UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10‑Q

(Mark One)

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☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 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)

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

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.

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 ☒

Number of shares of Registrant’s common stock, par value $0.01 per share, outstanding as of November 4, 2019: 100,154,182

Sanchez Energy Corporation (Debtor-in-Possession)

Form 10‑Q

For the Quarterly Period Ended September 30, 2019

Table of Contents

	PART I
Item 1.	Financial Statements	9
	Condensed Consolidated Balance Sheets as of September 30, 2019 (Unaudited) and December 31, 2018	9
	Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2019 and 2018 (Unaudited)	10
	Condensed Consolidated Statements of Stockholders’ Deficit for the Nine Months Ended September 30, 2019 and 2018 (Unaudited)	11
	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 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	53
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	76
Item 4.	Controls and Procedures	79
	PART II
Item 1.	Legal Proceedings	79
Item 1A.	Risk Factors	80
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	80
Item 3.	Defaults Upon Senior Securities	80
Item 4.	Mine Safety Disclosures	81
Item 5.	Other Information	81
Item 6.	Exhibits	82
SIGNATURES		83

2

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 relate to certain assumptions made based on management’s experience, perception of historical trends and technical analyses, current conditions, anticipated future developments and other factors we believe to be appropriate and reasonable. 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 similar 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 the outcome of the Chapter 11 Cases (as defined below), our restructuring plans and our ability to increase our financial flexibility, 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, there can be no assurance 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:

· risks and uncertainties associated with the Chapter 11 Cases, including our ability to develop, confirm and consummate a plan of reorganization under Chapter 11 or an alternative restructuring transaction, which may be necessary to continue as a going concern;

· our ability to maintain relationships with suppliers, customers, employees and other third parties as a result of our filing of the Bankruptcy Petitions (as defined below);

· our ability to obtain sufficient financing to allow us to emerge from bankruptcy and execute our business plan post-emergence;

· the length of time that the Company will operate under Chapter 11 protection and the continued availability of operating capital during the pendency of the Chapter 11 Cases;

· our ability to obtain Bankruptcy Court (as defined below) approval of the various motions and forms of orders, including with respect to our DIP Facility (as defined below), and risks associated with third-party motions in the Chapter 11 Cases, which may interfere with our ability to confirm and consummate a plan of reorganization or an alternative restructuring transaction;

· the potential adverse effects of the Chapter 11 Cases on our liquidity and results of operations;

· increased professional fees and advisory costs to execute a reorganization;

· 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 comply with the financial and other covenants in our debt instruments, including our DIP Facility, 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 pursue drilling plans and acquisitions that are successful in maintaining and economically developing our acreage, producing and replacing reserves and achieving anticipated production levels;

3

· our ability to realize the benefits of our various acquired assets, 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 our current low share price, our listing in the over-the-counter market rather than on a national securities exchange and our ongoing Chapter 11 Cases 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”);

· 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 Inc. (“Blackstone”);

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

· 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 effectiveness of our internal control over financial reporting;

· 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 or for which we owe an indemnity;

· 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;

4

· 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. Notes to the Condensed Consolidated 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;

· 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 stimulation 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.

5

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.

6

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.

natural gas liquids (“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.

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.

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.

7

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

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

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

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

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

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

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

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 natural 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.

8

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

Sanchez Energy Corporation (Debtor-in-Possession)

Condensed Consolidated Balance Sheets

(in thousands, except par value and share amounts)

