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10-Q 1 sn-20190331x10q.htm 10-Q sn_Current folio_10Q

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, 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 every Interactive Data File required to be submitted 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 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 ☐	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 3, 2019: 99,828,591

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Sanchez Energy Corporation

Form 10‑Q

For the Quarterly Period Ended March 31, 2019

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	PART I
Item 1.	Financial Statements	10
	Condensed Consolidated Balance Sheets as of March 31, 2019 (Unaudited) and December 31, 2018	10
	Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2019 and 2018 (Unaudited)	11
	Condensed Consolidated 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, 2019 and 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	38
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	49
Item 4.	Controls and Procedures	51
	PART II
Item 1.	Legal Proceedings	52
Item 1A.	Risk Factors	52
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	52
Item 3.	Defaults Upon Senior Securities	52
Item 4.	Mine Safety Disclosures	53
Item 5.	Other Information	53
Item 6.	Exhibits	54
SIGNATURES		55

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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, and our strategic relationship with Sanchez Midstream 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 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”);

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SOG’s ability to attract and retain personnel and other resources to perform its obligations under the 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 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 properties utilizing horizontal and vertical drilling, advanced completion technologies, hydraulic stimulation and 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;

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 generally and with respect to the marketing of oil, natural gas and NGLs, 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 production, revenue and cash flow from operating activities are derived from oil and natural gas 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 manage the financial risks where we share with more than one party the costs of drilling, equipping, completing and operating wells, including with respect to the Comanche Assets (as defined in “Item 1. Financial Statements - Note 14. Stockholders’ and Mezzanine Equity”);

the use of competing energy sources, the development of alternative energy sources and 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 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 guidelines with respect to derivatives, hedging activities and 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 “development costs,” “development project,” “development well,” “economically producible,” “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.

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

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: 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.

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.

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 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 oil and natural gas.

MBbls: One thousand Bbls.

MBoe: One thousand Boe.

Mcf: One thousand cubic feet of natural gas.

MMBbls: One million Bbls.

MMBoe: One million Boe.

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.

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

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.

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.

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.

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 feet (e.g., 600 foot well-spacing) and is often established by regulatory agencies.

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.

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.

WTI: West Texas Intermediate oil.

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PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

Sanchez Energy Corporation

Condensed Consolidated Balance Sheets

(in thousands, except par value and share amounts)


	March 31,		December 31,
	2019		2018
ASSETS		(Unaudited)
Current assets:
Cash and cash equivalents	$	200,698	$	197,613
Oil and natural gas receivables		79,022		87,222
Joint interest billings receivables		20,367		33,263
Accounts receivable - related entities		9,286		6,099
Fair value of derivative instruments		1,372		15,714
Other current assets		27,813		33,070
Total current assets		338,558		372,981
Oil and natural gas properties, on the basis of successful efforts accounting:
Proved oil and natural gas properties		3,817,836		3,792,431
Unproved oil and natural gas properties		317,377		328,643
Total oil and natural gas properties		4,135,213		4,121,074
Less: Accumulated depreciation, depletion, amortization and impairment		(1,827,245)		(1,761,949)
Total oil and natural gas properties, net		2,307,968		2,359,125

