commitment for the period July 1, 2018 to June 30, 2019 and has initiated a bank of 12 wells that may be counted toward the next annual drilling commitment period, which begins on July 1, 2019. Furthermore, our 2019 capital budget and plans include the ~~drilling of~~additional activity needed to fulfill the commitment to drill at least ~~the minimum number of wells required to maintain access to such undeveloped acreage.~~one well in any 120-day period.

Comanche Drilling ~~Obligation~~Commitment

In ~~connection with~~ the Comanche ~~Acquisition,~~area, we ~~through our subsidiaries, SN Maverick and SN UnSub, and Gavilan, entered into~~have a development ~~agreement with Anadarko. The development agreement~~commitment that, in addition to other requirements in the leases that must be met in order to maintain our acreage position, requires us to complete and equip 60 wells in each annual period commencing on September 1, 2017 and continuing thereafter until September 1, ~~2022. The development agreement permits up~~2022 or pay a penalty for the failure to do so. Up to 30 wells completed and equipped in excess of the annual ~~60 well~~60-well requirement tocan be carried over to satisfy part of the ~~60 well~~60-well requirement in subsequent annual periods on a well-for-well basis. ~~The development agreement contains a parent guarantee of the performance of SN Maverick and SN UnSub.~~ If we fail to complete and equip the required number of wells in a given year (after applying any qualifying additional wells from previous years), we and Gavilan ~~must pay~~are jointly and severally liable to Anadarko E&P Onshore, LLC for a default fee of $0.2 million for each

Table of Contents

well we do not timely complete and equip. ~~Our current capital budget and plans include the drilling of~~We currently intend to drill at least the minimum number of wells required to satisfy the development agreement and to comply with applicable lease requirements necessary to maintain ~~access to such undeveloped acreage.~~

~~Lease Payment Obligations~~

As of March 31, 2018, the Company had $172.2 million in lease payment obligations that satisfy operating lease criteria. These obligations include: (i) $87.9 million in payments due with respect to firm commitment of oil and natural gas volumes under the gathering agreement contract signed with SNMP as part of the Western Catarina Midstream Divestiture that commenced on October 14, 2015 and continues until October 13, 2020, (ii) $79.8 million for corporate and field office leases with expiration dates through March 2025, and (iii) $4.5 million for a 10 yearour Comanche acreage ~~lease agreement for a promotional ranch managed by the Company in Kenedy County, Texas.~~

The lease agreement for the acreage in Kenedy County, Texas includes a contractual requirement for the Company to spend a minimum of $4 million to make permanent improvements over the ten year life of the lease. The lease agreement does not specify the timing for such improvements to be made within the lease term. The Company has the right to terminate the lease obligation without penalty at any time with nine months advanced written notice and payment of any accrued leasehold expenses.position.

Volume Commitments

As is common in our industry, the Company is party to certain oil and natural gas gathering and transportation

and natural gas processing agreements that obligate us to deliver a specified volume of production over a defined time horizon. If not fulfilled, the Company is subject to deficiency payments. As of March 31, ~~2018,~~2019, the Company had approximately ~~$549.7~~$437.7 million in future commitments related to oil and natural gas gathering and transportation agreements ($~~207.4~~172.3 million for ~~2018~~2019 through ~~2020, $178.3~~2021, $128.8 million from ~~2021~~2022 through ~~2023,~~2024, and ~~$164~~$136.6 million under commitments expiring after December 31, ~~2023,~~2024, in the aggregate) and approximately ~~$183.8~~$52.0 million in future commitments related to natural gas processing agreements ($~~85.4~~51.3 million for ~~2018~~2019 through ~~2020, $36.3~~2021, and $0.7 million from ~~2021~~2022 through ~~2023, and $62.1 expiring after December 31, 2023)~~2024) that are not recorded in the accompanying condensed consolidated balance sheets.

For the three months ended March 31, 2019 and 2018, the Company incurred expenses related to deficiency fees of approximately $1.3 million and $0.6 million, respectively, that are reported on the condensed consolidated statements of operations in the ~~"Oil~~“Oil and natural gas production ~~expenses"~~expenses” line item. We expect to have additional expenses in ~~2018~~2019 related to our volume ~~commitments.~~commitments in connection with our reduced capital activity during the year.

Note 18. Condensed Consolidating Financial Information

The Company’s 7.75% Notes and 6.125% Notes have been registered with the SEC and are guaranteed by all of the Company’s subsidiaries, except for SN UR Holdings, LLC, SN Services, LLC, SN Terminal, LLC, SN Midstream, LLC, SN Comanche Manager, LLC, SN EF UnSub GP, LLC, SN EF UnSub Holdings, LLC, SN UnSub, SN Capital, LLC, Sanchez Resources, LLC, SR Acquisition I, LLC, SR Acquisition III, LLC and SR TMS, LLC which are unrestricted subsidiaries of the Company. As of March 31, 2019 such guarantor subsidiaries were 100 percent owned by the Company and the guarantees by these subsidiaries are full and unconditional (except for customary release provisions) and are joint and several.

Rule 3-10 of Regulation S-X requires that, in lieu of providing separate financial statements for subsidiary guarantors, condensed consolidating financial information be provided where the subsidiaries have guaranteed the debt of a registered security, where the guarantees are full, unconditional and joint and several and where the voting interest of the subsidiaries are 100% owned by the registrant.

The Company has no assets or operations independent of its subsidiaries and there are no significant restrictions upon the ability of its subsidiary guarantors to distribute funds to the Company by dividends or loans.

The following is a presentation of condensed consolidating financial information on a parent company, combined guarantor subsidiaries, combined non-guarantor subsidiaries and consolidated basis (in thousands) in accordance with Rule 3-10 of Regulation S-X and should be read in conjunction with the condensed consolidated financial statements. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had such guarantor subsidiaries operated as independent entities.

Investments in subsidiaries are accounted for by the respective parent company using the equity method for purposes of this presentation. Results of operations of subsidiaries are, therefore, reflected in the parent company’s investment accounts and earnings. The principal elimination entries set forth below eliminate investments in subsidiaries and intercompany balances and transactions. Typically in a condensed consolidating financial statement, the net income and equity of the parent company equals the net income and equity of the consolidated entity.

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~~Note 18. Revenue Recognition~~

~~Adoption of Topic 606~~

Effective January 1, 2018, we adopted the new accounting standard ASC 606, Revenue from Contracts with Customers, and all the related amendments (collectively referred to as “Topic 606”) to all open contracts using the modified retrospective method. We recognized the cumulative effect of initially applying the new revenue standard as an adjustment to the opening balance of retained earnings. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods.

~~For contracts that were modified before the beginning~~A summary of the ~~earliest reporting period presented, we elected to use a practical expedient permitted under~~condensed consolidated guarantor balance sheets for the rules of adoption whereby contracts do not need to be retrospectively restated for contract modifications. Instead, we have reflected the aggregate effect of all modifications that occur before the beginning of the earliest period presented.

Adoption of this guidance resulted in the derecognition of $16.3 million in deferred gains recorded under the Carnero Gathering Disposition and Carnero Processing Disposition and the recognition of a $6.4 million derivative asset in the value of the earnout provision owed to us by SNMP with a $22.7 million decrease to accumulated deficit as of January 1, 2018. The derivative asset was marked to market as ofperiods ended March 31, 2019 and December 31, 2018 ~~and incurred an approximate $273 thousand gain as a result.~~

~~The cumulative effect of the changes made to our consolidated January 1, 2018 condensed consolidated balance sheet for the adoption of Topic 606 were as follows~~is presented below (in thousands):

As of

Adjustments Due

As of
Balance Sheet

December 31, 2017

to ASC 606

January 1, 2018
Assets

Fair value of derivative instruments

$
16,430

$
150

$
16,580
Total current assets

350,798

150

350,948
Fair value of derivative instruments

1,428

6,251

7,679
Total assets

$
2,470,635

$
6,401

$
2,477,036
Liabilities

Other liabilities

$
65,480

$
(16,338)

$
49,142
Total liabilities

2,512,263

(16,338)

2,495,925
Equity

Accumulated deficit

(1,832,156)

22,739

(1,809,417)
Total stockholders' deficit

(469,140)

22,739

(446,401)
Total liabilities and stockholders' deficit

$
2,470,635

$
6,401

$
2,477,036


	March 31, 2019
Assets	Parent Company		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Total current assets	$	400,705	$	155,396	$	123,731	$	(341,274)	$	338,558
Total oil and natural gas properties, net		59		1,561,791		746,118		—		2,307,968
Investment in subsidiaries		1,571,237		—		(7,280)		(1,563,957)		—
Other assets		47,578		303,095		49,364		—		400,037
Total Assets	$	2,019,579	$	2,020,282	$	911,933	$	(1,905,231)	$	3,046,563

Liabilities and Stockholders' Equity
Current liabilities	$	160,396	$	366,802	$	206,234	$	(341,274)	$	392,158
Long term liabilities		2,232,143		228,396		208,792		—		2,669,331
Mezzanine equity		—		—		472,361		—		472,361
Total stockholders' equity (deficit)		(372,960)		1,425,084		24,546		(1,563,957)		(487,287)
Total Liabilities and Stockholders' Equity (Deficit)	$	2,019,579	$	2,020,282	$	911,933	$	(1,905,231)	$	3,046,563

~~Revenue from Contracts with Customers~~

Beginning in 2018, we account for revenue from contracts with customers in accordance with Topic 606. The unit of account in Topic 606 is a performance obligation, which is a promise in a contract to transfer to a customer either a distinct good or service (or bundle of goods or services) or a series of distinct goods or services provided over a period of time. Topic 606 requires that a contract’s transaction price, which is the amount of consideration to which an entity expects to be entitled in exchange for transferring promised goods or services to a customer, is to be allocated to each performance obligation in the contract based on relative standalone selling prices and recognized as revenue when (point in time) or as (over time) the performance obligation is satisfied.

Topic 606 provides additional clarification related to principal versus agent considerations. We enter into marketing agreements with our non-operating partners to market and sell their share of production to third parties. We have determined that we act as an agent in such arrangements and account for such arrangements on a net basis.


	December 31, 2018
Assets	Parent Company		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Total current assets	$	473,062	$	69,934	$	146,765	$	(316,780)	$	372,981
Total oil and natural gas properties, net		36		1,600,378		758,711		—		2,359,125
Investment in subsidiaries		1,577,054		—		(7,280)		(1,569,774)		—
Other assets		22,917		10,307		54,630		—		87,854
Total Assets	$	2,073,069	$	1,680,619	$	952,826	$	(1,886,554)	$	2,819,960

Liabilities and Stockholders' Equity
Current liabilities	$	155,396	$	282,719	$	226,964	$	(316,780)	$	348,299
Long term liabilities		2,203,546		51,211		208,599		—		2,463,356
Mezzanine equity		—		—		452,828		—		452,828
Total stockholders' equity (deficit)		(285,873)		1,346,689		64,435		(1,569,774)		(444,523)
Total Liabilities and Stockholders' Equity (Deficit)	$	2,073,069	$	1,680,619	$	952,826	$	(1,886,554)	$	2,819,960

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~~Disaggregation~~A summary of ~~Revenue~~

~~We recognized revenue~~the condensed consolidated guarantor statements of ~~$251.2 million~~operations for the ~~three months~~periods ended March 31, ~~2018. We disaggregate revenue in our income statement based on product type,~~2019 and ~~we further disaggregate our revenue related to sales and marketing revenue.~~2018 is presented below (in thousands):


	Three Months Ended March 31, 2019
	Parent Company		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Total revenues	$	—	$	151,528	$	65,194	$	—	$	216,722
Total operating costs and expenses		(15,708)		(120,360)		(56,167)		135		(192,100)
Other income (expense)		(59,823)		68		(31,638)		(135)		(91,528)
Income (loss) before income taxes		(75,531)		31,236		(22,611)		—		(66,906)

Income tax expense		436		—		—		—		436
Equity in income (loss) of subsidiaries		8,625		—		—		(8,625)		—
Net income (loss)	$	(67,342)	$	31,236	$	(22,611)	$	(8,625)	$	(67,342)

~~In selecting~~


	Three Months Ended March 31, 2018
	Parent Company		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Total revenues	$	—	$	167,488	$	83,740	$	—	$	251,228
Total operating costs and expenses		(15,531)		(82,666)		(74,178)		136		(172,239)
Other income (expense)		(66,767)		503		(17,404)		(136)		(83,804)
Income (loss) before income taxes		(82,298)	$	85,325	$	(7,842)	$	—	$	(4,815)

Equity in income (loss) of subsidiaries		77,484		—		—		(77,484)		—
Net income (loss)	$	(4,814)	$	85,325	$	(7,842)	$	(77,484)	$	(4,815)

A summary of the ~~disaggregation categories, we considered a number~~condensed consolidated guarantor statements of factors, including disclosures presented outside the financial statements, such as in our earnings release and investor presentations, information reviewed internally for evaluating performance, and other factors used by the Company or the users of its financial statements to evaluate performance or allocate resources. As such, we have concluded that disaggregating revenue by product type appropriately depicts how the nature, amount, timing, and uncertainty of revenue and cash flows ~~are affected by economic factors.~~for the periods ended March 31, 2019 and 2018 is presented below (in thousands):


	Three Months Ended March 31, 2019
	Parent Company		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Net cash provided by (used in) operating activities	$	(69,395)	$	158,774	$	(23,221)	$	—	$	66,158
Net cash provided by (used in) investing activities		38,452		(46,063)		(19,087)		(33,484)		(60,182)
Net cash provided by (used in) financing activities		(5)		(92,028)		55,658		33,484		(2,891)
Net increase (decrease) in cash and cash equivalents		(30,948)		20,683		13,350		—		3,085
Cash and cash equivalents, beginning of period		68,762		58,429		70,422		—		197,613
Cash and cash equivalents, end of period	$	37,814	$	79,112	$	83,772	$	—	$	200,698

~~Oil, Natural Gas, and NGL Revenues~~

We recognize revenue from the sale of oil, natural gas and NGLs in the period that the performance obligations are satisfied. Our performance obligations are primarily comprised of the delivery of oil, gas, or NGLs at a delivery point. Each barrel of oil, MMBtu of natural gas, or other unit of measure is separately identifiable and represents a distinct performance obligation to which the transaction price is allocated. Performance obligations are satisfied at a point in time once control of the product has been transferred to the customer through monthly delivery of oil, natural gas and NGLs.

Under our natural gas sales contracts, we deliver natural gas to the purchaser at an agreed upon delivery point. Natural gas is transported from our wellheads to delivery points specified under sales contracts. To deliver natural gas to these points, third parties gather, process and transport our natural gas. We maintain control of the natural gas during gathering, processing, and transportation. We transfer control of the product at the delivery point and recognize revenue based on the contract price. The costs to gather, process and transport the natural gas are recorded as Oil and natural gas production expenses.

NGLs, which are extracted from natural gas through processing, are either sold by us directly or by the processor under processing contracts. For NGLs sold by us directly, we transfer control of the product to the purchaser at the delivery point and recognize revenue based on the contract price. The costs to further process and transport NGLs are recorded as Oil and natural gas production expenses. For NGLs sold by the processor, our processing contracts provide that we transfer control to the processor at the tailgate of the processing plant and we recognize revenue based on the price received from the processor.

Our contracts with customers typically require payment for oil and condensate, gas and NGL sales within 30 days following the calendar month of delivery. The sales of oil and condensate, gas and NGLs typically include variable consideration that is based on pricing tied to local indices adjusted for differentials and volumes delivered in the current month. Revenues include estimates for the two most recent months using published commodity price indexes and volumes supplied by field operators.