	September 30,		December 31,
	2019		2018
ASSETS		(Unaudited)
Current assets:
Cash and cash equivalents	$	179,538	$	197,613
Oil and natural gas receivables		69,290		87,222
Joint interest billings receivables		10,979		33,263
Accounts receivable - related entities		10,161		6,099
Fair value of derivative instruments		6,263		15,714
Other current assets		24,679		33,070
Total current assets		300,910		372,981
Oil and natural gas properties, on the basis of successful efforts accounting:
Proved oil and natural gas properties		3,864,327		3,792,431
Unproved oil and natural gas properties		299,456		328,643
Total oil and natural gas properties		4,163,783		4,121,074
Less: Accumulated depreciation, depletion, amortization and impairment		(1,947,558)		(1,761,949)
Total oil and natural gas properties, net		2,216,225		2,359,125
Other assets:
Fair value of derivative instruments		9,346		12,102
Right of use assets, net		280,139		—
Investments (includes investment in SNMP measured at fair value of $0.8 million and $3.9 million as of September 30, 2019 and December 31, 2018, respectively)		12,200		16,664
Other assets		43,990		59,088
Total assets	$	2,862,810	$	2,819,960
LIABILITIES AND STOCKHOLDERS' DEFICIT
Current liabilities:
Debtor-in-possession financing	$	50,000	$	—
Accounts payable		14,372		32,382
Other payables		16,739		74,628
Accrued liabilities:
Capital expenditures		7,232		61,970
Other		66,298		102,728
Fair value of derivative instruments		700		706
Short term debt		—		304
Short term lease liabilities		109,494		—
Other current liabilities		31,961		75,581
Total current liabilities		296,796		348,299
Long term debt, net of premium, discount and debt issuance costs		166,956		2,395,408
Asset retirement obligations		49,183		46,175
Fair value of derivative instruments		—		366
Long term lease liabilities		173,990		—
Liabilities subject to compromise		2,398,106		—
Other liabilities		1		21,407
Total liabilities		3,085,032		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 September 30, 2019 and December 31, 2018)		474,857		452,828
Stockholders' deficit:
Preferred stock ($0.01 par value, 15,000,000 shares authorized; 619,503 and 1,838,985 shares issued and outstanding as of September 30, 2019 and December 31, 2018, respectively, of 4.875% Convertible Perpetual Preferred Stock, Series A; 2,466,013 and 3,527,830 shares issued and outstanding as of September 30, 2019 and December 31, 2018, respectively, of 6.500% Convertible Perpetual Preferred Stock, Series B)		31		53
Common stock ($0.01 par value, 300,000,000 shares authorized; 100,154,824 and 87,328,424 shares issued and outstanding as of September 30, 2019 and December 31, 2018, respectively)		1,014		881
Additional paid-in capital		1,371,698		1,367,427
Accumulated deficit		(2,069,822)		(1,812,884)
Total stockholders' deficit		(697,079)		(444,523)
Total liabilities and stockholders' deficit	$	2,862,810	$	2,819,960

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

9

Sanchez Energy Corporation (Debtor-in-Possession)

Condensed Consolidated Statements of Operations (Unaudited)

(in thousands, except per share amounts)

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2019		2018		2019		2018
REVENUES:
Oil sales	$	106,016	$	161,243	$	362,424	$	473,178
Natural gas liquid sales		22,675		69,995		92,891		175,833
Natural gas sales		26,572		39,460		100,932		122,330
Sales and marketing revenues		7,283		7,012		18,103		16,910
Total revenues		162,546		277,710		574,350		788,251
OPERATING COSTS AND EXPENSES:
Oil and natural gas production expenses		74,740		75,594		231,441		225,186
Exploration expenses		164		2,698		4,983		3,247
Sales and marketing expenses		6,672		7,239		16,591		16,498
Production and ad valorem taxes		9,867		15,221		34,682		42,898
Depreciation, depletion, amortization and accretion		57,864		67,944		187,920		189,515
Impairment of oil and natural gas properties		9,761		3,117		22,906		4,259
General and administrative expenses		20,915		21,312		66,266		73,199
Prepetition restructuring charges		18,231		—		41,855		—
Total operating costs and expenses		198,214		193,125		606,644		554,802
Operating income (loss)		(35,668)		84,585		(32,294)		233,449
Other income (expense):
Interest income		221		1,130		1,447		3,400
Other income (expense)		(12,829)		(7,677)		(13,785)		2,467
Gain on sale of oil and natural gas properties		—		—		—		1,528
Interest expense		(22,884)		(44,154)		(111,998)		(132,664)
Net gains (losses) on commodity derivatives		13,200		(28,286)		(20,827)		(142,384)
Total other expense		(22,292)		(78,987)		(145,163)		(267,653)
Reorganization items		55,321		—		55,321		—
Income (loss) before income taxes		(113,281)		5,598		(232,778)		(34,204)
Income tax benefit		(833)		—		(23)		—
Net income (loss)		(112,448)		5,598		(232,755)		(34,204)
Less:
Preferred stock dividends		(2,312)		(3,987)		(7,153)		(11,961)
Preferred unit dividends and distributions		(12,500)		(12,500)		(37,500)		(34,908)
Preferred unit amortization		(7,638)		(6,458)		(22,029)		(18,577)
Net loss attributable to common stockholders	$	(134,898)	$	(17,347)	$	(299,437)	$	(99,650)
Net loss per common share - basic and diluted	$	(1.39)	$	(0.21)	$	(3.14)	$	(1.22)
Weighted average number of shares used to calculate net loss attributable to common stockholders - basic and diluted		97,395		82,073		95,272		81,597