Other assets:
Fair value of derivative instruments		6,667		12,102
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		52,959		59,088
Total assets	$	3,046,563	$	2,819,960
LIABILITIES AND STOCKHOLDERS' DEFICIT
Current liabilities:
Accounts payable	$	11,863	$	32,382
Other payables		124,802		74,628
Accrued liabilities:
Capital expenditures		15,252		61,970
Other		90,819		102,728
Fair value of derivative instruments		22,843		706
Short term debt		245		304
Short term lease liabilities		102,508		—
Other current liabilities		23,826		75,581
Total current liabilities		392,158		348,299
Long term debt, net of premium, discount and debt issuance costs		2,396,151		2,395,408
Asset retirement obligations		47,122		46,175
Fair value of derivative instruments		3,090		366
Long term lease liabilities		222,315		—
Other liabilities		653		21,407
Total liabilities		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, 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		1,371,450		1,367,427
Accumulated deficit		(1,859,776)		(1,812,884)
Total stockholders' deficit		(487,287)		(444,523)
Total liabilities and stockholders' deficit	$	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
	March 31,
	2019		2018
REVENUES:
Oil sales	$	128,028	$	155,392
Natural gas liquid sales		40,500		49,305
Natural gas sales		43,049		41,729
Sales and marketing revenues		5,145		4,802
Total revenues		216,722		251,228
OPERATING COSTS AND EXPENSES:
Oil and natural gas production expenses		80,955		71,948
Exploration expenses		1,270		33
Sales and marketing expenses		4,931		4,173
Production and ad valorem taxes		13,050		13,469
Depreciation, depletion, amortization and accretion		67,481		59,248
Impairment of oil and natural gas properties		3,930		948
General and administrative expenses		20,483		22,420
Total operating costs and expenses		192,100		172,239
Operating income		24,622		78,989
Other income (expense):
Interest income		622		742
Other income		826		3,428
Interest expense		(44,553)		(43,920)
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		(2,516)		(3,987)
Preferred unit dividends and distributions		(12,500)		(9,908)
Preferred unit amortization		(7,033)		(5,930)
Net loss attributable to common stockholders	$	(89,391)	$	(24,640)

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

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

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Sanchez Energy Corporation

Condensed Consolidated Statements of Stockholders’ Equity (Deficit)

(Unaudited)

(in thousands)


	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, 2017	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
Issuance of common stock	—		—	—		—	100		1		565		—		566
Dividends on Series A and Series B Preferred stock	—		—	—		—	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)
Restricted stock awards, net of forfeitures	—		—	—		—	283		4		(4)		—		—
Non-cash stock-based compensation	—		—	—		—	—		—		(375)		—		(375)
Net loss	—		—	—		—	—		—		—		(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)

	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
	March 31,
	2019		2018
CASH FLOWS FROM 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		67,481		59,248
Impairment of oil and natural gas properties		3,930		948
Stock-based compensation expense (benefit)		273		(1,273)
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		(276)		(336)
(Gain) loss on investments		(1,517)		1,150
Loss on other assets		858		—
Amortization of deferred gain on Western Catarina Midstream Divestiture		—		(5,929)
Amortization of debt issuance costs		3,154		6,714
Accretion of debt discount, net		416		281
Changes in operating assets and liabilities:
Accounts receivable		22,185		12,984
Accounts receivable - related entities		(3,187)		(332)
Other payables		48,472		2,718
Accrued liabilities		(14,662)		(3,525)
Other current liabilities		(28,174)		(12,411)
Other assets and liabilities, net		(14,094)		4,694
Net cash provided by operating activities		66,158		84,519

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for oil and natural gas properties		(64,788)		(135,907)
Acquisition of oil and natural gas properties		—		2,834
Payments for purchases of other assets, net		(361)		(173)
Proceeds from sale of other assets		4,967		—
Net cash used in investing activities		(60,182)		(133,246)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		—		539,865
Repayment of borrowings		(2,886)		(99,087)
Financing costs		—		(11,940)
Preferred dividends paid		—		(3,987)
Cash paid to tax authority for employee stock-based compensation awards		(5)		(606)
Preferred unit dividends and distributions paid		—		(9,908)
Net cash provided by (used in) financing activities		(2,891)		414,337

Increase in cash and cash equivalents		3,085		365,610
Cash and cash equivalents, beginning of period		197,613		184,434
Cash and cash equivalents, end of period	$	200,698	$	550,044

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

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,” “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 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.

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, 2018 from the audited financial statements filed in its Annual Report on Form 10-K for the fiscal year ended December 31, 2018 (the “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 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, 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 2018 Annual 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 expenses. Actual results could differ materially from those estimates.

Recent Accounting Pronouncements

In June 2018, the FASB issued ASU 2018-07 “Compensation - Stock Compensation (ASC 718) - Improvements to Nonemployee Share-Based Payment Accounting,” which expands the scope of ASC 718, Compensation – Stock Compensation, to include share-based payment transactions for acquiring goods and services from nonemployees. We adopted this ASU effective January 1, 2019, which resulted in our remeasurement of the 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 utilize an expected loss methodology in place of the currently used incurred loss methodology, which will result in the 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, 2019, and earlier adoption is permitted. We are currently in the process of evaluating the impact of adoption of this guidance on our condensed consolidated financial statements.