~~Sales and Marketing Revenue~~

Beginning in the first quarter of 2018, we entered into commodity purchase transactions with third parties and then subsequently sold the purchased commodity as separate revenue streams. These purchase contracts were entered into to utilize existing firm transportation arrangements. We retain control of the purchased hydrocarbons prior to delivery to the purchaser. The Company has concluded that we are the principal in these arrangements and therefore we recognize revenue on a gross basis as Sales and Marketing Revenues within our condensed consolidated statement of operations, with costs to purchase and transport the commodity presented as Sales and Marketing Expenses in our condensed consolidated statement of operations. Contracts to sell the third party hydrocarbons are the same contracts as those for which we sell our produced hydrocarbons, and as such, we do not recognize this revenue any differently than our oil, natural gas, and NGL revenue discussed previously.

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~~Remaining Performance Obligations~~

Several of our sales contracts contain multiple performance obligations as each barrel of oil, MMBtu of natural gas, or other unit of measure is separately identifiable. For these contracts, we have taken the optional exception under ASC 606-10-50-14A(b) which is available only for wholly unsatisfied performance obligations for which the criteria in ASC 606-10-32-40 have been met. Under this exception, neither estimation of variable consideration nor disclosure of the transaction price allocated to the remaining performance obligations is required. Revenue is alternatively recognized in the period that the control of the commodity is transferred to the customer and the respective variable component of the total transaction price is resolved.

For forms of variable consideration that are not associated with a specific volume and thus do not meet the allocation exception, estimation is required. Examples of such variable consideration consist of deficiency payments, late payment fees, truck rejection charges, inflation adjustments, and imbalance penalties, however, these items are immaterial to our consolidated financial statements and/or have a low probability of occurrence. As significant reversals of revenue due to this variability are not probable, no estimation is required.

~~Contract Balances~~

Under our sales contracts, we invoice customers after our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our contracts do not give rise to contract assets or liabilities under Topic 606. At March 31, 2018 and December 31, 2017, our receivables from contracts with customers were $86.0 million and $101.4 million, respectively.

~~Reconciliation of Condensed Consolidated Balance Sheet~~

~~In accordance with the new revenue standard requirements, the disclosure of the impact of adoption on our condensed consolidated balance sheet is as follows (in thousands):~~

As of March 31, 2018

Balances without

Effect of change

Balance Sheet

Adoption ASC 606

higher/(lower)

As Reported
Assets

Fair value of derivative instruments

$
12,013

$
6

$
12,019
Total current assets

686,465

6

686,471
Fair value of derivative instruments

2,110

6,668

8,778
Total assets

$
2,897,168

$
6,674

$
2,903,842
Liabilities

Other liabilities

$
55,547

$
(16,338)

$
39,209
Total liabilities

2,953,601

(16,338)

2,937,263
Equity

Accumulated deficit

(1,857,069)

23,012

(1,834,057)
Total stockholders' deficit

(489,875)

23,012

(466,863)
Total liabilities and stockholders' deficit

$
2,897,168

$
6,674

$
2,903,842


	Three Months Ended March 31, 2018
	Parent Company		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Net cash provided by (used in) operating activities	$	(67,504)	$	112,330	$	39,693	$	—	$	84,519
Net cash provided by (used in) investing activities		27,660		(120,976)		(12,270)		(27,660)		(133,246)
Net cash provided by (used in) financing activities		428,331		(20,400)		(21,254)		27,660		414,337
Net increase (decrease) in cash and cash equivalents		388,487	$	(29,046)	$	6,169	$	—	$	365,610
Cash and cash equivalents, beginning of period		86,937		29,046		68,451		—		184,434
Cash and cash equivalents, end of period	$	475,424	$	—	$	74,620	$	—	$	550,044

~~Table of Contents~~

~~Reconciliation of Condensed Consolidated Statement of Operations~~

~~In accordance with the new revenue standard requirements, the disclosure of the impact of adoption on our condensed consolidated statement of operations is as follows (in thousands):~~

Three months ended March 31, 2018

Balances without

Effect of change

Adoption ASC 606

higher/(lower)

As Reported
Statement of Operations

Other income (expense)

$
3,155

$
273

$
3,428
Total other income (expense)

(84,077)

273

(83,804)
Income (loss) before income taxes

(5,088)

273

(4,815)
Net income (loss)

$
(5,088)

$
273

$
(4,815)

~~We expect the impact of the adoption of the new standard to be immaterial to our net income on an ongoing basis.~~

~~Note 19. Condensed Consolidating Financial Information~~

The Company’s 7.75% Notes and 6.125% Notes have been registered with the SEC and are guaranteed by all of the Company’s subsidiaries, except for SN UR Holdings, LLC, SN Services, LLC, SNT, SN Midstream, Manager, SN UnSub General Partner, SN UnSub Holdings, SN UnSub, SN Capital, LLC, Sanchez Resources, SR Acquisition III, LLC and SR TMS, LLC which are unrestricted subsidiaries of the Company. As of March 31, 2018 such guarantor subsidiaries are 100 percent owned by the Company and the guarantees by these subsidiaries are full and unconditional (except for customary release provisions) and are joint and several.

The following is a presentation of condensed consolidating financial information on a parent company, combined guarantor subsidiaries, combined non-guarantor subsidiaries and consolidated basis (in thousands) in accordance with Rule 3-10 of Regulation S-X and should be read in conjunction with the consolidated financial statements. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had such guarantor subsidiaries operated as independent entities.

~~Table of Contents~~

~~A summary of the condensed consolidated guarantor balance sheets for the periods ended March 31, 2018 and December 31, 2017 is presented below (in thousands):~~

March 31, 2018
Assets

Parent Company

Combined Guarantor Subsidiaries

Combined Non-Guarantor Subsidiaries

Eliminations

Consolidated
Total current assets

$
740,776

$
166,811

$
121,254

$
(342,370)

$
686,471
Total oil and natural gas properties, net

121,633

1,240,443

756,997

-

2,119,073
Investment in subsidiaries

1,148,093

-

(7,280)

(1,140,813)

-
Other assets

10,563

10,212

77,523

-

98,298
Total Assets

$
2,021,065

$
1,417,466

$
948,494

$
(1,483,183)

$
2,903,842

Liabilities and Shareholders' Equity

Current liabilities

$
200,817

$
355,358

$
260,451

$
(342,369)

$
474,257
Long-term liabilities

2,206,707

62,755

193,544

-

2,463,006
Mezzanine equity

-

-

433,442

-

433,442
Total shareholders' equity (deficit)

(386,459)

999,353

61,057

(1,140,814)

(466,863)
Total Liabilities and Shareholders' Equity (deficit)

$
2,021,065

$
1,417,466

$
948,494

$
(1,483,183)

$
2,903,842

December 31, 2017
Assets

Parent Company

Combined Guarantor Subsidiaries

Combined Non-Guarantor Subsidiaries

Eliminations

Consolidated
Total current assets

$
447,984

$
98,758

$
117,031

$
(312,975)

$
350,798
Total oil and natural gas properties, net

3,987

1,275,153

748,319

-

2,027,459
Investment in subsidiaries

1,081,692

-

(7,280)

(1,074,412)

-
Other assets

25,451

4,415

62,512

-

92,378
Total Assets

$
1,559,114

$
1,378,326

$
920,582

$
(1,387,387)

$
2,470,635

Liabilities and Shareholders' Equity

Current liabilities

$
212,026

$
312,531

$
250,946

$
(312,975)

$
462,528
Long-term liabilities

1,827,072

26,787

195,876

-

2,049,735
Mezzanine equity

-

-

427,512

-

427,512
Total shareholders' equity (deficit)

(479,984)

1,039,008

46,248

(1,074,412)

(469,140)
Total Liabilities and Shareholders' Equity (deficit)

$
1,559,114

$
1,378,326

$
920,582

$
(1,387,387)

$
2,470,635

~~Table of Contents~~

~~A summary of the condensed consolidated guarantor statements of operations for the periods ended March 31, 2018 and 2017 is presented below (in thousands):~~

Three Months Ended March 31, 2018

Parent Company

Combined Guarantor Subsidiaries

Combined Non-Guarantor Subsidiaries

Eliminations

Consolidated
Total revenues

$
-

$
167,488

$
83,740

$
-

$
251,228
Total operating costs and expenses

(15,531)

(82,666)

(74,178)

136

(172,239)
Other income (expense)

(66,767)

503

(17,404)

(136)

(83,804)
Income (loss) before income taxes

$
(82,298)

$
85,325

$
(7,842)

$
-

$
(4,815)

Income tax benefit (expense)

-

-

-

-

-
Equity in income (loss) of subsidiaries

77,484

-

-

(77,484)

-
Net income (loss)

$
(4,814)

$
85,325

$
(7,842)

$
(77,484)

$
(4,815)

Three Months Ended March 31, 2017

Parent Company

Combined Guarantor Subsidiaries

Combined Non-Guarantor Subsidiaries

Eliminations

Consolidated
Total revenues

$
-

$
111,828

$
22,015

$
-

$
133,843
Total operating costs and expenses

(64,572)

(54,605)

(21,911)

500

(140,588)
Other income (expense)

(11,236)

5,115

28,148

(500)

21,527
Income (loss) before income taxes

$
(75,808)

$
62,338

$
28,252

$
-

$
14,782

Income tax benefit (expense)

1,190

-

(237)

-

953
Equity in income (loss) of subsidiaries

83,634

-

-

(83,634)

-
Net income (loss)

$
9,016

$
62,338

$
28,015

$
(83,634)

$
15,735

~~A summary of the condensed consolidated guarantor statements of cash flows for the periods ended March 31, 2018 and 2017 is presented below (in thousands):~~

Three Months Ended March 31, 2018

Parent Company

Combined Guarantor Subsidiaries

Combined Non-Guarantor Subsidiaries

Eliminations

Consolidated
Net cash provided by (used in) operating activities

$
(67,504)

$
112,330

$
39,693

$
-

$
84,519
Net cash provided by (used in) investing activities

27,660

(120,976)

(12,270)

(27,660)

(133,246)
Net cash provided by (used in) financing activities

428,331

(20,400)

(21,254)

27,660

414,337
Net increase (decrease) in cash and cash equivalents

$
388,487

$
(29,046)

$
6,169

$
-

$
365,610
Cash and cash equivalents, beginning of period

86,937

29,046

68,451

-

184,434
Cash and cash equivalents, end of period

$
475,424

$
-

$
74,620

$
-

$
550,044

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Three Months Ended March 31, 2017

Parent Company

Combined Guarantor Subsidiaries

Combined Non-Guarantor Subsidiaries

Eliminations

Consolidated
Net cash provided by (used in) operating activities

$
(96,053)

$
61,965

$
20,400

$
-

$
(13,688)
Net cash provided by (used in) investing activities

(297,242)

(369,853)

(750,065)

289,751

(1,127,409)
Net cash provided by (used in) financing activities

109,661

307,888

635,967

(289,751)

763,765
Net increase (decrease) in cash and cash equivalents

$
(283,634)

$
-

$
(93,698)

$
-

$
(377,332)
Cash and cash equivalents, beginning of period

343,941

-

157,976

-

501,917
Cash and cash equivalents, end of period

$
60,307

$
-

$
64,278

$
-

$
124,585

Note ~~20.~~19. Variable Interest Entities

During the first quarter of 2016, the Company adopted ASU 2015-02, “Consolidation—Amendments to the Consolidation Analysis,” which introduces a separate analysis for determining if limited partnerships and similar entities are variable interest entities (“VIEs”) and clarifies the steps a reporting entity would have to take to determine whether the voting rights of stockholders in a corporation or similar entity are substantive.

As noted previously in Note 9, “Investments,” pursuant to the LLC Agreement of GRHL, GRHL authorized and issued a total of 100 Class A Units to SN Comanche Manager. Although the Company did not pay any cash for the Class A Units, theThe Company’s investment in GRHL represents a VIE that could expose the Company to losses limited to the estimated fair value of the investment. The carrying amounts of the investment in GRHL, and the Company’s maximum exposure to loss as of March 31, 2019 and December 31, 2018, was approximately $7.3 million. The Company did not record any earnings from its ownership of the Class A Units for the period from ~~March~~January 1, ~~2017~~2018 through March 31, ~~2018.~~2019. The Company determined that Blackstone is the primary beneficiary of the VIE as the Company has no significant voting rights in GRHL under the LLC Agreement and no power over decisions related to the business activities of GRHL, other than operation of the properties.

As noted above in Note 9, “Investments,” the Company, via SN Catarina, purchased from a subsidiary of Targa a 10% undivided interest in the SOII Facility in 2015. The Company determined that ownership in the SOII Facility is more similar to limited partnerships than corporations. Under the revised guidance of ASU 2015-02, a limited partnership or similar entity with equity at risk will not be a VIE if they are able to exercise kick-out rights over the general partner(s) or they are able to exercise substantive participating rights. On June 14, 2017, SN Catarina completed the SOII Disposition for $12.5 million in cash. Prior to the SOII Disposition, we concluded that the investment in SOII Facility is a VIE under the revised guidance because we cannot remove Targa as operator and we do not have substantive participating rights. In addition, Targa has the discretion to direct activities of the VIEs regarding the risks associated with price, operations, and capital investment which have the most significant impact on the VIEs economic performance.

The Company had previously accounted for the VIE as an equity method investment and determined that Targa is the primary beneficiary of the VIE as Targa is the operator of the SOII Facility and has the most influence with respect to the normal day-to-day operating decisions of the facility. Prior to the sale, we included the VIE in the “Other Assets - Investments” long-term asset line on the balance sheet.

As noted above in Note 9, “Investments,” in November 2016, the Company purchased common units of SNMP for $25.0 million as part of a private equity issuance. Rather than accounting for the investment under the equity method, the Company elected the fair value option to account for its interest in SNMP. The Company’s investment in SNMP represents a VIE that could expose the Company to losses limited to the equity in the investment at any point in time. The carrying amounts of the investment in SNMP, and the Company’s maximum exposure to loss as of March 31, 2019 and December 31, 2018, was approximately ~~$23.5 million.~~$4.9 million and $3.9 million, respectively.

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Below is a tabular comparison of the carrying amounts of the assets and liabilities of the VIE and the Company’s maximum exposure to loss as of March 31, ~~2018~~2019 and December 31, ~~2017~~2018 (in thousands):

March 31,

December 31,

2018

2017
Beginning Balance

$
32,507

$
39,656
Initial investment in GRHL

—

7,280
Distributions from equity investments

—

(311)
Loss from change in fair value of investment in SNMP

(1,704)

(1,591)
Sale of investments

—

(12,527)
Maximum exposure to loss

$
30,803

$
32,507


	March 31,		December 31,
	2019		2018
Beginning balance	$	11,189	$	32,507
Gain (loss) from change in fair value of investment in SNMP		977		(21,318)
Maximum exposure to loss	$	12,166	$	11,189

Note 20. Subsequent Events

SN UnSub Debt Repayment

On April 23, 2019 and May 1, 2019, SN UnSub made repayments under the SN UnSub Credit Agreement of $3.0 million and $3.0 million, respectively, resulting in an outstanding principal balance of $159.0 million.

~~Note 21. Subsequent Events~~

~~On April 20,~~

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our condensed consolidated financial statements and related notes appearing in Part I, Item 1 of this Quarterly Report on Form 10‑Q and information contained in our 2018 ~~SN UnSub made~~Annual Report. The following discussion contains “forward‑looking statements” that reflect our future plans, estimates, beliefs and expected performance. Please see “Cautionary Note Regarding Forward‑Looking Statements.”