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

10

Sanchez Energy Corporation (Debtor-in-Possession)

Condensed Consolidated Statements of Stockholders’ 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, 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)
Dividends on Series A and Series B Preferred Stock	—		—	—		—	—		—		—		(2,325)		(2,325)
Dividends on SN UnSub Preferred Units	—		—	—		—	—		—		—		(12,500)		(12,500)
Accretion of discount on SN UnSub Preferred Units	—		—	—		—	—		—		—		(7,358)		(7,358)
Restricted stock awards, net of forfeitures	—		—	—		—	(81)		4		(4)		—		—
Exchange of preferred stock for common stock	(155)		(1)	—		—	363		2		(1)		—		—
Non-cash stock-based compensation	—		—	—		—	—		—		158		—		158
Net loss	—		—	—		—	—		—		—		(52,965)		(52,965)
BALANCE, June 30, 2019	625		6	2,511		25	100,076		1,013		1,371,603		(1,934,924)		(562,277)
Dividends on Series A and Series B Preferred Stock	—		—	—		—	—		—		—		(2,312)		(2,312)
Dividends on SN UnSub Preferred Units	—		—	—		—	—		—		—		(12,500)		(12,500)
Accretion of discount on SN UnSub Preferred Units	—		—	—		—	—		—		—		(7,638)		(7,638)
Restricted stock awards, net of forfeitures	—		—	—		—	(38)		(1)		1		—		—
Exchange of preferred stock for common stock	(5)		—	(45)		—	117		2		(2)		—		—
Non-cash stock-based compensation	—		—	—		—	—		—		96		—		96
Net loss	—		—	—		—	—		—		—		(112,448)		(112,448)
BALANCE, September 30, 2019	620	$	6	2,466	$	25	100,155	$	1,014	$	1,371,698	$	(2,069,822)	$	(697,079)

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Sanchez Energy Corporation (Debtor-in-Possession)

Condensed Consolidated Statements of Stockholders’ Deficit (Continued)

(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)
Dividends on Series A and Series B Preferred Stock	—		—	—		—	—		—		—		(3,987)		(3,987)
Dividends on SN UnSub Preferred Units	—		—	—		—	—		—		—		(12,500)		(12,500)
Accretion of discount on SN UnSub Preferred Units	—		—	—		—	—		—		—		(6,189)		(6,189)
Restricted stock awards, net of forfeitures	—		—	—		—	2,625		26		(26)		—		—
Non-cash stock-based compensation	—		—	—		—	—		—		4,651		—		4,651
Net loss	—		—	—		—	—		—		—		(34,987)		(34,987)
BALANCE, June 30, 2018	1,839	$	18	3,528	$	35	87,798		884		1,370,908		(1,891,720)		(519,875)
Dividends on Series A and Series B Preferred Stock	—		—	—		—	—		—		—		(3,987)		(3,987)
Dividends on SN UnSub Preferred Units	—		—	—		—	—		—		—		(12,500)		(12,500)
Accretion of discount on SN UnSub Preferred Units	—		—	—		—	—		—		—		(6,458)		(6,458)
Restricted stock awards, net of forfeitures	—		—	—		—	(268)		(1)		1		—		—
Non-cash stock-based compensation	—		—	—		—	—		—		(1,398)		—		(1,398)
Net loss	—		—	—		—	—		—		—		5,598		5,598
BALANCE, September 30, 2018	1,839	$	18	3,528	$	35	87,530	$	883	$	1,369,511	$	(1,909,067)	$	(538,620)

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

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Sanchez Energy Corporation (Debtor-in-Possession)

Condensed Consolidated Statements of Cash Flows (Unaudited)

(in thousands)