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In February 2016, the FASB issued ASU 2016-02 “Leases (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 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 ROU asset represents the lessee’s right to use, or control the use of, a specified asset for 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 lease. The Company adopted this standard effective January 1, 2019. We elected the package of practical expedients permitting us to not reassess under the new standard 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 balance sheet and the derecognition of the deferred gain previously recorded on a sale-leaseback transaction as a cumulative effect 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)

No impact was recorded to the condensed consolidated statement of operations related to the adoption of Topic 842.

Note 3. Leases

We determine if an arrangement is a lease at inception. To the extent that we determine an arrangement represents a lease, we classify that lease as an operating lease or a finance lease. We currently do not have any finance leases. We capitalize our operating leases on our consolidated balance sheet 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.

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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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 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 of accounting, our net share of these costs are capitalized as part of oil and natural gas properties on the balance sheet as incurred.

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 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 leases typically do not provide an implicit rate. Accordingly, we are required to use our estimated incremental borrowing rate in determining the present value of lease payments based on the information available at commencement date. Our estimated incremental borrowing rate reflects a reasonable projection of the 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 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.

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Practical Expedients and Accounting Policy Elections

Certain of our lease arrangements include lease and non-lease components. For all existing asset classes with multiple component types, we have utilized the 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 recognition requirements of Topic 842 to our short term leases. Accordingly, we recognize lease payments related to our short term leases in 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 natural gas production expenses on the 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

(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):


	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%

As of March 31, 2019, minimum future payments, including imputed interest, for our long term operating leases under ASC 842 are as follows (in thousands):


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

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As of December 31, 2018, undiscounted minimum future payments for our long term operating leases under ASC 840 were as follows (in thousands):


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


	March 31,		December 31,
	2019		2018
Cash at banks	$	39,733	$	66,426
Money market funds		160,965		131,187
Total cash and cash equivalents	$	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

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. Changes in production rates, levels of reserves, future development costs, and other factors will impact our actual impairment analyses in future periods.

Unproved Properties—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 expirations from changes in the development plan.

Note 7. Debt

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


			March 31,		December 31,
	Interest Rate	Maturity Date	2019		2018
Short Term Debt:				(in thousands)

SR Credit Agreement(1)(2)	Variable	-	$	245	$	304
Total short term debt			$	245	$	304

Long Term Debt:
7.75% Notes	7.75%	June 15, 2021	$	600,000	$	600,000
SN UnSub Credit Agreement(1)	Variable	March 1, 2022		165,000		167,500
4.59% Non-Recourse Subsidiary Term Loan(1)	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
Credit Agreement(3)	Variable	February 14, 2023		—		—
7.25% Senior Secured Notes	7.25%	February 15, 2023		500,000		500,000
				2,441,663		2,444,490
Unamortized discount on Additional 7.75% Notes				(1,996)		(2,222)
Unamortized premium on Additional 6.125% Notes				1,023		1,090
Unamortized discount on 7.25% Senior Secured Notes				(3,984)		(4,241)
Unamortized debt issuance costs				(40,555)		(43,709)
Total long term debt			$	2,396,151	$	2,395,408

(1)

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

(2)

Incurred interest at a weighted-average rate of approximately 6.0% and 6.8% for the three months ended March 31, 2019 and the year ended December 31, 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
	March 31,
	2019		2018
Interest on SR Credit Agreement	$	(225)	$	(348)
Interest on Senior Notes		(38,297)		(33,564)
Interest and commitment fees on SN UnSub Credit Agreement		(2,283)		(2,301)
Interest on Non-Recourse Subsidiary Term Loan		(42)		(47)
Interest, commitment fees and letter of credit fees on Credit Agreement		(136)		(665)
Amortization of debt issuance costs		(3,154)		(6,714)
Amortization of discounts and premium on Senior Notes		(416)		(281)
Total interest expense	$	(44,553)	$	(43,920)

Credit Facilities

Third Amended and Restated Credit Agreement

On February 14, 2018, the Company entered into a revolving credit facility, 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.