Business Overview

Sanchez Energy Corporation (together with our consolidated subsidiaries, “Sanchez Energy,” the “Company,” “we,” “our,” “us” or similar terms), a ~~repayment on the SN UnSub Credit Agreement of $4.0 million, resulting~~Delaware corporation formed in ~~a carrying amount of $167.5 million.~~

August 2011, is an independent exploration and

5538

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production company focused on the acquisition and development of oil and natural gas resources in the onshore United States. We are currently focused on the horizontal development of significant resource potential from the Eagle Ford Shale in South Texas, and we also hold other producing properties and undeveloped acreage, including in the Tuscaloosa Marine Shale (“TMS”) in Mississippi and Louisiana which offers potential future development opportunities. As of March 31, 2019, we have assembled approximately 466,000 gross (264,000 net) leasehold acres in the Eagle Ford Shale, where we plan to invest the majority of our 2019 capital budget. We continually evaluate opportunities to manage our overall portfolio, which may include the acquisition of additional properties in the Eagle Ford Shale or other producing areas and, from time to time, the divestiture of non-core assets. Our successful acquisition of such properties will depend on the circumstances and the financing alternatives available to us at the time we consider such opportunities. However, at this time we are primarily focused on lowering cash costs across our business and reducing our financial leverage, with an objective of maximizing our liquidity position and improving our balance sheet. We are also pursuing a number of strategic alternatives to better align our capital structure with the current low commodity price environment; however, we cannot provide any assurances that any of these alternatives will be completed on terms acceptable to us, on a timely basis, or at all. In addition, the market for acquisition and divestiture of oil and natural gas assets has slowed significantly, and this reduced transaction activity level, combined with continued challenging conditions in the credit and capital markets, among other reasons, may make it difficult for us to complete divestitures of non-core assets or pursue other strategic alternatives.

Basis of Presentation

The condensed consolidated financial statements have been prepared in accordance with U.S. GAAP.

Core Properties

Eagle Ford Shale

We and our predecessor entities have a long history in the Eagle Ford Shale where we have assembled approximately 466,000 gross (264,000 net) leasehold acres and have 4,372 gross (2,121 net) specifically identified potential future drilling locations. As of March 31, 2019, 959 of these drilling locations represented PUDs and were evaluated using existing geologic and engineering data. Although the approximately 3,413 gross additional non-proved locations identified by our management were determined using the same geologic and engineering methodology as those locations to which proved reserves are attributed, they fail to satisfy all criteria for proved reserves for reasons such as development timing, economic viability at Securities and Exchange Commission (“SEC”) pricing and production volume certainty. In evaluating and determining those locations, we also considered the availability of local infrastructure, drilling support assets, property restrictions and state and local regulations. The Company updates its estimate of identified potential future drilling locations from time to time based on various factors, including actual results from recently drilled and completed wells, changes in well-spacing strategies and other observed performance and operating trends. We may increase or decrease our estimated inventory of potential future drilling locations as appropriate based on additional information and performance data. Our estimate of potential future drilling locations was derived based on evaluations designed to optimize the value of our oil and natural gas properties and the efficiency of our multi-year development program and is not intended to represent an actual forecast or limitation in the number of locations that may be drilled. The locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results and other factors, and may differ from the locations currently identified. With our limited capital budget for 2019 (or if we do not increase our capital expenditures budget in 2020), many of our identified drilling locations may be uneconomic at current or projected prices. For the year 2019, we plan to invest the majority of our capital budget in the Eagle Ford Shale.

In 2017, we acquired approximately 252,000 gross (61,000 net) acres in Dimmit, Webb, La Salle, Zavala and Maverick counties, Texas (the “Comanche Acquisition”), representing a 24% working interest in the asset, which we refer to as the Comanche area. We have identified approximately 2,782 gross (676 net) Eagle Ford locations for potential future drilling in our Comanche area.

In the Comanche area, we have a development commitment that, in addition to other requirements in the leases that must be met in order to maintain our acreage position, requires us to complete and equip 60 wells in each annual period commencing on September 1, 2017 and continuing thereafter until September 1, 2022 or pay a penalty for the failure to do so. Up to 30 wells completed and equipped in excess of the annual 60-well requirement can be carried over to satisfy part of the 60-well requirement in subsequent annual periods on a well-for-well basis. As of August 31, 2018,

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the Company had achieved a 30-well bank at Comanche that can be applied toward its current annual development commitment for the period that extends from September 1, 2018 to August 31, 2019. The Company completed and equipped an additional 45 wells at Comanche between September 1, 2018 and March 31, 2019, resulting in a total of 75 wells that can be applied toward the current annual development commitment of 60 wells. Accordingly, the Company has met its annual development commitment for the period September 1, 2018 to August 31, 2019. We currently intend to drill at least the minimum number of wells required to satisfy the development agreement and to comply with applicable lease requirements necessary to maintain our Comanche acreage position. SN Maverick is currently engaged in a disagreement with Gavilan, an entity controlled by Blackstone, regarding operations of the Comanche Assets under the joint development agreement with Gavilan (the “JDA”). Among other things, Gavilan has asserted that SN Maverick is in default of the JDA and Gavilan has the right to take over operations of the Comanche Assets. Although SN Maverick disputes Gavilan’s assertions and has asserted defenses to the allegations and its own counterclaims against Gavilan, if Gavilan prevails in the disagreement, SN Maverick would lose its rights to operate the Comanche Assets and certain rights of SN Maverick under the JDA, including the ability to vote or appoint representatives to the operating committee or to transfer the Comanche Assets, among others. Furthermore, Gavilan has attempted to initiate a division of operatorship under the JDA pursuant to which operatorship of the Comanche Assets would be divided between Gavilan (or a third-party operator) and SN Maverick in accordance with certain procedures specified in the JDA. Arbitration regarding this dispute was initiated by Gavilan with the American Arbitration Association on February 18, 2019, seeking, among other things, a declaration that SN Maverick is in default under the JDA, and the Company submitted its answer and counterclaims on February 26, 2019 seeking, among other things, a declaration that Gavilan is in default under the JDA. Loss of operatorship of some portion or all of the Comanche Assets, or a finding that SN Maverick is in default under the JDA, would have a material adverse effect on our business, financial condition or results of operations.

We have approximately 106,000 net acres in Dimmit, La Salle and Webb counties, Texas representing a 100% working interest, which we refer to as the Catarina area. We have identified approximately 575 gross (575 net) locations for potential future drilling in our Catarina area.

In the Catarina area, we have a drilling commitment that requires us to drill (i) 50 wells in each 12-month period commencing on July 1, 2014 and (ii) at least one well in any consecutive 120‑day period, in order to maintain rights to any future undeveloped acreage. Up to 30 wells drilled in excess of the minimum 50 wells in a given annual period can be carried over to satisfy part of the 50-well requirement in the subsequent 12-month period on a well-for-well basis. As of June 30, 2018, the Company achieved a 26-well drilling bank at Catarina that can be applied toward its current annual drilling commitment for the period that extends from July 1, 2018 to June 30, 2019. The Company drilled an additional 36 wells between July 1, 2018 and March 31, 2019 at Catarina, resulting in a total of 62 wells toward the current annual drilling commitment of 50 wells. Accordingly, the Company has met all of its 50-well annual drilling commitment for the period July 1, 2018 to June 30, 2019 and has initiated a bank of 12 wells that may be counted toward the next annual drilling commitment period, which begins on July 1, 2019. The Company’s 2019 capital budget and plans include the additional activity needed to fulfill the commitment to drill at least one well in any 120-day period.

We have approximately 89,000 net acres in Dimmit, Frio, La Salle, and Zavala counties, Texas, which we refer to as the Maverick area, which we believe lies in the black oil window. We have identified approximately 790 gross (760 net) locations for potential future drilling in our Maverick area.

We have approximately 7,600 net acres in Gonzales County, Texas, which we refer to as the Palmetto area, which we believe lies in the volatile oil window. We have identified approximately 225 gross (110 net) locations for potential future drilling in our Palmetto area.

Tuscaloosa Marine Shale

As of December 31, 2018, we owned approximately 34,000 net acres in the TMS. Although TMS development is currently challenged due to well costs and commodity prices, we believe that the TMS play has significant future development potential as changes in technology, commodity prices and service costs occur.

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Recent Developments

2019 Capital Program

The Company has set its 2019 capital budget at a range of $100 million to $150 millionfor development and optimization activities in our core areas, which represents a substantial reduction from capital expenditures of approximately $593 million in 2018. We seek to remain flexible in our business strategy to make changes to this estimated capital budget as the commodity markets and our overall financial and business position evolve over time.

Management Appointments

On March 19, 2019, the Board appointed Cameron W. George, the Company’s previous Interim Chief Financial Officer, to serve as Executive Vice President and Chief Financial Officer. In addition, the Board appointed Gregory B. Kopel, the Company’s previous Senior Vice President, General Counsel and Secretary, to serve as Executive Vice President, General Counsel and Secretary, also effective as of March 19, 2019.

Outlook

We and other companies in our industry face significant risks related to business operations, the prices we receive for our production, competition for employees and capital, and other factors which could materially impact our results of operations and financial condition. During recent months, our oil and natural gas production has fallen short of expectations due to a number of contributing factors, including the impacts of certain activities designed and implemented to evaluate various reservoir stimulation and hydrocarbon flowback strategies and appraisal initiatives to assess the productivity of certain horizons in the Eagle Ford Shale, in consultation with certain of our working interest partners. We have taken responsive actions to address these operational challenges and anticipate a return to more predictable production levels. Additionally, in response to a prolonged period of commodity price volatility and to meet certain minimum hedging requirements in our debt agreements, we took advantage of market opportunities in recent years to hedge a significant percentage of our oil and natural gas production for 2018 at prices of approximately $52 per Bbl for oil and $3 per MMBtu for natural gas. However, oil prices recovered to substantially higher levels during the first three quarters of 2018 and our hedge position limited the positive impact we received from the more favorable market prices. We are hedged to a lower extent in 2019 and beyond. We believe that a recovery in our operational performance, as well as stronger commodity prices, could improve our overall financial position.

Although commodity and capital markets showed signs of improvement, oil prices experienced a significant decline in the fourth quarter 2018. As a result, we continue to manage our business for the potential of ongoing commodity price volatility. This volatility has significantly influenced our industry and operating environment in the past, and we believe it may again in the future. We face continuing uncertainty with respect to the demand for our products, commodity prices, service availability and costs, and our ability to fund capital projects, along with significant challenges associated with our financial position. In November 2018, we engaged Moelis & Company LLC as financial advisor to explore strategic alternatives to strengthen our balance sheet and maximize the value of the Company. We are currently reviewing our alternatives, and we may adopt strategies that include actions such as a refinancing or restructuring of our indebtedness or capital structure, reducing or delaying capital investments, selling non-core assets or seeking to raise additional capital through debt or equity financing. In addition, the market for acquisition and divestiture of oil and natural gas assets has slowed significantly, and this reduced transaction activity level, combined with continued challenging conditions in the credit and capital markets, among other reasons, may make it difficult for us to complete divestitures of non-core assets or pursue other strategic alternatives.

We currently expect that the Company’s cash flows and cash on hand will be sufficient to fund our anticipated 2019 operating needs, debt service obligations, capital expenditures, and commitments and contingencies. However, if commodity prices decline further, we may be unable to meet our remaining 2019 operating needs, debt service obligations, capital expenditures and commitments and contingencies. We continuously evaluate our current and projected capital spending, operating activities and funding requirements, with consideration of realized commodity prices and the results of our operations, and may make further adjustments to our capital expenditures and related financing plans as warranted. In addition, we periodically review acquisition and divestiture opportunities involving third parties, SNMP and/or other members of the Sanchez Group.

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Results of Operations

Three Months Ended March 31, 2019 Compared to Three Months Ended March 31, 2018

Net Production and Revenues from Production

The following table summarizes production, average sales prices and operating revenue for our oil, NGLs and natural gas operations for the periods indicated (in thousands, except average sales price and percentages):



	Three Months Ended				Increase (Decrease)
	March 31,				2019 vs 2018
	2019		2018		$		%
Net Production:
Oil (MBbls)		2,336		2,521		(185)	(7)	%
Natural gas liquids (MBbls)		2,335		2,406		(71)	(3)	%
Natural gas (MMcf)		13,158		13,950		(792)	(6)	%
Total oil equivalent (MBoe)		6,864		7,251		(387)	(5)	%

Average Sales Price Excluding Derivatives(1):
Oil ($ per Bbl)	$	54.81	$	61.64	$	(6.83)	(11)	%
Natural gas liquids ($ per Bbl)		17.34		20.50		(3.16)	(15)	%
Natural gas ($ per Mcf)		3.27		2.99		0.28	9	%
Oil equivalent ($ per Boe)	$	30.82	$	33.98	$	(3.16)	(9)	%

Average Sales Price Including Derivatives(2):
Oil ($ per Bbl)	$	53.79	$	53.32	$	0.47	1	%
Natural gas liquids ($ per Bbl)		17.34		20.50		(3.16)	(15)	%
Natural gas ($ per Mcf)		3.18		3.09		0.09	3	%
Oil equivalent ($ per Boe)	$	30.31	$	31.27	$	(0.96)	(3)	%

Revenues from Production(1)(3):
Oil sales	$	128,028	$	155,392	$	(27,364)	(18)	%
Natural gas liquids sales		40,500		49,305		(8,805)	(18)	%
Natural gas sales		43,049		41,729		1,320	3	%
Total revenues from production	$	211,577	$	246,426	$	(34,849)	(14)	%

(1)

Excludes the realized impact of derivative instrument settlements.

(2)

Includes the realized impact of derivative instrument settlements.

(3)

Excludes revenues related to sales and marketing activities.

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The following table sets forth information regarding combined net production of oil, NGLs and natural gas attributable to our properties for each of the periods presented:


	Three Months Ended
	March 31,
	2019		2018
Net Production:
Oil (MBbls)
Comanche		1,072		1,206
Catarina		975		773
Maverick		256		485
Palmetto		10		31
TMS / Other		23		26
Total		2,336		2,521
Natural gas liquids (MBbls)
Comanche		882		1,037
Catarina		1,448		1,348
Maverick		2		9
Palmetto		3		12
Total		2,335		2,406
Natural gas (MMcf)
Comanche		4,892		5,737
Catarina		8,234		8,107
Maverick		12		48
Palmetto		20		58
Total		13,158		13,950
Net production volumes:
Total oil equivalent (MBoe)		6,864		7,251
Average daily production (Boe/d)		76,267		80,572
Average sales price (1):
Oil ($ per Bbl)	$	54.81	$	61.64
Natural gas liquids ($ per Bbl)	$	17.34	$	20.50
Natural gas ($ per Mcf)	$	3.27	$	2.99
Oil equivalent ($ per Boe)	$	30.82	$	33.98
Average unit costs per Boe:
Oil and natural gas production expenses	$	11.79	$	9.92
Production and ad valorem taxes	$	1.90	$	1.86
General and administrative expenses	$	2.98	$	3.09
Depreciation, depletion, amortization and accretion	$	9.83	$	8.17
Impairment of oil and natural gas properties	$	0.57	$	0.13

(1)

Excludes the realized impact of derivative instrument settlements.

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Net Production. Production decreased from 7,251 MBoe for the three months ended March 31, 2018 to 6,864 MBoe for the three months ended March 31, 2019, primarily due to the reduction in our drilling and development activity. The number of gross wells producing at the period end and net production for the periods were as follows:


	Three Months Ended March 31,
	2019		2018
	# Wells	MBoe	# Wells	MBoe
Comanche	1,747	2,769	1,644	3,199
Catarina	456	3,795	395	3,472
Palmetto	76	16	84	53
Maverick	67	260	63	502
TMS / Other	50	24	47	25
Total	2,396	6,864	2,233	7,251

For the three months ended March 31, 2019, 34% of our production was oil, 34% was NGLs and 32% was natural gas, compared to the three months ended March 31, 2018 for which 35% of our production was oil, 33% was NGLs and 32% was natural gas. The production mix is relatively consistent between the periods.

Revenues from Production. Sales revenue for oil, NGLs and natural gas totaled $211.5 million and $246.4 million for the three months ended March 31, 2019 and 2018, respectively. Sales revenue for oil, NGLs and natural gas decreased $27.4 million and $8.8 million, and increased $1.3 million, respectively, for the three months ended March 31, 2019 as compared to the three months ended March 31, 2018. The decreases in sales revenue for oil and NGLs were due to decreases in production, as discussed above, as well as decreases in average realized prices. The increase in sales revenue for natural gas is primarily attributable to increased average realized prices for the three months ended March 31, 2019 as compared to the comparable period of 2018.