	Nine Months Ended
	September 30,
	2019		2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(232,755)	$	(34,204)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		187,920		189,515
Impairment of oil and natural gas properties		22,906		4,259
Gain on sale of oil and natural gas properties		—		(1,528)
Stock-based compensation expense		355		4,344
Net losses on commodity derivative contracts		20,827		142,384
Net cash settlements paid on commodity derivative contracts		(5,799)		(69,317)
(Gain) loss on other derivatives		(276)		5,262
Loss on investments		4,464		3,361
Loss (gain) on sale of inventory		143		(571)
Loss on other assets		858		—
Loss on prepaid asset impairment		11,755		—
Amortization of deferred gain on Western Catarina Midstream Divestiture		—		(17,790)
Amortization of debt issuance costs		8,275		12,706
Accretion of debt discount, net		1,019		1,112
Reorganization items		39,238		—
Changes in operating assets and liabilities:
Accounts receivable		41,305		1,982
Accounts receivable - related entities		(4,062)		(3,365)
Other payables		(40,452)		8,537
Accrued liabilities		59,218		17,595
Other current liabilities		(20,519)		(12,531)
Other assets and liabilities, net		5,330		(2,225)
Net cash provided by operating activities		99,750		249,526
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for the development of oil and natural gas properties		(114,655)		(452,296)
Proceeds from the sale of oil and natural gas properties		—		1,425
Acquisition of oil and natural gas properties		—		2,834
Payments for purchases of other assets		(761)		(9,573)
Proceeds from the sale of other assets		5,199		3,788
Net cash used in investing activities		(110,217)		(453,822)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings, including borrowings under DIP Facility		57,922		539,865
Repayment of borrowings		(18,327)		(103,262)
Financing costs, including costs related to DIP Facility		(9,505)		(12,995)
Preferred dividends paid		—		(11,961)
Cash paid to tax authority for employee stock-based compensation awards		(198)		(705)
Preferred unit distributions paid		(37,500)		(22,408)
Net cash (used in) provided by financing activities		(7,608)		388,534
(Decrease) increase in cash and cash equivalents		(18,075)		184,238
Cash and cash equivalents, beginning of period		197,613		184,434
Cash and cash equivalents, end of period	$	179,538	$	368,672
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Change in asset retirement obligations	$	129	$	1,532
Change in accrued capital expenditures		(54,871)		24,652
ROU assets obtained in exchange for operating lease obligations		361,648		—
SUPPLEMENTAL DISCLOSURE:
Cash paid for interest	$	84,803	$	120,775
Cash paid for reorganization items	$	9,521	$	—

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

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Sanchez Energy Corporation (Debtor-in-Possession)

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 have other producing properties and undeveloped acreage, including in the Tuscaloosa Marine Shale (“TMS”) in Mississippi and Louisiana, as well as other locations in Louisiana and Texas, which may offer potential future development opportunities. As of September 30, 2019, we held approximately 435,000 gross (233,000 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 or divestiture of such properties will generally depend on the circumstances and market conditions at the time we consider such opportunities. As discussed in “—Note 3. Chapter 11 Cases,” we are currently operating our business as “debtors-in-possession” in accordance with the applicable provisions of the Bankruptcy Code (as defined below).

Liquidity

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.

As previously disclosed, the Company substantially reduced its capital expenditures from approximately $593 million in 2018 to a budgeted amount of $100 to $150 million for 2019 in order to preserve capital in the current low and uncertain commodity price environment. As discussed in “Part I, Item 1. Notes to the Condensed Consolidated Financial Statements—Note 17. Commitments and Contingencies,” the Company is party to certain agreements that require it to meet annual drilling and development commitments to maintain undeveloped leasehold positions. To reduce its capital expenditures by this magnitude in 2019, the Company exercised privileges under certain of such agreements (primarily by utilizing well “banks” achieved through drilling and developing wells in excess of the quantity required to maintain the related acreage during prior annual periods) and negotiated deferral arrangements. If the Company is unable to negotiate additional extensions, deferrals, waivers or other similar arrangements to delay or otherwise reduce the activity necessary to maintain such undeveloped leasehold positions, it may be unable to continue to hold capital expenditures at comparable low levels in future years. As a result, the Company may be required to seek additional funding sources in order to pursue development plans which would maintain certain of its undeveloped acreage.