As of March 31, 2019, there were no outstanding borrowings under the Credit Agreement. However, on January 10, 2019, a standby letter of credit was issued on our behalf by the lender under the Credit Agreement in the amount of approximately $17.1 million. This letter of credit currently remains outstanding and is undrawn.

As of March 31, 2019, the Company was in compliance with the covenants of the Credit Agreement. 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 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 the lender under the Credit Agreement could terminate the commitment thereunder, accelerate the repayment of debt and require cash collateralization of any letters of credit. Any acceleration of our debt obligations could result in a foreclosure on the collateral securing the debt.

SN UnSub Credit Agreement

On March 1, 2017, SN EF UnSub, LP (“SN UnSub”) entered into a credit agreement for a $500 million revolving credit facility with a maturity date of March 1, 2022 (the “SN UnSub Credit Agreement”). On December 10, 2018, as part of the most recent semi-annual redetermination, the borrowing base under the SN UnSub Credit Agreement was decreased from $380 million to $315 million and may be further reduced in the future. The next regularly scheduled borrowing base redetermination is expected in the second quarter 2019.

As of March 31, 2019, there were approximately $165.0 million of borrowings and no letters of credit outstanding under the SN UnSub Credit Agreement. Additionally, as of March 31, 2019 SN UnSub was in compliance with the 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 in compliance with the financial covenants of the SR Credit Agreement.

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Senior Notes

7.75% Senior Notes Due 2021

On June 13, 2013, the 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”). 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.

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 that will mature on January 15, 2023 (the “Original 6.125% Notes”). 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.

7.25% Senior Secured First Lien Notes due 2023

On February 14, 2018, the Company 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”) at an issue price of 99.0% of the principal amount.

Note 8. Derivative Instruments

Hedging activities, which are governed by the terms of our Credit Agreement, 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 (a) lenders, or affiliates of lenders, to the SN UnSub Credit Agreement, or (b) counterparties designated as secured with and 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-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.

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


	April 1 - December 31, 2019		2020		2021
Oil positions:
Fixed price swaps (NYMEX WTI):
Hedged volume (Bbls)		2,339,000		1,055,560		216,000
Average price ($/Bbl)	$	51.89	$	55.36	$	57.10

Natural gas positions:
Fixed price swaps (NYMEX Henry Hub):
Hedged volume (MMBtu)		13,105,000		6,893,150		1,440,000
Average price ($/MMBtu)	$	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, 2019 and the year ended December 31, 2018 (in thousands):


	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 and fractionation services that contain provisions that 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 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 marked these derivatives to market and, as a result, recorded gains of approximately $0.3 million and $0.1 million for the three months ended March 31, 2019 and 2018, respectively. Any gains or losses related to embedded derivatives are recorded as a component of other income (expense) in the consolidated statement of operations.

Earnout Derivative: We are entitled to receive earnout payments from SNMP based on natural gas delivered above a threshold volume and a tariff at certain pipeline 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 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		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 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

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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

A subsidiary of the Company owns 1,500,000 shares of Class A Common Stock of Lonestar Resources US Inc. (“Lonestar”). As of March 31, 2019, this ownership represents approximately 6.1% of Lonestar’s outstanding shares of common stock. The Company accounts for the investment in Lonestar as 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 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.

A subsidiary of the Company owns 100 Class A Units of Gavilan Resources Holdco, LLC (“GRHL”). Tranches representing 20% of the Class A Units vest on each of the first five anniversaries 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 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, 2019, the carrying value of the investment in GRHL was $7.3 million. The Company did not record any earnings or distributions from its ownership of the Class A Units for the period from January 1, 2018 through March 31, 2019.