Sales and Marketing Revenues. The Company recorded sales and marketing revenues of $5.1 million and $4.8 million during the three months ended March 31, 2019 and 2018, respectively. The commodity purchase and sale transactions associated with this revenue stream commenced during the first quarter 2018. We believe an opportunity exists, from time to time, to participate in additional economic benefits and operational efficiencies in support of our upstream activities by purchasing and reselling production from others, to a limited extent, in order to utilize existing firm transportation arrangements. The volumes associated with these activities are variable and, accordingly, the related revenues from these activities are expected to fluctuate from period to period.

The following tables provide an analysis of the impacts of changes in average realized prices and production volumes between the periods on our revenues from production from the three months ended March 31, 2018 to the three months ended March 31, 2019 (in thousands, except average sales price). The decrease in revenue from the three months

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ended March 31, 2018 to the three months ended March 31, 2019 is primarily attributable to the decrease in realized commodity prices for oil and NGLs and the decrease in production volumes.



	Production Volume						Three Months Ended		Revenue
	Three Months Ended March 31,						March 31, 2018		Decrease
	2019		2018		Difference		Average Sales Price		from Production
Oil (MBbls)		2,336		2,521		(185)	$	61.64	$	(11,403)
NGLs (MBbls)		2,335		2,406		(71)	$	20.50	$	(1,455)
Natural gas (MMcf)		13,158		13,950		(792)	$	2.99	$	(2,370)
Total oil equivalent (MBoe)		6,864		7,251		(387)	$	33.98	$	(15,228)


	Average Sales Price per Unit						Three Months Ended		Revenue
	Three Months Ended March 31,						March 31, 2019		Increase/(Decrease)
	2019		2018		Difference		Production Volume		from Price
Oil (MBbls)	$	54.81	$	61.64	$	(6.83)		2,336	$	(15,961)
NGLs (MBbls)	$	17.34	$	20.50	$	(3.16)		2,335	$	(7,350)
Natural gas (MMcf)	$	3.27	$	2.99	$	0.28		13,158	$	3,690
Total oil equivalent (MBoe)	$	30.81	$	33.98	$	(3.17)		6,864	$	(19,621)

Additionally, a 10% increase or decrease in our average realized sales prices, excluding the impact of derivatives, would have increased or decreased our revenues by approximately $21.1 million.

Operating Costs and Expenses

The table below presents detail of operating costs and expenses for the periods indicated (in thousands except percentages):



	Three Months Ended				Increase (Decrease)
	March 31,				2019 vs 2018
	2019		2018		$		%
Oil and natural gas production expenses	$	80,955	$	71,948	$	9,007	13	%
Exploration expenses		1,270		33		1,237	*
Sales and marketing expenses		4,931		4,173		758	18	%
Production and ad valorem taxes		13,050		13,469		(419)	(3)	%
Depreciation, depletion, amortization and accretion		67,481		59,248		8,233	14	%
Impairment of oil and natural gas properties		3,930		948		2,982	*
General and administrative expenses		20,483		22,420		(1,937)	(9)	%
Total operating costs and expenses		192,100		172,239		19,861	12	%

Interest income		622		742		(120)	(16)	%
Other income		826		3,428		(2,602)	(76)	%
Interest expense		(44,553)		(43,920)		(633)	1	%
Net losses on commodity derivatives		(48,423)		(44,054)		(4,369)	10	%
Income tax expense		(436)		—		(436)	*	%

*Not meaningful.

Oil and Natural Gas Production Expenses. Oil and natural gas production expenses are the costs incurred to produce our oil and natural gas, as well as the daily costs incurred to maintain our producing properties. Our oil and natural gas production expenses increased to approximately $81.0 million ($11.79 per Boe) for the three months ended March 31, 2019 as compared to $71.9 million ($9.92 per Boe) for the same period in 2018. The increase in expense is primarily attributable to our adoption of ASC 842 whereby the Western Catarina Midstream deferred gain was derecognized as of January 1, 2019. As such, beginning with the three months ended March 31, 2019, we no longer realized amortization of the deferred gain, which resulted in an increase in production expenses as compared to the three months ended March 31, 2018. The increase in oil and natural gas production expenses per Boe was due to production expenses increasing and production decreasing.

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Exploration Expenses. The Company records exploration expenditures as charges against earnings for items such as exploratory dry holes, exploratory geological and geophysical costs and delay rentals. Exploration expenses totaled $1.3 million and less than $0.1 million during the three months ended March 31, 2019 and 2018, respectively. The increase in our exploration expenses for the three months ended March 31, 2019 as compared to the same period in 2018 was primarily due to an increase in our exploratory geological and geophysical seismic costs and an increase in our delay rentals.

Sales and Marketing Expenses. The Company incurred sales and marketing expenses of approximately $4.9 million and $4.2 million for the three months ended March 31, 2019 and 2018, respectively. The commodity purchase and sale transactions associated with the related revenue stream commenced during the first quarter 2018. We believe an opportunity exists, from time to time, to participate in additional economic benefits and operational efficiencies in support of our upstream activities by purchasing and reselling production from others, to a limited extent, in order to utilize existing firm transportation arrangements. The volumes associated with these activities are variable and, accordingly, the related expenses from these activities are expected to fluctuate from period to period.

Production and Ad Valorem Taxes. Production taxes are paid on produced oil and natural gas based upon a percentage of gross revenues or at fixed rates established by state or local taxing authorities. Ad valorem taxes are paid based upon the appraised fair market value of producing properties using an estimated discounted cash flow approach and a fixed rate established by state or local taxing authorities. Our production and ad valorem taxes totaled $13.1 million ($1.90 per Boe) and $13.5 million ($1.86 per Boe) for the three months ended March 31, 2019 and 2018, respectively. Production and ad valorem taxes remained relatively consistent between periods.

Depreciation, Depletion, Amortization and Accretion. Depreciation, depletion, amortization and accretion expense increased $8.3 million from $59.2 million ($8.17 per Boe) for the three months ended March 31, 2018 to $67.5 million ($9.83 per Boe) for the three months ended March 31, 2019. The increase in expense represented an approximate $11.4 million increase due to a higher depletion rate which was offset by a $3.2 million decrease from lower production.

Impairment of Oil and Natural Gas Properties. We did not record a proved property impairment during the three months ended March 31, 2019 or 2018. We recorded impairment of $3.9 million and $0.9 million to our unproved oil and natural gas properties for the three months ended March 31, 2019 and 2018, respectively due to acreage expiration from changes in development plan. Changes in production rates, levels of reserves, future development costs and other factors will impact our actual impairment analyses in future periods.

General and Administrative Expenses. Our general and administrative expenses totaled $20.5 million ($2.98 per Boe) for the three months ended March 31, 2019 compared to $22.4 million ($3.09 per Boe) for the same period in 2018. This decrease was primarily due to a decrease in salaries and wages resulting from a reduction in employee headcount as well as a decrease in professional fees. Offsetting these decreases was the change from a stock-based compensation benefit of $1.3 million to stock-based compensation expense of $0.3 million due to our adoption of ASU 2018-07.

Other Income. For the three months ended March 31, 2019, other income totaled $0.8 million compared to other income of $3.4 million for the three months ended March 31, 2018. The other income during the three months ended March 31, 2019 relates primarily to gains of $1.0 million and $0.5 million associated with the increases in fair values of the investments in SNMP and Lonestar, respectively, as compared to a loss of $1.7 million and a gain of $0.5 million, respectively, for the comparable period of 2018. Additionally, we received an immaterial amount of income on Company owned equipment during the three months ended March 31, 2019 as compared to $1.7 million for the comparable period of 2018.

Interest Expense. For the three months ended March 31, 2019, interest expense totaled $44.6 million and included $3.2 million in amortization of debt issuance costs. This is compared to the three months ended March 31, 2018, for which interest expense totaled $43.9 million and included $3.0 million in amortization of debt issuance costs and $3.7 million in a write down of debt issuance costs associated with the amendment and restatement of the Credit Agreement. Interest expense for the three months ended March 31, 2019 was consistent with the comparable period of 2018.

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Commodity Derivative Transactions. We apply mark‑to‑market accounting to our derivative contracts; therefore, the full volatility of the non‑cash change in fair value of our outstanding contracts is reflected in other income and expenses. During the three months ended March 31, 2019, we recognized a net loss of $48.4 million on our commodity derivative contracts, which included net losses of $3.5 million associated with the settlements of commodity derivative contracts and mark-to-market losses of $44.9 million on unsettled commodity derivative contracts. The mark-to-market losses were a result of the increase in estimated future commodity prices as compared to the derivative settlement prices. The settlement losses during the period were primarily a result of increases in commodity prices from the time the positions were entered into until the time of settlement. During the three months ended March 31, 2018, we recognized a net loss of $44.1 million on our commodity derivative contracts, which included mark-to-market losses on oil and natural gas derivatives of $20.8 million and $3.7 million, respectively, and net losses of $19.6 million associated with the settlements of commodity derivative contracts.

Income Tax Expense. For the three months ended March 31, 2019, the Company recorded an income tax expense of $0.4 million, and our effective tax rate was approximately (0.7%). The Company did not record an income tax expense for the three months ended March 31, 2018, and our effective tax rate was approximately 0%. The statutory rate was 21% for both periods, and the difference between the statutory rate and the Company’s effective tax rates was primarily related to valuation allowances recorded during the periods.

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with U.S. GAAP requires our management to select and apply accounting policies that best provide the framework to report our results of operations and financial position. The selection and application of those policies requires our management to make difficult subjective or complex judgments concerning reported amounts of revenue and expenses during the reporting period and the reported amounts of assets and liabilities at the date of the financial statements. As a result, there exists the likelihood that materially different amounts would be reported under different conditions or using different assumptions.

As of March 31, 2019, our critical accounting policies were consistent with those discussed in our 2018 Annual Report.

Use of Estimates

The condensed consolidated financial statements are prepared in conformity with U.S. GAAP, which requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserves and related cash flow estimates used in the depletion and impairment of proved oil and natural gas properties, the evaluation of unproved properties for impairment, the fair value of commodity derivative contracts, embedded derivatives and asset retirement obligations, accrued oil and natural gas revenues and expenses and the allocation of general and administrative expenses. Actual results could differ materially from those estimates.

Liquidity and Capital Resources

The primary source of liquidity and capital resources to fund our development program and other obligations has been cash flow from operations, available cash on hand and proceeds from borrowings and securities issuances. Operating cash flows, however, are largely dependent on oil and natural gas prices and differentials, sales volumes and costs. Oil and natural gas prices declined significantly during the fourth quarter 2018 and have remained low in 2019 through the present date. These lower commodity prices have negatively impacted revenues, earnings and cash flows, and sustained low oil and natural gas prices have had and will continue to have a material and adverse effect on our liquidity position and our ability to raise additional funds through financing transactions.

As of March 31, 2019, we had approximately $200.7 million in cash and cash equivalents, $7.9 million in available borrowing capacity under our Credit Agreement, and $150.0 million in available borrowing capacity under the SN UnSub Credit Agreement, resulting in aggregate liquidity of approximately $358.6 million. Failure to comply with certain covenants under the Credit Agreement or the SN UnSub Credit Agreement could result in events of default in the future that would restrict our access to capital and/or accelerate our payment obligations.

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With the significant reduction of our capital budget, we currently expect that the Company’s cash flows and cash on hand will be sufficient to fund our anticipated 2019 operating needs, debt service obligations, capital expenditures, and commitments and contingencies. However, if commodity prices decline further, we may be unable to fund our remaining 2019 operating needs, debt service obligations, capital expenditures and commitments and contingencies.

We continuously evaluate our current and projected capital spending, operating activities and funding requirements, with consideration of realized commodity prices and the results of our operations and may make further adjustments to our capital expenditures and related financing plans as warranted. In addition, we periodically review acquisition and divestiture opportunities involving third parties, SNMP and/or affiliates of SOG. We may from time to time seek to retire or purchase our outstanding debt as well as our outstanding preferred equity securities through cash purchases and/or exchanges for equity securities and/or debt securities, as applicable, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

Cash Flows

Our cash flows for the three months ended March 31, 2019 and 2018 (in thousands) are as follows:


	Three Months Ended
	March 31,
	2019		2018
Cash Flow Data:
Net cash provided by operating activities	$	66,158	$	84,519
Net cash used in investing activities	$	(60,182)	$	(133,246)
Net cash provided by (used in) financing activities	$	(2,891)	$	414,337

Net Cash Provided by Operating Activities. Net cash provided by operating activities was $66.2 million for the three months ended March 31, 2019 compared to cash provided by operating activities of $84.5 million for the same period in 2018. This decrease was primarily related to lower revenues from lower production and lower realized prices.

One of the primary sources of variability in the Company’s cash flows from operating activities is fluctuations in commodity prices, the impact of which the Company has historically partially mitigated by entering into commodity derivative contracts. Production volume changes also impact cash flow, costs related to operations and debt service.

Net Cash Used in Investing Activities. Net cash flows used in investing activities totaled $60.2 million for the three months ended March 31, 2019 compared to $133.2 million for the same period in 2018. Capital expenditures incurred for drilling and leasehold activities for the three months ended March 31, 2019 totaled $18.1 million and cash paid for capital expenditures was $64.8 million. The capital expenditures incurred are primarily associated with bringing 18 gross wells on-line during the first quarter 2019. The difference between expenditures incurred and paid during the period is due to timing of payments associated with higher activity levels during the fourth quarter 2018. We also received $4.9 million from the sale of certain other assets. During the three months ended March 31, 2018, capital expenditures incurred for drilling and leasehold activities totaled $150.0 million and cash paid for capital expenditures was $135.9 million. The capital expenditures incurred are primarily associated with bringing 68 gross wells on-line. In addition, we received $2.8 million from post-closing adjustments for the Comanche Acquisition.

Net Cash Provided by (Used in) Financing Activities. Net cash flows used in financing activities totaled $2.9 million for the three months ended March 31, 2019 compared to $414.3 million provided by financing activities for the same period in 2018. During the three months ended March 31, 2019, we made payments of $2.9 million on the SN UnSub Credit Facility and our other debt agreements. During the three months ended March 31, 2018, we issued $500 million in 7.25% senior secured notes (before discounts of $5.1 million) and had incremental borrowings of $45 million. Additionally, we made repayments on our prior credit facility of $95 million. We also made payments of $9.9 million for distributions to holders of preferred units in SN UnSub.

Off‑Balance Sheet Arrangements

As of March 31, 2019, we did not have any off‑balance sheet arrangements.

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Commitments and Contractual Obligations

Refer to Note 17, “Commitments and Contingencies” of Part I, Item 1. Financial Statements for a description of lawsuits pending against the Company.

There have been no material changes in our contractual obligations during the three months ended March 31, 2019 other than those disclosed in Note 17, “Commitments and Contingencies” of Part I, Item 1. Financial Statements.

~~Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations~~

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our condensed consolidated financial statements and related notes appearing in Part I, Item 1 of this Quarterly Report on Form 10‑Q and information contained in our 2017 Annual Report. The following discussion contains “forward‑looking statements” that reflect our future plans, estimates, beliefs and expected performance. Please see “Cautionary Note Regarding Forward‑Looking Statements.”

~~Business Overview~~

Sanchez Energy Corporation (together with our consolidated subsidiaries, “Sanchez Energy,” the “Company,” “we,” “our,” “us” or similar terms), a Delaware corporation formed in August 2011, is an independent exploration and production company focused on the acquisition and development of U.S. onshore unconventional oil and natural gas resources, with a current focus on the horizontal development of significant resource potential in the Eagle Ford Shale in South Texas. We also hold an undeveloped acreage position in the Tuscaloosa Marine Shale (“TMS”) in Mississippi and Louisiana, which offers future development opportunities. As of March 31, 2018, we have assembled approximately 487,000 gross leasehold acres (285,000 net acres) in the Eagle Ford Shale. For the year 2018, we plan to invest substantially all of our capital budget in the Eagle Ford Shale. We continually evaluate opportunities to grow our acreage and our producing assets through acquisitions. Our successful acquisition of such assets will depend on the opportunities and the financing alternatives available to us at the time we consider such opportunities.