In addition, commodity prices remain depressed, and the Company’s oil, natural gas and NGL production has declined in connection with reduced development activity.  Lower commodity prices and declining production have adversely impacted the Company’s revenues and cash flow. This has led to a reduction in forecasted liquidity, which has affected the Company’s ability to service the significant obligations associated with its high level of indebtedness.

To improve its liquidity and position the Company for future success, Sanchez Energy undertook a review of various strategic alternatives with its advisors and Board of Directors (the “Board”) beginning in 2018. In anticipation of potential liquidity constraints, the Company commenced discussions with its bondholders, other stakeholders and potential third-party investors on a restructuring transaction to reduce the Company’s debt and strengthen its overall financial flexibility. On July 15, 2019, the Company elected to defer making an interest payment of approximately $35.2 million on the Company’s 6.125% Notes (as defined below) for a 30-day grace period, which expired on August 14, 2019, in order to preserve liquidity and continue discussions with stakeholders. The Debtors filed their Bankruptcy Petitions on the Petition Date (as defined below), prior to the expiration of the grace period. Although the Company has not yet reached an agreement with any of its stakeholders on the terms of a comprehensive restructuring transaction, the Company obtained additional financing pursuant to the DIP Facility (as defined below) on an interim basis, as discussed below.

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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 September 30, 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 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 for purposes of making these calculations.

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

Bankruptcy Accounting

As further discussed in “—Note 3. Chapter 11 Cases,” on August 11, 2019 (the “Petition Date”), Sanchez Energy Corporation, SN Palmetto, LLC, SN Marquis LLC, SN Cotulla Assets, LLC, SN Operating, LLC, SN TMS, LLC, SN Catarina, LLC, Rockin L Ranch Company, LLC, SN Payables, LLC, SN EF Maverick, LLC (“SN Maverick”) and SN UR Holdings, LLC (“SN UR Holdings”) (each a “Debtor” and collectively, the “Debtors”) filed voluntary petitions (the “Bankruptcy Petitions”) for reorganization under Chapter 11 of the U.S. Bankruptcy Code (the “Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”).

The condensed consolidated financial statements have been prepared as if the Company is a going concern and reflect the application of Accounting Standards Codification 852 “Reorganizations”  (“ASC 852”). ASC 852 requires that the financial statements, for periods subsequent to the filing of the Bankruptcy Petitions, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that are realized or incurred in the bankruptcy proceedings are recorded in “Reorganization items” on the Company’s condensed consolidated statements of operations. In addition, prepetition 

15

unsecured and under-secured obligations that may be impacted by the bankruptcy reorganization process have been classified as “Liabilities subject to compromise” on the Company’s condensed consolidated balance sheet at September 30, 2019. These liabilities are reported at the amounts expected to be allowed as claims by the Bankruptcy Court, although they may be settled for less. The Company has not taken a view with respect to the ultimate recoveries or payments under these agreements or on account of these liabilities in the presentation of such amounts on the financial statements.

The accompanying condensed consolidated financial statements do not purport to reflect or provide for the consequences of the Chapter 11 Cases. In particular, the condensed consolidated financial statements do not purport to show: (i) the realizable value of assets on a liquidation basis or their availability to satisfy liabilities; (ii) the amount of prepetition liabilities that may be allowed for claims or contingencies, or the status and priority thereof; (iii) the effect on stockholders’ deficit accounts of any changes that may be made to the Company’s capitalization; or (iv) the effect on operations of any changes that may be made to the Company’s business. While operating as debtors-in-possession under Chapter 11 of the Bankruptcy Code, the Debtors may sell or otherwise dispose of or liquidate assets or settle liabilities in amounts other than those reflected on the Company’s condensed consolidated financial statements, subject to the approval of the Bankruptcy Court or otherwise as permitted in the ordinary course of business. Further, a plan of reorganization could materially change the amounts and classifications on the Company’s historical condensed consolidated financial statements.

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 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 (“G&A”) 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.