A subsidiary of the Company owns 2,272,727 common units of SNMP. As of March 31, 2019, this ownership represents approximately 12.5% of SNMP’s outstanding common units. The Company elected the fair value option to account for its interest in SNMP and records the equity investment at fair value at the end of each reporting period. For the three months ended March 31, 2019 and 2018, the Company recorded a gain of $1.0 million and a loss of $1.7

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million, respectively, related to the investment in SNMP. In addition, for the three months ended March 31, 2019 and 2018, the Company recorded dividend income of approximately $0.3 million and $1.0 million, respectively, from quarterly distributions on the 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 upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

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, 2019 and December 31, 2018 (in thousands):


	As of March 31, 2019
	Active Market
	for Identical		Observable		Unobservable		Total
	Assets		Inputs		Inputs		Carrying
	(Level 1)		(Level 2)		(Level 3)		Value
Cash and cash equivalents:
Cash equivalents	$	160,965	$	—	$	—	$	160,965
Equity investments:
Investment in SNMP		4,886		—		—		4,886
Investment in Lonestar		6,015		—		—		6,015
Oil derivative instruments:
Swaps		—		(24,501)		—		(24,501)
Gas derivative instruments:
Swaps		—		781		—		781
Other:
Earnout derivative asset		—		—		5,826		5,826
Total	$	171,866	$	(23,720)	$	5,826	$	153,972

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	As of December 31, 2018
	Active Market
	for Identical		Observable		Unobservable		Total
	Assets		Inputs		Inputs		Carrying
	(Level 1)		(Level 2)		(Level 3)		Value
Cash and cash equivalents:
Cash equivalents	$	131,187	$	—	$	—	$	131,187
Equity investments:
Investment in SNMP		3,909		—		—		3,909
Investment in Lonestar		5,475		—		—		5,475
Oil derivative instruments:
Swaps		—		20,608		—		20,608
Gas derivative instruments:
Swaps		—		586		—		586
Other:
Embedded derivative instruments		—		(308)		—		(308)
Earnout derivative asset		—		—		5,858		5,858
Total	$	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, 2019 and December 31, 2018. The Company’s money market funds and time deposits represent cash equivalents held with banks and financial institutions. The Company identified the money market funds and time deposits as Level 1 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. and there are active markets for the underlying investments. In addition, the Level 1 instruments include the Company’s equity investments in SNMP and Lonestar which are publicly traded companies.

The Company’s commodity derivative instruments consist of swaps as of March 31, 2019 and December 31, 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, and therefore are 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, 2019 or December 31, 2018.

Embedded Derivatives: The Company believes that substantially all of the inputs required to calculate the embedded derivatives 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 inputs.

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Earnout Derivative: These payments were deemed to be a derivative which 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,		December 31,
	2019		2018
Beginning balance	$	5,858	$	—
Initial fair value of earnout derivative		—		6,401
Loss on earnout derivatives		(32)		(543)
Ending balance	$	5,826	$	5,858

Fair Value on a Non‑Recurring Basis

In connection with the voluntary conversions by 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, Series B (the “Series B Preferred Stock”) into shares of the Company’s common stock in February and March 2019, the Company issued common stock according to the conversion rate established by the Certificates of Designations for the Series A Preferred Stock and Series B Preferred 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. As there is an active market for the Company’s common stock, the Company has designated this fair value measurement as Level 1. 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, 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 $89.3 million as of March 31, 2019 and was calculated using quoted market prices based on trades of such debt as of that 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 $166.8 million as of March 31, 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 $402.5 million as of March 31, 2019.

Note 11. Asset Retirement Obligations

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


	Three Months Ended		Year Ended
	March 31,		December 31,
	2019		2018
Abandonment liability, beginning of period	$	46,175	$	36,098
Liabilities incurred during period		—		1,965
Divestitures		—		(158)
Revisions		—		5,077
Accretion expense		947		3,193
Abandonment liability, end of period	$	47,122	$	46,175

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Note 12. Related Party Transactions

Sanchez Oil and Gas Corporation

Expenses allocated to the Company from SOG 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 $17.9 million, respectively.

As of March 31, 2019 and December 31, 2018, the Company had a net receivable from SOG and its affiliates of $9.3 million and $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, 2019 and December 31, 2018 consists primarily of advances related to general and administrative and other costs paid to SOG.