During the fourth quarter of 2017, the Company changed from the full cost method to the successful efforts method in accounting for its oil and natural gas exploration and development activities. Financial information for prior periods has been recast to reflect retrospective application of the successful efforts method. For additional information, see Note 2, “Basis of Presentation and Summary of Significant Accounting Policies” of Part I, Item 1. Financial Statements.

~~Acquisition and Divestiture Transactions~~

~~Listed below is a table of our significant consummated acquisition and divestiture transactions since January 1, 2017:~~

Transaction

Transaction Date

Transaction Effective Date

Core Area

Net Acreage Acquired

Net Acreage Remaining at 3/31/18

(Purchase) / Disposition Price (millions)
Javelina Disposition

9/19/2017

8/1/2017

Eagle Ford

N/A

N/A

$
105
Marquis Disposition

6/15/2017

1/1/2017

Eagle Ford

N/A

N/A

$
50
Comanche Acquisition(1)

3/1/2017

7/1/2016

Eagle Ford, Pearsall

76,000

76,000

$
(1,044)
Cotulla Disposition(2)

12/14/2016

6/1/2016

Cotulla, Eagle Ford

N/A

N/A

$
167

~~(1)~~

~~The acreage and purchase price disclosed in this table includes only acreage and purchase price related to the SN Comanche Assets.~~

~~(2)~~

The Cotulla Disposition has been included in the table above to capture the subsequent closings that occurred during the three months ended March 31, 2017 and June 30, 2017. Refer to Note 4, “Acquisitions and Divestitures” for additional detail.

~~Javelina Disposition~~

On September 19, 2017, the Company, through its wholly owned subsidiary, SN Cotulla Assets, LLC (“SN Cotulla”), sold approximately 68,000 undeveloped net acres located in the Eagle Ford Shale in LaSalle and Webb Counties, Texas to Vitruvian Exploration IV, LLC for approximately $105 million in cash, after preliminary closing adjustments (the “Javelina Disposition”). Consideration received from the Javelina Disposition was based on an August 1, 2017 effective date and is subject to normal and customary post-closing adjustments.

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~~Marquis Disposition~~

On June 15, 2017, the Company, through its wholly owned subsidiary, SN Marquis LLC, sold approximately 21,000 net acres primarily located in the Eagle Ford Shale in Fayette and Lavaca Counties, Texas to Lonestar Resources US, Inc. (“Lonestar”) for approximately $44.0 million in cash, after preliminary closing adjustments, and approximately $6.0 million in Lonestar’s Series B Convertible Preferred Stock, valued as of the closing date, which subsequently converted into 1.5 million shares of Lonestar’s Class A Common Stock (the “Marquis Disposition”). The consideration received from the Marquis Disposition was based on a January 1, 2017 effective date and is subject to normal and customary post-closing adjustments.

~~Comanche Acquisition~~

On March 1, 2017, the Company, through two of its subsidiaries, SN EF UnSub, LP (“SN UnSub”) and SN EF Maverick, LLC (“SN Maverick”), along with Gavilan Resources, LLC (“Gavilan”), an entity controlled by The Blackstone Group, L.P. completed the acquisition of approximately 318,000 gross (155,000 net) acres comprised of 252,000 gross (122,000 net) Eagle Ford Shale acres and 66,000 gross (33,000 net) acres of deep rights only, which includes the Pearsall Shale, representing an approximate 49% average working interest therein (the “Comanche Assets”) from Anadarko E&P Onshore LLC and Kerr-McGee Oil and Gas Onshore LP (together, “Anadarko”) for approximately $2.1 billion in cash (the “Comanche Acquisition”). Pursuant to the purchase and sale agreement entered into in connection with the Comanche Acquisition, (i) SN UnSub paid approximately 37% of the purchase price (including through a $100 million cash contribution from other Company entities) and (ii) SN Maverick paid approximately 13% of the purchase price. In the aggregate, SN UnSub and SN Maverick acquired half of the 49% working interest in the Comanche Assets (approximately 50% and 0%, respectively, of the estimated total proved developed producing reserves (PDPs), 20% and 30%, respectively, of the estimated total proved developed non-producing reserves (PDNPs), and 20% and 30%, respectively, of the total proved undeveloped reserves (PUDs)) (“SN Comanche Assets”). Pursuant to the purchase and sale agreement, Gavilan paid 50% of the purchase price and acquired the remaining half of the 49% working interest in and to the Comanche Assets (and approximately 50% of the estimated total PDPs, PDNPs and PUDs). The Comanche Assets are primarily located in the Western Eagle Ford and are contiguous with our existing acreage, significantly expanding our asset base and production. The effective date of the Comanche Acquisition was July 1, 2016, and is subject to normal and customary post-closing purchase price adjustments.

~~Cotulla Disposition~~

On December 14, 2016, SN Cotulla Assets, LLC (“SN Cotulla”), a wholly-owned subsidiary of the Company, sold approximately 15,000 net acres located in Dimmit County, Frio County, LaSalle County, Zavala County and McMullen County, Texas (the “Cotulla Assets”) to Carrizo (Eagle Ford) LLC for ~~an adjusted purchase price of approximately $153.5 million, subject to normal and customary post-closing adjustments (the “Cotulla Disposition”). Consideration received from the Cotulla Disposition was based on a June 1, 2016 effective date.~~ ~~During 2017, two additional closings occurred and final post-closing adjustments were made to the purchase price, which resulted in total aggregate consideration of approximately $167.4 million.~~

~~2018 Capital Program~~

Our 2018 capital budget is focused on the development of our approximately 285,000 net acres in the Eagle Ford Shale, where we plan to invest between $475 million and $525 million. The increase from our previous guidance is largely attributable to the positive results we continue to have in the Catarina area and the decision to drill approximately 12 additional wells in that area. Additionally, we have had a higher working interest than previously planned and are moving to full slickwater completions. Over 94 percent of this planned spending will be on the drilling and completion of wells in the Eagle Ford Shale. The remainder will be invested for facilities and leasing activities.

~~Basis of Presentation~~

~~The condensed consolidated financial statements have been prepared in accordance with U.S. GAAP.~~

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~~Core Properties~~

~~Eagle Ford Shale~~

We and our predecessor entities have a long history in the Eagle Ford Shale, where, as of March 31, 2018, we have assembled approximately 487,000 gross leasehold acres (approximately 285,000 net acres) and have approximately 7,900 gross (3,600 net) specifically identified drilling locations for potential future drilling. As of March 31, 2018, approximately 732 of these gross drilling locations represented proved undeveloped reserves. These locations were developed using existing geologic and engineering data. The approximately 7,168 additional gross drilling locations are specifically identified non-proven locations that have been identified by our management team. Although these approximate 7,168 gross additional non-proven locations are determined using the same geologic and engineering methodology as those locations to which proved reserves are attributed, they fail to satisfy all criteria for proven reserves for reasons such as development timing, economic viability at Securities and Exchange Commission (“SEC”) pricing, and production volume certainty. In evaluating and determining those locations, we also considered the availability of local infrastructure, drilling support assets, property restrictions and state and local regulations. The locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results and other factors, and may differ from the locations currently identified. For the year 2018, we plan to invest substantially all of our capital budget in the Eagle Ford Shale.

In 2017, we acquired approximately 252,000 gross (61,000 net) Eagle Ford Shale acres in Dimmit, Webb, La Salle, Zavala and Maverick Counties, Texas through the Comanche Acquisition representing a 24% working interest, which area we refer to as the Comanche area. We anticipate drilling, completion and facilities costs on this acreage to average between $3.0 million and $6.0 million per well. The variability in the cost is largely a factor of lateral lengths, which can vary from approximately 4,400 feet to approximately 11,000 feet. We have identified approximately 5,300 gross (1,285 net) Eagle Ford locations for potential future drilling on our Comanche area.

In the Comanche area, we have a drilling obligation that, in addition to other requirements in the leases that must be adhered to in order to maintain our acreage position, requires us to complete and equip 60 wells in each annual period commencing on September 1, 2017 and continuing thereafter until September 1, 2022. Up to 30 wells completed and equipped in excess of the annual 60 well requirement can be carried over to satisfy part of the 60 well requirement in subsequent annual periods on a well-for-well basis. As of March 31, 2018, 79 wells had been drilled towards the 60 well commitment that will end on August 31, 2018. As a result, the Company has met its annual drilling commitment in the Comanche area for the current period and has already drilled 19 wells toward a maximum bank of 30 wells for the next annual drilling commitment period that begins on September 1, 2018. In addition, as of March 31, 2018, 132 net drilled-but-uncompleted wells (“DUCs”) acquired as part of the Comanche Acquisition had commenced completions operations and all 132 of those DUCs had been brought online. These DUCs do not count toward the annual development obligation. For the year 2018, our current capital budget and plans include the drilling of at least the minimum number of wells to maintain access to such undeveloped acreage in the Comanche area.

We have approximately 106,000 net acres in Dimmit, LaSalle and Webb Counties, Texas representing a 100% working interest, which area we refer to as the Catarina area. We anticipate drilling, completion and facilities costs on this acreage to be between $3.0 million and $6.0 million per well based on our current estimates and historical well costs. The variability in the cost is largely a factor of lateral lengths, which can vary from approximately 4,400 feet to approximately 11,100 feet. We have identified greater than 1,100 gross (1,100 net) locations for potential future drilling in our Catarina area.

In the Catarina area, we have a drilling obligation that requires us to drill (i) 50 wells in each 12-month period commencing on July 1, 2014 and (ii) at least one well in any consecutive 120‑day period in order to maintain rights to any future undeveloped acreage. Up to 30 wells drilled in excess of the minimum 50 wells in a given annual period can be carried over to satisfy part of the 50 well requirement in the subsequent 12-month period on a well-for-well basis. By exceeding the 50 well annual drilling commitment in the two prior years by 20 wells and 18 wells, respectively, the Company maximized the allowable 30 well bank that can be applied towards the current annual drilling commitment period. As of March 31, 2018, SN had drilled 29 wells in addition to the 30 wells banked towards the 50 well annual drilling commitment in the Catarina area that extends from July 1, 2017 to June 30, 2018. As a result, the Company has met its annual drilling commitment at Catarina for the current period and has already drilled nine wells toward a maximum bank of 30 wells for the next annual drilling commitment period that begins on July 1, 2018.

~~Table of Contents~~

We have approximately 110,000 net acres in Dimmit, Frio, LaSalle, and Zavala Counties, Texas, which we refer to as the Maverick area. 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 $6.0 million per well based on our current estimates and historical well costs. The variability in the cost is largely a factor of lateral lengths, which can vary from approximately 9,500 feet to approximately 10,000 feet. We have identified greater than 1,025 gross (985 net) locations for potential future drilling on our Maverick area.

We have approximately 7,600 net acres in Gonzales County, Texas, which we refer to as the Palmetto area. 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 $5.5 million and $6.0 million per well based on our current estimates and historical well costs. We have identified greater than 440 gross (215 net) locations for potential future Eagle Ford drilling in our Palmetto area.

~~Tuscaloosa Marine Shale~~

As of March 31, 2018, we owned approximately 34,000 net acres in the TMS. The TMS development is currently challenged due to high well costs and depressed commodity prices. We believe that the TMS play has significant development potential as changes in technology, commodity prices, and service prices occur.

~~Recent Developments~~

~~Comanche Integration~~

Integration of the Comanche Assets continued during the first quarter 2018. As of March 31, 2018, we had brought 209 gross wells on-line since we closed the transaction on March 1, 2017, including 62 wells during the first quarter of 2018 and 147 wells during 2017. In addition, as of March 31, 2018, there were 42 wells awaiting completion within the Comanche area. With the Comanche Assets strategically located adjacent to our existing Catarina assets, and in close proximity to our Maverick area, we anticipate substantial and continuing operating synergies and other benefits arising from the scale and concentration of our expanded Eagle Ford position. We believe our continued focus on the Western Eagle Ford, expertise at multi-bench development and efficient cost structure provide us with opportunities to create significant value from the Comanche Assets.

~~Conversion from Full Cost to Successful Efforts~~

During the fourth quarter of 2017, we changed from the full cost method to the successful efforts method in accounting for oil and natural gas exploration and development activities. Financial information for prior periods has been recast to reflect retrospective application of the successful efforts method, as prescribed by the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 932 “Extractive Activities – Oil and Gas.” Although the full cost method of accounting for oil and natural gas exploration and development activities continues to be an acceptable alternative, the successful efforts method of accounting is the generally preferred method under U.S. GAAP and is more widely used in the industry such that the change improves the comparability of the Company’s financial statements to its peers. Changing to the successful efforts method of accounting is expected to provide greater transparency in results of our assets, enhance operating decision making and capital allocation processes and eliminate proved property impairments based on historical prices, which are not indicative of fair value of our assets. In general, under successful efforts, exploration expenditures such as exploratory dry holes, exploratory geological and geophysical costs, delay rentals, unproved impairments, and exploration overhead are charged against earnings as incurred, versus being capitalized under the full cost method of accounting. Successful efforts also provides for the assessment of potential property impairments under Accounting Standards Codification (ASC) 360 “Property, Plant, and Equipment” by comparing the net carrying value of oil and natural gas properties with associated projected undiscounted pre-tax future net cash flows. If the expected undiscounted pre-tax future net cash flows are lower than the unamortized capitalized costs, the capitalized cost is reduced to fair value. Under the full cost method of accounting, a write-down would be required if the net carrying value of oil and natural gas properties exceeded a full cost “ceiling,” using an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months. In addition, gains or losses, if applicable, are generally recognized on the dispositions of oil and natural gas property and equipment under the successful efforts method, as opposed to an adjustment to the net carrying value of the remaining assets under the full cost method.

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~~Issuance of 2023 Secured Notes~~

On February 14, 2018, we issued $500 million in aggregate principal amount of 7.25% Senior Secured Notes. Interest on the 7.25% Senior Secured Notes accrues from February 14, 2018 at the rate of 7.25% per annum, payable semiannually in cash in arrears on February 15 and August 15 of each year, commencing on August 15, 2018. The notes and the note guarantees are our and our subsidiary guarantor’s general first lien secured obligations. The 7.25% Senior Secured Notes will mature on February 15, 2023, unless on October 10, 2022 either (i) some or all of our 6.125% Notes (as defined in “Note 7. Debt”) are still outstanding and have not been defeased or (ii) we or any of our restricted subsidiaries have any outstanding indebtedness that was used to purchase, repurchase, redeem, defease or otherwise acquire or retire for value our 6.125% Notes, and such indebtedness under this clause (ii) has a final maturity date that is earlier than May 17, 2023, in which case either of clause (i) or clause (ii), the 7.25% Senior Secured Notes will mature on October 14, 2022. The 7.25% Senior Secured Notes are secured by first-priority liens on a “second-out” collateral proceeds payment priority basis in the Shared Collateral, subject to permitted collateral liens. The 7.25% Senior Secured Notes are effectively junior to any obligations under our amended and restated credit facility and obligations under any hedging arrangements and cash management arrangements permitted to be secured on a first lien basis under our amended and restated credit facility, to the extent of the value of the collateral securing such obligations. See “Note 7. Debt” of Part I, Item 1. Financial Statements.