16

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 ASC 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 ASC 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. Chapter 11 Cases

Voluntary Reorganization Under Chapter 11

On the Petition Date, the Debtors filed the Bankruptcy Petitions for reorganization under the Bankruptcy Code in the Bankruptcy Court. The Debtors filed a motion with the Bankruptcy Court seeking to jointly administer the Chapter 11 Cases under the caption In re Sanchez Energy Corporation, Case No. 19-34508. The Debtors also filed various motions with the Bankruptcy Court, which were approved, seeking authorization to continue to operate their businesses as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. Additionally, the Bankruptcy Court has granted certain other relief requested by the Debtors, including interim relief allowing the Company to use its cash to fund the Chapter 11 Cases and to borrow an initial $50 million pursuant to the DIP Facility (as defined below) and giving the Company the authority to, among other things, continue to pay certain vendors and other third parties. During the pendency of the Chapter 11 Cases, all transactions outside the ordinary course of the Company’s business require prior approval of the Bankruptcy Court. The Company expects ordinary course operations to continue substantially uninterrupted during the Chapter 11 Cases. SN UnSub (as defined below), its general partner, and certain other unrestricted subsidiaries of the Company are not included in the Chapter 11 Cases and are classified as “non-Debtors”.

Subject to certain exceptions, under the Bankruptcy Code, the filing of the Bankruptcy Petitions automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or filing of other actions against the Debtors or their property to recover, collect or secure a claim arising prior to the date of the Bankruptcy Petitions. Accordingly, although the filing of the Bankruptcy Petitions triggered defaults on the Debtors’ debt obligations, creditors are stayed from taking any actions against the Debtors as a result of such defaults, subject to certain limited exceptions permitted by the Bankruptcy Code. Substantially all of the Debtors’ prepetition liabilities are subject to settlement and compromise under the Bankruptcy Code.

Under the Bankruptcy Code, unless creditors agree otherwise, prepetition liabilities and postpetition liabilities must be satisfied in full before the Company’s existing stockholders are entitled to receive or retain any property under a plan of reorganization. The ultimate recovery to creditors and/or stockholders, if any, will not be determined until

17

confirmation and implementation of a plan or plans of reorganization. There can be no assurance as to what values, if any, will be ascribed in the Chapter 11 Cases to each of these constituencies or what types or amounts of settlements, if any, they will receive. A plan of reorganization could result in holders of the Debtors’ liabilities and/or stockholders receiving no settlement on account of their interests and cancellation of their holdings.

Executory Contracts

Subject to certain exceptions, under the Bankruptcy Code, the Debtors may assume, assign or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and certain other conditions. Generally, the rejection of an executory contract or unexpired lease is treated as a prepetition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves a Debtor of performing its future obligations under such executory contract or unexpired leases but entitles the contract counterparty or lessor to a prepetition general unsecured claim for damages caused by such deemed breach. Counterparties to such rejected contracts or leases may assert unsecured claims in the Bankruptcy Court against the applicable Debtor’s estate(s) for such damages. Generally, the assumption of an executory contract or unexpired lease requires a Debtor to cure existing monetary defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. Accordingly, any description of an executory contract or unexpired lease with the Debtors in this quarterly report, including where applicable a quantification of a Debtor’s obligations under any such executory contract or unexpired lease with the Debtor, is qualified by any overriding rejection rights such Debtor has under the Bankruptcy Code. Further, nothing herein is or shall be deemed an admission with respect to any claim amounts or calculations arising from the rejection of any executory contract or unexpired lease and the Debtors expressly preserve all of their rights with respect thereto. With limited exceptions, the Debtors have not yet made formal determinations with respect to the assumption or rejection of executory contracts or unexpired leases.

Process for Plan of Reorganization

Following the Petition Date, the Company has continued to engage with stakeholders in pursuit of a comprehensive restructuring transaction.  The Company believes the Chapter 11 Cases provide the most expeditious manner in which to effect a capital structure solution. In order to successfully exit the Chapter 11 Cases, we will need to obtain confirmation by the Bankruptcy Court of a plan (or plans) of reorganization that satisfies the requirements of the Bankruptcy Code. A plan of reorganization would, among other things, resolve the Debtors’ prepetition obligations, set forth the revised capital structure of the newly reorganized entity and provide for corporate governance subsequent to exit from the Chapter 11 Cases. However, there can be no assurance that the Company will be able to reorganize its capital structure on terms acceptable to the Company, the other Debtors, their creditors or other stakeholders, or at all.