Sanchez Midstream Partners

As of March 31, 2019 and December 31, 2018, the Company had a net payable to SNMP of approximately $3.3 million and $3.9 million, respectively, that consists primarily of fees associated with oil and natural gas gathering and transportation services.

Note 13. Accrued Liabilities and Other Current Liabilities

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


	March 31,		December 31,
	2019		2018
Capital expenditures	$	15,252	$	61,970
Other:
General and administrative expenses		17,551		19,460
Production taxes		4,563		5,157
Ad valorem taxes		4,711		445
Lease operating expenses		27,825		24,138
Interest payable		32,776		47,866
Other accrued liabilities		3,393		5,662
Total accrued liabilities	$	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 current liabilities as of March 31, 2019 and December 31, 2018 (in thousands):


	March 31,		December 31,
	2019		2018
Operated prepayment liability	$	23,795	$	51,844
Deferred gain on Western Catarina Midstream Divestiture - short term		—		23,720
Phantom compensation payable - short term		31		17
Total other current liabilities	$	23,826	$	75,581

Note 14. Stockholders’ and Mezzanine Equity

Series A Preferred Stock

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, 2019, based on the initial conversion price, approximately 1,814,502 shares of common stock would be issuable upon conversion of all of the outstanding shares of the Series A Preferred Stock.

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 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, beginning with the three month period ended March 31, 2019, the Board determined to suspend the dividend on our Series A Preferred Stock. Dividends accumulated through that date have been accrued.

Series B Preferred Stock

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, 2019, based on the initial conversion price, approximately 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, beginning with the three month period ended March 31, 2019, the Board determined to suspend the dividend on our Series B Preferred Stock. Dividends accumulated through that date have been accrued.

Preferred Stock Conversions

On February 12, 2019, 72,500 shares of Series A Preferred Stock converted into 168,563 shares of our common stock and 245,832 shares of Series B Preferred Stock converted into 574,510 shares of our common stock at the election of the holders thereof. From March 6 to March 8, 2019, 563,832 shares of Series A Preferred Stock converted into 1,310,914 shares 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 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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Through the conversions, each of the 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 shares outstanding prior to these conversions.

SN UnSub Preferred Unit Issuance

On March 1, 2017, the Company, 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 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”) (the “Comanche Acquisition”).

At the closing of the Comanche Acquisition, certain funds managed or advised by GSO Capital Partners L.P. purchased 485,000 preferred units of SN UnSub and Intrepid Private Equity V-A LLC purchased 15,000 preferred units of SN UnSub (in aggregate, the “SN UnSub Preferred Units”). The SN UnSub Preferred Units are accounted for as mezzanine equity in the condensed consolidated balance sheet consisting of the following as of March 31, 2019 and December 31, 2018, respectively, (in thousands):


	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 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, 2019 and 2018 (in thousands, except per share amounts):


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

Note 15. Stock‑Based Compensation

The Company’s Third Amended and Restated Long Term Incentive Plan (the “LTIP”) allows for grants of stock options, stock appreciation rights, restricted shares, phantom stock, other stock based awards or stack awards, or any combination thereof.

Effective January 1, 2019, the Company records stock-based compensation expense for awards granted 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 – Stock Compensation”, to include share-based payment transactions for acquiring goods and services from nonemployees. Pursuant to this standard, stock-based compensation expense is based on the grant-date fair value of our stock awards and is recognized over the vesting period using the straight-line method. As a result of our adoption of ASU 2018-07, the Company remeasured the value of our outstanding unvested awards as of January 1, 2019. This did not have a material impact on our financial statements.

During the three months ended March 31, 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 an immaterial number of shares of 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 vest in equal annual amounts over a three year period.

For the 2018 performance period applicable to our performance phantom stock awards granted in 2017 (the “Performance Awards”), 0% of the target shares were awarded.

For the 2018 performance period applicable to our cash-settled performance-based phantom stock awards and stock-settled performance-based phantom stock awards granted in 2018 (together, the “PBPS Awards”), 71% of the target shares were awarded, equating to 419,430 cash-settled awards and 419,430 stock-settled awards. Stock-based compensation expense for these awards was calculated in accordance with ASC 718 and is being amortized over the vesting period.