~~Amended and Restated Credit Facility~~

On February 14, 2018, the Company, as borrower, and the Loan Parties (as defined in “Note 7. Debt” of Part I, Item 1. Financial Statements), entered into a revolving credit facility represented by a Third Amended and Restated Credit Agreement dated as of February 14, 2018 with Royal Bank of Canada, providing for a $25 million first-out senior secured working capital and letter of credit facility (the “Credit Agreement”), which amended and restated the Company’s previous credit facility in its entirety. Availability under our Credit Agreement is at all times subject to customary conditions. The obligations under our Credit Agreement are guaranteed by all of our restricted subsidiaries that guarantee the Senior Notes and the 7.25% Senior Secured Notes and, pursuant to the CTA (as defined in “Note 7. Debt” of Part I, Item 1. Financial Statements), are secured by first priority liens on a “first-out” collateral proceeds payment priority basis in the Shared Collateral, subject only to permitted collateral liens. See “Note 7. Debt” of Part I, Item 1. Financial Statements.

~~Outlook~~

Although commodity and capital markets have shown signs of improvement, we continue to manage our business for the potential of ongoing commodity price volatility. This volatility has significantly influenced our industry and operating environment in the past, and we believe it will in the future. We face continued uncertainty with respect to the demand for our products, commodity prices, service availability and costs, and our ability to fund capital projects. As a result, we continue to evaluate the possibility of certain non-core divestitures to improve liquidity and actively manage our portfolio and returns.

Based on current market prices and various production and cost assumptions, we believe the Company’s cash flows and cash on hand as of March 31, 2018, which includes cash raised from the February 2018 issuance of the 7.25% Senior Secured Notes, as previously described, will be sufficient to fund our anticipated operating needs, debt service obligations, capital expenditures, and commitments and contingencies over a multi-year planning horizon. We continuously evaluate our capital spending, operating and funding activities, with consideration of realized commodity prices and the results of our operations, and may make further adjustments to our capital spending program and related financing plans as warranted. We continuously review acquisition and divestiture opportunities involving third parties, SNMP and/or other members of the Sanchez Group.

~~Table of Contents~~

~~Results of Operations~~

~~Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017~~

~~Revenue and Production~~

Increase

Three Months Ended

(Decrease)

March 31,

2018 vs 2017


2018

2017

$
%

Net Production:

Oil (MBbl)

2,521

1,549

972
63
%
Natural gas liquids (MBbl)

2,406

1,371

1,035
75
%
Natural gas (MMcf)

13,950

10,456

3,494
33
%
Total oil equivalent (MBoe)

7,251

4,662

2,589
56
%
Average Sales Price Excluding Derivatives(1):

Oil ($ per Bbl)

$
61.64

$
47.31

$
14.33
30
%
Natural gas liquids ($ per Bbl)

20.50

19.77

0.73
4
%
Natural gas ($ per Mcf)

2.99

3.20

(0.21)
(7)
%
Oil equivalent ($ per Boe)

$
33.98

$
28.71

$
5.27
18
%
Average Sales Price Including Derivatives(2):

Oil ($ per Bbl)

$
53.32

$
47.26

$
6.06
13
%
Natural gas liquids ($ per Bbl)

20.50

19.77

0.73
4
%
Natural gas ($ per Mcf)

3.09

2.93

0.16
5
%
Oil equivalent ($ per Boe)

$
31.27

$
28.08

$
3.19
11
%
REVENUES(1)(3):

Oil sales

$
155,392

$
73,276

$
82,116
112
%
Natural gas liquids sales

49,305

27,100

22,205
82
%
Natural gas sales

41,729

33,467

8,262
25
%
Total revenues

$
246,426

$
133,843

$
112,583
84
%

~~(1)~~

~~Excludes the impact of derivative instrument settlements.~~

~~(2)~~

~~Includes the impact of derivative instrument settlements.~~

~~(3)~~

~~Excludes revenues related to sales and marketing revenues.~~

~~Table of Contents~~

~~The following table sets forth information regarding combined net production of oil, NGLs and natural gas attributable to our properties for each of the periods presented:~~

Three Months Ended

March 31,

2018

2017
Production:

Oil - MBbl

Comanche

1,206

300
Catarina

773

770
Maverick

485

274
Cotulla

—

15
Palmetto

31

61
Marquis

—

122
TMS / Other

26

7
Total

2,521

1,549
Natural gas liquids - MBbl

Comanche

1,037

266
Catarina

1,348

1,059
Maverick

9

7
Cotulla

—

1
Palmetto

12

10
Marquis

—

28
TMS / Other

—

—
Total

2,406

1,371
Natural gas - MMcf

Comanche

5,737

1,862
Catarina

8,107

8,368
Maverick

48

41
Cotulla

—

1
Palmetto

58

68
Marquis

—

117
TMS / Other

—

(1)
Total

13,950

10,456
Net production volumes:

Total oil equivalent (MBoe)

7,251

4,662
Average daily production (Boe/d)

80,572

51,800
Average Sales Price (1):

Oil ($ per Bbl)

$
61.64

$
47.31
Natural gas liquids ($ per Bbl)

$
20.50

$
19.77
Natural gas ($ per Mcf)

$
2.99

$
3.20
Oil equivalent ($ per Boe)

$
33.98

$
28.71
Average unit costs per Boe:

Oil and natural gas production expenses

$
9.92

$
8.15
Production and ad valorem taxes

$
1.86

$
1.40
General and administrative

$
3.09

$
14.47
Depreciation, depletion, amortization and accretion

$
8.17

$
5.66
Impairment of oil and natural gas properties

$
0.13

$
0.40

~~(1)~~

~~Excludes the impact of derivative instruments.~~

~~Table of Contents~~

~~Net Production~~. Production increased from 4,662 MBoe for the three months ended March 31, 2017 to 7,251 MBoe for the three months ended March 31, 2018 due to increase in production due to the addition of wells from the Comanche Acquisition. The number of gross wells producing at the period end and the net production for the periods were as follows:

Three Months Ended March 31,

2018

2017


# Wells

MBoe

# Wells

MBoe
Comanche

1,644

3,199

1,435

877
Catarina

395

3,472

347

3,224
Maverick

63

502

80

287
Cotulla

—

—

—

16
Palmetto

84

53

80

82
Marquis

—

—

104

170
TMS / Other

47

25

14

6
Total

2,233

7,251

2,060

4,662

For the three months ended March 31, 2018, 35% of our production was oil, 33% was NGLs and 32% was natural gas compared to the three months ended March 31, 2017 production that was 33% oil, 29% NGLs and 38% natural gas. The production mix is relatively consistent between the periods due to the similar proportion of oil, NGLs and natural gas production from our producing properties.

~~Revenues~~. Sales revenue for oil, NGLs, and natural gas totaled $246.4 million and $133.8 million for the three months ended March 31, 2018 and 2017, respectively. Sales revenue for oil, NGLs, and natural gas for the three months ended March 31, 2018 increased $82.1 million, $22.2 million and $8.3 million, respectively, as compared to the three months ended March 31, 2017. The increase in sales revenue for oil, NGLs, and natural gas is primarily attributable to increased production related to the Comanche Acquisition, completed in March 2017. Additionally, sales and marketing revenues of $4.8 million contributed to the increase in revenue during the three months ended March 31, 2018.

The tables below provide an analysis of the impacts of changes in production volumes and average realized prices between the periods on our revenues from the quarter ended March 31, 2017 to the quarter ended March 31, 2018 (in thousands, except average sales price). The change in average realized prices from the quarter ended March 31, 2017 to the quarter ended March 31, 2018 can be attributed to the increase in the market price of oil and NGLs offset by the decrease in the market price of natural gas.

Q1 2018

Q1 2017

Production

Q1 2017

Revenue

Production

Production

Volume

Average Sales

Increase/(Decrease)


Volume

Volume

Difference

Price

due to Production
Oil (MBbl)

2,521

1,549

972

$
47.31

$
45,981
Natural gas liquids (MBbl)

2,406

1,371

1,035

$
19.77

$
20,458
Natural gas (MMcf)

13,950

10,456

3,494

$
3.20

$
11,183
Total oil equivalent (MBoe)

7,251

4,662

2,589

$
28.71

$
77,622











Q1 2018

Q1 2017

Q1 2018

Revenue

Average Sales

Average Sales

Average Sales

Production

Increase/(Decrease)


Price

Price

Price Difference

Volume

due to Price
Oil (MBbl)

$
61.64

$
47.31

$
14.33

2,521

$
36,135
Natural gas liquids (MBbl)

$
20.50

$
19.77

$
0.73

2,406

$
1,747
Natural gas (MMcf)

$
2.99

$
3.20

$
(0.21)

13,950

$
(2,921)
Total oil equivalent (MBoe)

$
33.98

$
28.71

$
5.27

7,251

$
34,961

Additionally, a 10% increase in our average realized sales prices, excluding the impact of derivatives, would have increased our revenues for the three months ended March 31, 2018 by approximately $24.6 million, and a 10% decrease in our average realized sales prices, excluding the impact of derivatives, would have decreased our revenues for the three months ended March 31, 2018 by approximately $24.6 million.

~~Table of Contents~~

~~Operating Costs and Expenses~~

~~The table below presents a detail of operating costs and expenses for the periods indicated (in thousands, except percentages):~~

Three Months Ended

Increase (Decrease)

March 31,

2018 vs 2017


2018

2017

$

%
OPERATING COSTS AND EXPENSES:

Oil and natural gas production expenses

$
71,948

$
37,998

$
33,950

89%
Exploration expenses

33

352

(319)

-91%
Sales and marketing expenses

4,173

—

4,173

*
Production and ad valorem taxes

13,469

6,524

6,945

106%
Depreciation, depletion, amortization and accretion

59,248

26,404

32,844

124%
Impairment of oil and natural gas properties

948

1,845

(897)

-49%
General and administrative expenses(1)

22,420

67,465

(45,045)

-67%
Total operating costs and expenses

172,239

140,588

31,651

23%

Interest income

742

357

385

108%
Other income

3,428

10,535

(7,107)

*
Gain on sale of oil and natural gas properties

—

4,344

(4,344)

-100%
Interest expense

(43,920)

(33,025)

(10,895)

33%
Net gains (losses) on commodity derivatives

(44,054)

38,881

(82,935)

-213%
Income tax benefit

—

953

(953)

0%

~~(1)~~

Includes non-cash stock-based compensation benefit of ($0.4) million and expense of $12.1 million for the three months ended March 31, 2018 and 2017, respectively, and includes acquisition and divestiture costs of $0.4 million and $24.1 million for the three months ended March 31, 2018 and 2017, respectively.

~~Oil and Natural Gas Production Expenses~~. Oil and natural gas production expenses are the costs incurred to produce our oil and natural gas, as well as the daily costs incurred to maintain our producing properties. Such costs also include field personnel costs, utilities, chemical additives, salt water disposal, maintenance, repairs and occasional well workover expenses related to our oil and natural gas properties. Our oil and natural gas production expenses increased 89% to approximately $71.9 million for the three months ended March 31, 2018 as compared to $38.0 million for the same period in 2017. The 89% increase in oil and natural gas production expenses in the first quarter of 2018 compared to the same period of 2017 is attributable to the increase in marketing and transportation costs incurred in the operation of our larger asset base and higher number of producing wells brought online and acquired as part of the Comanche Acquisition in March 2017. Our average production expenses increased from $8.15 per Boe during the three months ended March 31, 2017 to $9.92 per Boe for the three months ended March 31, 2018. This increase was due primarily to the increase in production expenses previously described.

~~Exploration Expenses~~. The Company records exploration expenditures as charges against earnings for charges such as exploratory dry holes, exploratory geological and geophysical costs and delay rentals. The decrease in our exploration expenses for the three months ended March 31, 2018 as compared to the same period in 2017 was primarily due to fewer delay rental and exploratory geological and geophysical costs.

~~Sales and Marketing Expenses~~. Beginning in the first quarter of 2018, we entered into commodity purchase transactions with third parties and then subsequently sold the purchased commodity as separate revenue streams. These purchase contracts were entered into to utilize existing firm transportation arrangements. The Company incurred expenses to purchase and transport the commodity of approximately $4.2 million for the three months ended March 31, 2018.

~~Production and Ad Valorem Taxes~~. Production taxes are paid on produced oil and natural gas based upon a percentage of gross revenues or at a fixed rate established by state taxing authorities. Ad valorem taxes are paid based upon a percentage, established by state or local taxing authorities, of the fair market value of real and/or business assets. The fair market value of producing properties in Texas is determined using an estimated discounted cash flow approach. Our production and ad valorem taxes totaled $13.5 million and $6.5 million for the three months ended March 31, 2018 and 2017, respectively. The increase in production and ad valorem taxes in the first quarter of 2018 compared to the same period in 2017 was primarily due to the increase in production taxes based on the corresponding increase in

~~Table of Contents~~

revenue during the period and an increase in ad valorem taxes related to an increase in our asset base as a result of the Comanche Acquisition completed in March 2017. Our average production and ad valorem taxes increased from $1.40 per Boe during the three months ended March 31, 2017 to $1.86 per Boe for the three months ended March 31, 2018.

~~Depreciation, Depletion and Amortization~~. Depreciation, depletion and amortization (“DD&A”) reflects the systematic expensing of the capitalized costs incurred in the acquisition, successful exploration and development of oil and natural gas properties. Our DD&A expense increased $32.8 million from $26.4 million ($5.66 per Boe) for the three months ended March 31, 2017 to $59.2 million ($8.17 per Boe) for the three months ended March 31, 2018. Higher production as a result of the Comanche Acquisition during the three months ended March 31, 2018 as compared to the same period in 2017 resulted in a $14.7 million increase in depletion expense and the increase in the depletion rate resulted in a $18.1 million increase in depletion expense.

~~Impairment of Oil and Natural Gas Properties~~. Net capitalized costs of proved oil and natural gas properties are compared to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, using estimated discounted future net cash flows. The underlying commodity prices embedded in the estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that management believes will impact realizable prices of our oil and natural gas properties We did not record a proved property impairment during the three months ended March 31, 2018 and 2017. Unproved properties are reviewed periodically by management and transferred into the amortization base when management determines that a project area has been evaluated through drilling operations or thorough geologic evaluation. If the results of an assessment indicate that the properties are impaired, the carrying amount of the identified unproved properties are reduced to their fair value. We recorded impairment of $0.9 million ($0.13 per Boe) and $1.8 million ($0.40 per Boe) to our unproved oil and natural gas properties for the three months ended March 31, 2018 and 2017, respectively due to acreage expiration from changes in development plan. Changes in production rates, levels of reserves, future development costs and other factors will impact our actual impairment analyses in future periods.

~~General and Administrative Expenses~~. Our G&A expenses totaled $22.4 million ($3.09 per Boe) for the three months ended March 31, 2018 compared to $67.5 million ($14.47 per Boe) for the same period in 2017. This decrease was due primarily to lower acquisition and divestiture costs included in G&A during the three months ended March 31, 2018 compared to the same period in 2017, which included acquisition costs related to the Comanche Acquisition. The decrease is also attributable to lower stock-based compensation expense as a result of a decrease in the share price.

For the three months ended March 31, 2018 and 2017, we recorded a non-cash stock‑based compensation benefit (settled in common shares) of approximately ($0.4) million (($0.05) per Boe) and expense of approximately $12.1 million ($2.59 per Boe), respectively. The decrease in the non-cash stock-based compensation expense amount was caused by a decrease in the Company’s stock price offset by an increase in the awards outstanding during the period. The Company records stock‑based compensation expense for awards granted to non‑employees at fair value and the unvested awards are revalued each period, impacting the amortization over the remaining life of the awards.

We recorded costs associated with insignificant acquisition or divestiture activities that were included in G&A of $0.4 million ($0.05 per Boe) for the three months ended March 31, 2018. We recorded costs associated with the Comanche Acquisition that are included in G&A of $24.1 million ($5.16 per Boe) for the three months ended March 31, 2017.