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
	March 31,
	2019		2018
Restricted stock awards, directors	$	18	$	297
Restricted stock awards, non-employees		75		(204)
Performance awards		48		(468)
Phantom stock awards		132		(898)
Total stock-based compensation expense (benefit)	$	273	$	(1,273)

Based on the $0.20 per share closing price of the Company’s common stock on March 31, 2019, there was approximately $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 2.03 years.

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

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

Based on the estimated per share price of the Performance Awards on March 31, 2019, there was 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 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, 2019 and 2018 is presented below (in thousands):


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

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

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


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

Note 16. Income Taxes

The Company used a year-to-date effective tax rate method for recording income taxes for the three month periods ended March 31, 2019 and 2018. This method is based on our determination at March 31, 2019 and 2018 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 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 effective tax rate for the three months ended March 31, 2019 and 2018 was (0.7%) and 0%, 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 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 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, 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, 2019, the Company had no material uncertain tax positions.

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.

Catarina Drilling Commitment

In the Catarina area, we have a drilling commitment that requires us to drill (i) 50 wells in each 12-month period commencing 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. 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. 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 additional activity needed to fulfill the commitment to drill at least one well in any 120-day period.

Comanche Drilling Commitment

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 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. 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 are jointly and severally liable to Anadarko E&P Onshore, LLC for a default fee of $0.2 million for each

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well we do not timely complete and equip. 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.

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, 2019, the Company had approximately $437.7 million in future commitments related to oil and natural gas gathering and transportation agreements ($172.3 million for 2019 through 2021, $128.8 million from 2022 through 2024, and $136.6 million under commitments expiring after December 31, 2024, in the aggregate) and approximately $52.0 million in future commitments related to natural gas processing agreements ($51.3 million for 2019 through 2021, and $0.7 million from 2022 through 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 and natural gas production expenses” line item. We expect to have additional expenses in 2019 related to our volume 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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A summary of the condensed consolidated guarantor balance sheets for the periods ended March 31, 2019 and December 31, 2018 is presented below (in thousands):


	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


	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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A summary of the condensed consolidated guarantor statements of operations 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
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)


	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 condensed consolidated guarantor statements of cash flows 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

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	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

Note 19. Variable Interest Entities

The 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 January 1, 2018 through March 31, 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.

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 $4.9 million and $3.9 million, respectively.

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, 2019 and December 31, 2018 (in thousands):


	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.

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 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

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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 million for 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 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, 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, the actions of 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 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 price swaps by agreeing to increase the notional quantity hedged or extend the notional quantity settlement period under a 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 regulated by, as applicable, the terms of the Credit Agreement, the SN UnSub Credit Agreement and 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 (a) lenders, or affiliates of lenders, to the SN UnSub Credit Agreement, or (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 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” for a description of all of our derivatives covering anticipated future production as of March 31, 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 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, 2019, the fair value of our commodity derivative contracts was a net liability of approximately $23.7 million. A 10% increase or decrease in the oil and natural gas index prices above the March 31, 2019 prices would result in a decrease or increase, respectively, in the fair value of our commodity derivative contracts of $26.6 million. On a 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 production to a limited number of 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

As of March 31, 2019, we had no borrowings outstanding under the Credit Agreement, $165.0 million outstanding under the SN UnSub Credit Agreement and $23.2 million outstanding under the SR Credit Agreement, all of which carry variable interest rates. Our senior notes bear interest at fixed interest 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 approximately $1.7 million change in annual interest expense. We believe our exposure to interest-related losses at March 31, 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 our variable rate indebtedness.

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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, 2019 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. The adoption of ASC 842, Leases, required the implementation of new controls and the modification of certain accounting 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 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

Carefully consider the risk factors under the caption “Risk Factors” under Part I, Item 1A in our 2018 Annual Report, together with all of the other information included in this Quarterly Report on Form 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

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, 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

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).

10.1	(a)		First Amendment to Amended and Restated Agreement of Limited Partnership of SN EF UnSub, LP, among SN EF UnSub GP, LLC, GSO ST Holdings LP, and 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, 2019.


	SANCHEZ ENERGY CORPORATION

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

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