~~Other Income.~~ For the three months ended March 31, 2018, other income totaled $3.4 million compared to other income of $10.5 million for the three months ended March 31, 2017. The other income during the three months ended March 31, 2018 relates primarily to dividend income of $1.0 million from the quarterly dividend on the investment in SNMP and $1.7 million from rental income on Company owned equipment offset by $1.2 million net loss associated with the decrease in fair value of the investments in SNMP and Lonestar. For the three months ended March 31, 2017, other income primarily related to a $8.9 million gain associated with the increase in fair value of the investment in SNMP.

~~Interest Expense~~. For the three months ended March 31, 2018, interest expense totaled $43.9 million and included $3.0 million in amortization of debt issuance costs and $3.7 million in write down of debt issuance costs associated with decreasing the borrowing base on the Credit Agreement. For the three months ended March 31, 2017,

~~Table of Contents~~

interest expense totaled $33.0 million and included $2.5 million in amortization of debt issuance costs. The interest expense incurred during the three months ended March 31, 2017 is primarily related to the 7.75% Notes, the 6.125% Notes, and one month of interest on the SN UnSub Credit Agreement (as defined in “Note 7, Debt” of Part I. Item 1 Financial Statements). The increase in interest expense for the three months ended March 31, 2018, relates primarily to the 7.25% Senior Secured Notes issued in February 2018 and increased expense related to the SN UnSub Credit Agreement acquired as part of the Comanche Acquisition.

~~Commodity Derivative Transactions~~. We apply mark‑to‑market accounting to our derivative contracts; therefore, the full volatility of the non‑cash change in fair value of our outstanding contracts is reflected in other income and expense. During the three months ended March 31, 2018, we recognized a net loss of $44.1 million on our commodity derivative contracts, which included mark-to-market losses on oil and natural gas derivatives of $20.8 million and $3.7 million, respectively, and net losses of $19.6 million associated with the settlements of commodity derivative contracts. The mark-to-market losses were primarily the result of increases in commodity prices from the previous reporting period until the end of the current reporting period. The settlement losses were primarily a result of the increases in commodity prices from the time the trades were entered until the time of cash settlement for trades that liquidated by their terms during the current period.

During the three months ended March 31, 2017, we recognized a net gain of $38.9 million on our commodity derivative contracts, which included mark-to-market gains on oil and natural gas derivatives of $22.4 million and $19.3 million, respectively, and net losses of $2.9 million associated with the settlements of commodity derivative contracts. The mark-to-market gains were primarily the result of decreases in commodity prices from the previous reporting period until the end of the current reporting period. The settlement losses were primarily a result of the increases in commodity prices from the time the trades were entered until the time of cash settlement for trades that liquidated by their terms during the current period.

~~Income Tax Benefit~~. For the three months ended March 31, 2018, the Company did not record an income tax expense. Our effective tax rate for the three months ended March 31, 2018 was approximately 0% compared to a statutory rate of 21%. The difference between the statutory rate and the Company’s effective tax rate is primarily related to a valuation allowance recorded during the period. For the three months ended March 31, 2017, the Company recorded an income tax benefit of approximately $1.0 million. During the three months ended March 31, 2017, the Company issued warrants to purchase common stock that had a day one difference in estimated fair value for book and tax accounting purposes, which caused an income tax benefit during the period. Our effective tax rate for the three months ended March 31, 2017 was approximately (6.4)% compared to a statutory rate of 35%. The difference between the statutory rate and the Company’s effective tax rate is primarily related to the recording of certain deferred tax liabilities associated with the Comanche Acquisition that were recorded directly to equity, whereas the correlating movement in the valuation allowance was required to run through income tax expense.

~~Critical Accounting Policies and Estimates~~

~~As of March 31, 2018, our critical accounting policies were consistent with those discussed in our 2017 Annual Report.~~

~~Use of Estimates~~

The condensed consolidated financial statements are prepared in conformity with U.S. GAAP, which requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserves and related cash flow estimates used in the depletion and impairment of oil and natural gas properties, the evaluation of unproved properties for impairment, the fair value of commodity derivative contracts and asset retirement obligations,

~~Table of Contents~~

~~accrued oil and natural gas revenues and expenses and the allocation of general and administrative expenses. Actual results could differ materially from those estimates.~~

~~Liquidity and Capital Resources~~

As of March 31, 2018, we had approximately $550 million in cash and cash equivalents, $25 million in available borrowing capacity under the Credit Agreement, and $158.5 million in available borrowing capacity under the SN UnSub Credit Agreement, resulting in aggregate liquidity of approximately $733.5 million. For a description of current and previous credit agreements along with the indentures covering our Senior Notes refer to Note 7, “Debt” of Part I, Item 1. Financial Statements. Other potential sources of capital and liquidity also include, among other things, our securities that can be issued pursuant to our shelf registration statement filed with the SEC, including pursuant to our $75 million at-the-market equity distribution program we entered into on May 25, 2017.

On February 14, 2018, we issued $500 million in aggregate principal amount of the 7.25% Senior Secured Notes and amended and restated our prior revolving credit facility to, among other things, (i) reduce its size from a $350 million borrowing base with a $300 million aggregate commitment amount to a $25 million commitment to provide primarily for working capital and letters of credit, (ii) extend the maturity from 2019 to 2023, (iii) remove all material financial maintenance covenants and (iv) provide for the continued ability to hedge. See Note 7, “Debt” of Part I, Item 1. Financial Statements.

We may from time to time seek to retire or purchase our outstanding debt as well as our outstanding preferred equity securities through cash purchases and/or exchanges for equity securities and/or debt securities, as applicable, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

~~Cash Flows~~

~~Our cash flows for the three months ended March 31, 2018 and 2017 (in thousands) are as follows:~~

Three Months Ended

March 31,

2018

2017
Cash Flow Data:

Net cash provided by (used in) operating activities

$
84,519

$
(13,688)
Net cash used in investing activities

$
(133,246)

$
(1,127,409)
Net cash provided by financing activities

$
414,337

$
763,765

~~Net Cash Provided by (Used in) Operating Activities.~~ Net cash provided by operating activities was $84.5 million for the three months ended March 31, 2018 compared to cash used in operating activities of $13.7 million for the same period in 2017. This increase was related to higher revenues due to the impact of higher average commodity prices for oil and NGLs between these periods and increased production related to the SN Comanche Assets acquired in

~~Table of Contents~~

March 2017. The increase was partially offset by a decrease in average realized prices for natural gas and cash outflows for settlements on commodity derivatives for the three months ended March 31, 2018 compared to cash inflows for settlements on commodity derivatives for the three months ended March 31, 2017.

One of the primary sources of variability in the Company’s cash flows from operating activities is fluctuations in commodity prices, the impact of which the Company partially mitigates by entering into commodity derivatives. Sales volume changes also impact cash flow. The Company’s cash flows from operating activities are also dependent on the costs related to continued operations and debt service.

~~Net Cash Used in Investing Activities.~~ Net cash flows used in investing activities totaled $133.2 million for the three months ended March 31, 2018 compared to $1,127.4 million for the same period in 2017. Capital expenditures for leasehold and drilling activities for the three months ended March 31, 2018 totaled $135.9 million, primarily associated with bringing 68 gross wells on-line and the completion of drilled-but-uncompleted wells acquired in the Comanche Acquisition. In addition, we received $2.8 million related to the post-closing adjustments for the Comanche Acquisition during the three months ended March 31, 2018. For the three months ended March 31, 2017, we purchased the SN Comanche Assets for approximately $1,039 million. We incurred capital expenditures for leasehold and drilling activities of $87.7 million, primarily associated with bringing 18 gross wells on-line. In addition, we invested $7.5 million in other property and equipment during the three months ended March 31, 2017.

~~Net Cash Provided by Financing Activities.~~ Net cash flows provided by financing activities totaled $414.3 million for the three months ended March 31, 2018 compared to $763.8 million for the same period in 2017. During the three months ended March 31, 2018, we issued $500 million in 7.25% Senior Secured Notes (net of discounts of $5.1 million) and had incremental borrowings of $45 million. Additionally, we made repayments on the prior credit facility of $95 million. We also made payments of $9.9 million for distributions to holders of the SN UnSub Preferred Units. During the three months ended March 31, 2017, we entered into the SN UnSub Credit Agreement in connection with the Comanche Acquisition and had borrowings of $190 million and issued the SN UnSub Preferred Units for $500 million. In addition, we issued common stock for $135.9 million (net of underwriting discounts of $7.8 million). We made payments of $44.8 million for deferred financing costs associated with the SN UnSub Credit Agreement and issuance costs for the SN UnSub Preferred Units, collectively.

~~Off‑Balance Sheet Arrangements~~

~~As of March 31, 2018, we did not have any off‑balance sheet arrangements.~~

~~Commitments and Contractual Obligations~~

~~Refer to Note 17, “Commitments and Contingencies” of Part I, Item 1. Financial Statements for a description of lawsuits pending against the Company.~~

There have been no material changes in our contractual obligations during the three months ended March 31, 2018 other than those disclosed in Note 17, “Commitments and Contingencies” of Part I, Item 1. Financial Statements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to a variety of market risks, including the effects of adverse changes in commodity prices and, potentially, interest rates as described below.

The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

Our primary market risk exposure relates to the prices we receive for our oil, natural gas and NGL production. The prices we ultimately realize for our oil, natural gas and NGLs are based on a number of variables, including prevailing index prices attributable to our production and certain differentials to those index prices. Pricing for oil,

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natural gas and NGLs is volatile and unpredictable, and this volatility is expected to continue in the future. In addition, the prices we receive for our oil, natural gas and NGLs depend on many factors outside of our control, such as the supply and demand for oil, natural gas and NGLs, the relative strength of the global economy, ~~and~~ the actions of ~~OPEC.~~OPEC and international sanctions against countries such as Iran and Venezuela.

To reduce the impact on the Company’s business and results of operations from fluctuations in the prices we receive for oil, natural gas and NGLs, and to protect the economics of property acquisitions at the time of execution, the Company periodically enters into derivative contracts with respect to a portion of its projected oil and natural gas production through various transactions that fix or modify the future prices to be realized. These transactions may include ~~fixed-for-floating~~fixed price swaps (whereby, on the settlement date, the Company will receive or pay an amount based on the difference between a pre-determined fixed price and a variable market price for a notional quantity of production), put options (whereby the Company pays a cash premium in order to establish a fixed floor price for a notional quantity of production and, on the settlement date, receives the excess, if any, of the fixed price floor over a variable market price), and costless collars (whereby, on the settlement date, the Company receives the excess, if any, of a variable market price over a fixed floor price, up to a fixed ceiling price for a notional quantity of production). In addition, the Company periodically enters into call swaptions as a way to achieve greater downside price protection than offered under prevailing ~~fixed-for-floating~~fixed price swaps by agreeing to ~~expand~~increase the notional quantity hedged or extend the notional quantity settlement period under a ~~fixed-for floating~~fixed price swap at the counterparty’s election on a designated date. The market for NGL hedging has historically been constrained in terms of price, tenor, liquidity and availability of counterparties. The Company does not currently have any NGL hedges in place. We continue to assess our exposure to NGL price volatility and the NGL hedging market in general and may seek to enter into derivatives in the future on a portion of our projected NGL production. In addition, from time to time, the Company may evaluate strategies to unwind, terminate, cancel, restructure or otherwise modify its existing commodity derivatives in connection with the ongoing assessment of its general risk profile, including projected future production levels, covenant and other compliance requirements, its overall financial position and other considerations.

These hedging activities, which are ~~governed~~regulated by, as applicable, the terms of ~~our~~the Credit Agreement, the SN UnSub Credit Agreement and ~~the terms of~~ SN UnSub’s organizational documents, are intended to support oil and natural gas prices at targeted levels and manage exposure to oil and natural gas price fluctuations. It is our policy to enter into derivative contracts only with counterparties that are creditworthy and competitive market participants. Any derivatives that are, as applicable, with ~~(x)~~(a) lenders, or affiliates of lenders, to the SN UnSub Credit Agreement, or ~~(y)~~(b) counterparties designated as secured under the Credit Agreement are, in each case, collateralized by the assets securing the applicable facility, and, therefore, do not currently require the posting of cash collateral. Any derivatives that are with (x) non-lenders (or non-lender ~~counterparties, as designated~~affiliates) under the SN UnSub Credit Agreement or (y) counterparties that are not designated as secured under

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the Credit Agreement are, in each case, unsecured and do not require the posting of cash or other collateral. It is never the Company’s intention to enter into derivative contracts for speculative trading purposes. Please refer to Note 8, “Derivative Instruments” ~~in Part I, Item 1. Financial Statements~~ for a description of all of our derivatives covering anticipated future production as of March 31, ~~2018.~~2019.

The prices at which we enter into commodity derivative contracts covering our production in the future will be dependent upon conditions in the commodity and financial markets at the time we enter into these transactions, which may result in higher or lower hedge prices for oil, natural gas and NGLs ~~if any,~~ under these contracts, if any, as compared to the hedge prices under our current contracts. Accordingly, our hedging strategy may not protect us from significant or sustained declines in the prices of oil, natural gas and NGLs for future production. Conversely, our hedging strategy may limit our ability to realize incremental cash flows from commodity price increases during periods for which we have hedged our production. As such, our hedging strategy may not prove effective in adequately protecting us from changes in the prices of oil, natural gas and NGLs that could have a significant adverse effect on our liquidity, business, financial condition and results of operations.

At March 31, ~~2018,~~2019, the fair value of our commodity derivative contracts was a net liability of approximately ~~$78.7~~$23.7 million. A 10% increase or decrease in the oil and natural gas index prices above the March 31, ~~2018~~2019 prices would result in a decrease or increase, respectively, in the fair value of our commodity derivative contracts of ~~$81.4 million; conversely,~~$26.6 million. On a ~~10% decrease~~consolidated basis, the Company has hedged approximately 2,339,000 Bbls of its remaining 2019 oil production and 13,105,000 MMBtu of its remaining 2019 natural gas production. SN UnSub’s production represents approximately 47% of the hedged oil volumes and approximately 42% of the hedged gas volumes.

Credit Risk

Our credit risk relates primarily to trade receivables and financial derivative instruments. Credit exposure for each customer is monitored for outstanding balances and current activity. For derivatives entered into as part of our hedging program, we are subject to counterparty credit risk to the extent the counterparty is unable to meet its settlement commitments. We may also be exposed to credit risk due to the concentration of our customers in the energy industry, as our customers may be similarly affected by prolonged changes in economic and industry conditions, or by the sale of our oil and natural gas ~~index price would result in an increase~~production to a limited number of ~~$80.9 million.~~purchasers.

We actively manage this credit risk by selecting counterparties that we believe to be highly creditworthy and continuing to monitor their financial position. Concentration of credit risk is regularly reviewed to ensure that counterparty credit risk is adequately diversified.

As of March 31, 2019, the substantial majority of our credit exposure was with investment grade counterparties. We believe exposure to losses related to credit risk at March 31, 2019 was not material, which is consistent with all periods presented.

Interest Rate Risk

At the Company’s election, borrowings under the Credit Agreement or the SN UnSub Credit Agreement may be made on a variable alternate base rate (“ABR”) or a Eurodollar (LIBOR) rate, plus an applicable margin determined based on the utilization of available borrowing capacity, as defined in the applicable credit agreement. As of March 31, ~~2018, there were~~2019, we had no borrowings outstanding under the Credit Agreement, ~~and $171.5~~$165.0 million ~~in borrowings~~ outstanding under the SN UnSub Credit ~~Agreement.~~

Agreement and $23.2 million outstanding under the SR Credit Agreement, all of which carry variable interest rates. Our ~~7.75% Notes~~senior notes bear ainterest at fixed interest ~~rate of 7.75% with~~rates. A one percent change in the interest rates on the outstanding borrowings under the SN UnSub credit facility and the SR Credit Agreement would result in an ~~expected maturity date of June 15, 2021, and we had $600~~approximately $1.7 million ~~outstanding as of~~change in annual interest expense. We believe our exposure to interest-related losses at March 31, ~~2018. Our 6.125% Notes bear a fixed~~2019 was not material.

We currently do not have any interest rate derivative contracts in place. We continue to assess our exposure to fluctuating interest rates and may seek to enter into interest rate derivatives in the future on a portion of ~~6.125% with an expected maturity date of January 15, 2023, and we had $1.15 billion outstanding as of March 31, 2018. On February 14,~~our variable rate indebtedness.

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2018, we issued $500 million in aggregate principal amount of 7.25% Senior Secured Notes which bear interest at a fixed rate of 7.25% with an expected maturity date of February 15, 2023, subject to satisfaction of certain conditions, and we had $500 million outstanding as of March 31, 2018.

Our Non-Recourse Subsidiary Term Loan (as defined in “Note 7. Debt” of Part I, Item 1. Financial Statements) bears a fixed interest rate of 4.59% with an expected maturity date of August 31, 2022, and we had approximately $4.1 million outstanding as of March 31, 2018.

The credit facility which we assumed through a non-recourse subsidiary when we acquired the equity in Sanchez Resources bears a variable interest rate and, although the original maturity date was August 7, 2018, prior to its acquisition by the Company, the administrative agent and the lenders accelerated the obligations due under the credit facility, which continues to bear interest on the outstanding and unpaid borrowings. As of March 31, 2018, there was approximately $24 million in borrowings past due with no availability to borrow additional funds under that credit facility.

As of March 31, 2018, we did not have any interest rate derivative contracts in place. If we incur significant debt with a risk of fluctuating interest rates in the future under the Credit Agreement, SN UnSub Credit Agreement, or other debt instruments, we may enter into interest rate derivative contracts on a portion of our then outstanding debt to mitigate the risk of fluctuating interest rates.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report pursuant to Rule 13a-15 promulgated pursuant to the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Based upon that evaluation, our principal executive officer and principal financial officer concluded that, as of the end of the period covered by this report, our disclosure controls and procedures were effective to provide reasonable assurance that material information required to be disclosed by us in reports that we file or submit under the Exchange Act is appropriately recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms and that information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

Changes in Internal Controls

There was no change in our internal control over financial reporting during the three months ended March 31, ~~2018~~2019 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. The adoption of ASC ~~606, Revenue from Contracts with Customers,~~842, Leases, required the implementation of new controls and the modification of certain accounting ~~processes related to revenue recognition.~~processes. The impact of these changes was not material to the Company’s internal control over financial reporting.

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PART II—OTHER INFORMATION

Item 1. Legal Proceedings

For a description of our material pending legal proceedings, please refer to (i) Note 17, “Commitments and Contingencies” of Part I, Item 1. Financial ~~Statements.~~Statements and (ii) the “Business Overview” of Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Item 1A. Risk Factors

~~Consider carefully~~Carefully consider the risk factors under the caption ~~"Risk Factors"~~“Risk Factors” under Part I, Item 1A in our ~~2017~~2018 Annual Report, together with all of the other information included in this Quarterly Report on Form ~~10-Q; in our 2017 Annual Report;~~10-Q and in our other public filings, press releases, and public discussions with our management. Additional risks and uncertainties not currently known to us or that we currently deem immaterial may materially adversely affect our business, financial condition or results of operations.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Unregistered Sales of Equity Securities

On January 4, 2018, we issued 100,000 shares of our common stock to Intrepid Partners, LLC in connection with services performed by it or its affiliates in connection with the Comanche Acquisition. The offer and issuance of the shares was exempt under Section 4(a)(2) under the Securities Act of 1933 as an offering by the issuer not involving a public offering and/or Regulation D promulgated thereunder.None

Repurchase of Equity Securities

Period

Total number of shares withheld(1)

Average Price per share

Total number of shares repurchased as part of publicly announced plans

Maximum number of shares that may yet be repurchased under the plan
January 1, 2018 - January 31, 2018

42,175

$ 5.36

-

-
February 1, 2018 - February 28, 2018

52,873

$ 3.47

-

-
March 1, 2018 - March 31, 2018

26,120

$ 3.03

-

-
Total

121,168

$ 4.03

-

-


Period	Total number of shares withheld(1)	Average Price per share	Total number of shares repurchased as part of publicly announced plans	Maximum number of shares that may yet be repurchased under the plan
January 1, 2019 - January 31, 2019	—	—	—	—
February 1, 2019 - February 28, 2019	—	—	—	—
March 1, 2019 - March 31, 2019	141,245	$ 0.26	—	—
Total	141,245	$ 0.26	—	—

(1)

Represents shares that were purchased by the Company to satisfy employee tax withholding obligations that arose upon the vesting of restricted stock awards.

Item 3. Defaults Upon Senior Securities

~~None.~~The annual dividend on each share of our Series A Preferred Stock is 4.875% on the liquidation preference of $50.00 per share and is payable quarterly, in arrears, on each January 1, April 1, July 1 and October 1, when, as and if declared by the Board. The Company may, at its option, pay dividends in cash and, subject to certain conditions, common stock or any combination thereof. Dividends are cumulative, and beginning during the three month period ending March 31, 2019, the Board determined to suspend the dividend on our Series A Preferred Stock. Dividends accumulated through that date have been accrued. The amount and total arreage on the Series A Preferred Stock as of the date of filing of this report is approximately $0.6 million.

The annual dividend on each share of our Series B Preferred Stock is 6.500% on the liquidation preference of $50.00 per share and is payable quarterly, in arrears, on each January 1, April 1, July 1 and October 1, when, as and if declared by the Board. The Company may, at its option, pay dividends in cash and, subject to certain conditions, common stock or any combination thereof. Dividends are cumulative, and beginning during the three month period ending March 31, 2019, the Board determined to suspend the dividend on our Series B Preferred Stock. Dividends accumulated through that date have been accrued. The amount and total arreage on the Series B Preferred Stock as of the date of filing of this report is approximately $2.7 million.

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Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

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Item 6. Exhibits

EXHIBIT INDEX


3.1			Restated Certificate of Incorporation of Sanchez Energy Corporation, effective as of May 28, 2013 (filed as Exhibit 3.2 to the Company's Quarterly Report on Form 10-Q on November 8, 2013 (File No. 001‑35372) and incorporated herein by reference).

3.2			Certificate of Designations of Series C Junior Participating Preferred Stock of Sanchez Energy Corporation (filed as Exhibit 3.1 to the Company's Current Report on Form 8‑K on July 29, 2015 (File No. 001‑35372) and incorporated herein by reference).

3.3			Amended and Restated Bylaws, dated as of December 13, 2011 (filed as Exhibit 3.2 to the Company's Current Report on Form 8‑K on December 19, 2011 (File No. 001‑35372) and incorporated herein by reference).

~~4.1~~10.1	(a)		Indenture dated as of February 14, 2018 among Sanchez Energy Corporation, the guarantors party thereto, Delaware Trust Company, as trustee and Royal Bank of Canada, as collateral trustee (filed as Exhibit 4.1First Amendment to ~~the Company’s Current Report on Form 8‑K on February 20, 2018, and incorporated herein by reference).~~

~~10.1~~			~~Third~~ Amended and Restated ~~Credit~~ Agreement ~~dated as~~ of ~~February 14, 2018~~Limited Partnership of SN EF UnSub, LP, among ~~Sanchez Energy Corporation, as borrower, Royal Bank of Canada, as administrative agent~~SN EF UnSub GP, LLC, GSO ST Holdings LP, and collateral agent, RBC Capital Markets, as Arranger and the lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8‑K on February 20, 2018, and incorporated herein by reference).

~~10.2~~			Purchase Agreement, dated February 7, 2018, by and among Sanchez Energy Corporation, the subsidiary guarantors named therein and Citigroup Global Markets Inc., as representative of the several initial purchasers named therein (filed as Exhibit 10.1 to the Company’s Current Report on Form 8‑K on February 12, 2018, and incorporated herein by reference).GSO ST Holdings Associates LLC.

31.1	(a)		Sarbanes‑Oxley Section 302 certification of Principal Executive Officer.

31.2	(a)		Sarbanes‑Oxley Section 302 certification of Principal Financial Officer.

32.1	(b)		Sarbanes‑Oxley Section 906 certification of Principal Executive Officer.

32.2	(b)		Sarbanes‑Oxley Section 906 certification of Principal Financial Officer.

101.INS	(a)	—	XBRL Instance Document.

101.SCH	(a)	—	XBRL Taxonomy Extension Schema Document.

101.CAL	(a)	—	XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF	(a)	—	XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB	(a)	—	XBRL Taxonomy Extension Labels Linkbase Document.

101.PRE	(a)		XBRL Taxonomy Extension Presentation Linkbase Document

(a)

Filed herewith.

(b)

Furnished herewith.

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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 thereunto duly authorized, on May 8, ~~2018.~~2019.


	SANCHEZ ENERGY CORPORATION

	By:	/s/ Kirsten A. Hink
		Kirsten A. Hink
		Senior Vice President and Chief Accounting Officer (Duly Authorized Officer)

	By:	/s/ ~~Howard J. Thill~~Cameron W. George
		~~Howard J. Thill~~Cameron W. George
		Executive Vice President and Chief Financial Officer (Principal Financial Officer)

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	Changes to Condensed Consolidated Balance Sheet
March 31, 2017		Under Full Cost		Changes		As Reported Under Successful Efforts
Oil and natural gas properties:
Proved oil and natural gas properties	$	4,077,686	$	(1,324,878)	$	2,752,808
Unproved oil and natural gas properties		466,868		(6,705)		460,163
Total oil and natural gas properties		4,544,554		(1,331,583)		3,212,971
Less: Accumulated depreciation, depletion, amortization and impairment		(2,769,126)		1,381,319		(1,387,807)
Total oil and natural gas properties, net		1,775,428		49,736		1,825,164
Total assets	$	2,078,560	$	49,736	$	2,128,296

Current liabilities:
Other current liabilities	$	17,273	$	8,907	$	26,180
Total current liabilities		172,557		8,907		181,464
Other liabilities		63,506		22,639		86,145
Total liabilities		2,156,133		31,546		2,187,679
Accumulated deficit		(1,822,912)		18,190		(1,804,722)
Total stockholders' equity (deficit)		(481,502)		18,190		(463,312)


Proved oil and natural gas properties	$	781,789
Unproved properties		263,471
Other assets acquired		6,702
Fair value of assets acquired		1,051,962
Asset retirement obligations		(8,289)
Fair value of net assets acquired	$	1,043,673


	December 31, 2017
			Gross Amounts		Net Amounts
	Gross Amount		Offset in the		Presented in the
	of Recognized		Consolidated		Consolidated
	Assets		Balance Sheets		Balance Sheets
Offsetting Derivative Assets:
Current asset	$	16,510	$	(80)	$	16,430
Long-term asset		2,100		(672)		1,428
Total asset	$	18,610	$	(752)	$	17,858
Offsetting Derivative Liabilities:
Current liability	$	56,270	$	(80)	$	56,190
Long-term liability		18,146		(672)		17,474
Total liability	$	74,416	$	(752)	$	73,664


Proved oil and natural gas properties	$	17,719
Unproved properties		5,227
Other assets acquired		3,952
Fair value of assets acquired		26,898
Asset retirement obligations		(2,902)
Fair value of net assets acquired	$	23,996


	As of		Adjustments Due		As of
Balance Sheet	December 31, 2017		to ASC 606		January 1, 2018
Assets
Fair value of derivative instruments	$	16,430	$	150	$	16,580
Total current assets		350,798		150		350,948
Fair value of derivative instruments		1,428		6,251		7,679
Total assets	$	2,470,635	$	6,401	$	2,477,036
Liabilities
Other liabilities	$	65,480	$	(16,338)	$	49,142
Total liabilities		2,512,263		(16,338)		2,495,925
Equity
Accumulated deficit		(1,832,156)		22,739		(1,809,417)
Total stockholders' deficit		(469,140)		22,739		(446,401)
Total liabilities and stockholders' deficit	$	2,470,635	$	6,401	$	2,477,036


	As of March 31, 2018
	Balances without		Effect of change
Balance Sheet	Adoption ASC 606		higher/(lower)		As Reported
Assets
Fair value of derivative instruments	$	12,013	$	6	$	12,019
Total current assets		686,465		6		686,471
Fair value of derivative instruments		2,110		6,668		8,778
Total assets	$	2,897,168	$	6,674	$	2,903,842
Liabilities
Other liabilities	$	55,547	$	(16,338)	$	39,209
Total liabilities		2,953,601		(16,338)		2,937,263
Equity
Accumulated deficit		(1,857,069)		23,012		(1,834,057)
Total stockholders' deficit		(489,875)		23,012		(466,863)
Total liabilities and stockholders' deficit	$	2,897,168	$	6,674	$	2,903,842


	Three Months Ended March 31, 2017
	Parent Company		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Total revenues	$	-	$	111,828	$	22,015	$	-	$	133,843
Total operating costs and expenses		(64,572)		(54,605)		(21,911)		500		(140,588)
Other income (expense)		(11,236)		5,115		28,148		(500)		21,527
Income (loss) before income taxes	$	(75,808)	$	62,338	$	28,252	$	-	$	14,782

Income tax benefit (expense)		1,190		-		(237)		-		953
Equity in income (loss) of subsidiaries		83,634		-		-		(83,634)		-
Net income (loss)	$	9,016	$	62,338	$	28,015	$	(83,634)	$	15,735


					Increase
	Three Months Ended				(Decrease)
	March 31,				2018 vs 2017
	2018		2017		$		%
Net Production:
Oil (MBbl)		2,521		1,549		972	63	%
Natural gas liquids (MBbl)		2,406		1,371		1,035	75	%
Natural gas (MMcf)		13,950		10,456		3,494	33	%
Total oil equivalent (MBoe)		7,251		4,662		2,589	56	%
Average Sales Price Excluding Derivatives(1):
Oil ($ per Bbl)	$	61.64	$	47.31	$	14.33	30	%
Natural gas liquids ($ per Bbl)		20.50		19.77		0.73	4	%
Natural gas ($ per Mcf)		2.99		3.20		(0.21)	(7)	%
Oil equivalent ($ per Boe)	$	33.98	$	28.71	$	5.27	18	%
Average Sales Price Including Derivatives(2):
Oil ($ per Bbl)	$	53.32	$	47.26	$	6.06	13	%
Natural gas liquids ($ per Bbl)		20.50		19.77		0.73	4	%
Natural gas ($ per Mcf)		3.09		2.93		0.16	5	%
Oil equivalent ($ per Boe)	$	31.27	$	28.08	$	3.19	11	%
REVENUES(1)(3):
Oil sales	$	155,392	$	73,276	$	82,116	112	%
Natural gas liquids sales		49,305		27,100		22,205	82	%
Natural gas sales		41,729		33,467		8,262	25	%
Total revenues	$	246,426	$	133,843	$	112,583	84	%



	Q1 2018		Q1 2017		Production		Q1 2017		Revenue
	Production		Production		Volume		Average Sales		Increase/(Decrease)
	Volume		Volume		Difference		Price		due to Production
Oil (MBbl)		2,521		1,549		972	$	47.31	$	45,981
Natural gas liquids (MBbl)		2,406		1,371		1,035	$	19.77	$	20,458
Natural gas (MMcf)		13,950		10,456		3,494	$	3.20	$	11,183
Total oil equivalent (MBoe)		7,251		4,662		2,589	$	28.71	$	77,622


	Q1 2018		Q1 2017				Q1 2018		Revenue
	Average Sales		Average Sales		Average Sales		Production		Increase/(Decrease)
	Price		Price		Price Difference		Volume		due to Price
Oil (MBbl)	$	61.64	$	47.31	$	14.33		2,521	$	36,135
Natural gas liquids (MBbl)	$	20.50	$	19.77	$	0.73		2,406	$	1,747
Natural gas (MMcf)	$	2.99	$	3.20	$	(0.21)		13,950	$	(2,921)
Total oil equivalent (MBoe)	$	33.98	$	28.71	$	5.27		7,251	$	34,961