The Debtors have the exclusive right for 120 days after the Petition Date to file a plan of reorganization (the “Exclusive Filing Period”), and if the Debtors’ plan of reorganization is filed within the Exclusive Filing Period, the Debtors also have the exclusive right for 180 days after the Petition Date to solicit acceptances and rejections regarding such plan of reorganization, in each case, subject to extension for cause by the Bankruptcy Court. If the Exclusive Filing Period lapses, any party in interest may file a plan of reorganization for any of the Debtors.

In addition to being voted on by holders of impaired claims and equity interests, a plan of reorganization must satisfy certain requirements of the Bankruptcy Code and must be confirmed by the Bankruptcy Court in order to become effective. A plan of reorganization would be accepted by holders of claims against and equity interests in the Company if (i) more than one-half in number and at least two-thirds in dollar amount of allowed claims actually voting in each class of claims impaired by the plan have voted to accept the plan and (ii) at least two-thirds in amount of allowed equity interests actually voting in each class of equity interests impaired by the plan has voted to accept the plan. A class of claims or equity interests that does not receive or retain any property under the plan on account of such claims or interests is deemed to have voted to reject the plan.

Under certain circumstances set forth in Section 1129(b) of the Bankruptcy Code, the Bankruptcy Court may confirm a plan even if such plan has not been accepted by all impaired classes of claims and equity interests. The precise requirements and evidentiary showing for confirming a plan notwithstanding its rejection by one or more impaired classes of claims or equity interests depends upon a number of factors, including the status and seniority of the claims or equity interests in the rejecting class (i.e., secured or unsecured claims, subordinated or senior claims, preferred or common stock). Generally, with respect to common stock or preferred stock interests, a plan may be “crammed down” even if the stockholders receive no recovery if the proponent of the plan demonstrates that (1) no class junior to the

18

common stock or class or series of preferred stock, as applicable, is receiving or retaining property under the plan and (2) no class of claims or interests senior to the common stock or class or series of preferred stock, as applicable, is being paid more than in full.

The timeline for the Debtors to file a plan of reorganization will depend on the timing and outcome of numerous other ongoing matters in the Chapter 11 Cases. There can be no assurance at this time that the Debtors will be able to successfully develop, confirm and consummate a  plan of reorganization or other alternative restructuring transactions that satisfies the conditions of the Bankruptcy Code and is confirmed by the Bankruptcy Court, or that any such plan or transactions will be implemented successfully.

DIP Facility

In connection with the Bankruptcy Petitions, the Debtors filed a motion seeking, among other things, interim and final approval of debtor-in-possession financing on terms and conditions set forth in a proposed Senior Secured Debtor-in-Possession Term Loan Credit Agreement (as amended, supplemented or otherwise modified, the “DIP Facility”) among Sanchez Energy Corporation, as borrower, the financial institutions or other entities from time to time parties thereto, as lenders (the “DIP Lenders”), and Wilmington Savings Fund Society, FSB (“WSFS”), as administrative agent and collateral agent (the “DIP Agent”). The initial lenders under the DIP Facility are members of an ad hoc group of certain holders of the 7.25% Senior Secured Notes (the “Secured Noteholders”) or affiliates of such Secured Noteholders. The DIP Facility was approved by the Bankruptcy Court on an interim basis and the Company closed and borrowed an initial $50 million of new money loans thereunder on August 19, 2019, following the Bankruptcy Court’s entry of an interim order approving the DIP Facility on August 16, 2019. On September 19, 2019, the Bankruptcy Court declined to grant final approval of the DIP Facility at that time, and the Debtors, the DIP Lenders and certain other stakeholders are in ongoing discussions regarding the terms of the DIP Facility that will be presented to the Bankruptcy Court again for final approval at a subsequent hearing. The Company’s ability to access the remaining additional principal amount of new term loans under the DIP Facility is subject to the final approval of the Bankruptcy Court. On September 24, 2019, the Company, the DIP Agent and the Required Lenders (as defined in the DIP Facility) entered into an amendment to the DIP Facility (the “Amendment”). By its terms, the Amendment was effective as of September 20, 2019. The Amendment provided for, among other things, an extension to October 2, 2019  of the milestone date set forth in the DIP Facility for the entry of a final order of the Bankruptcy Court authorizing the Debtors’ entry into the DIP Facility and the other transactions contemplated by the DIP Facility (the “Final DIP Order”) and provided for the further extension of such milestone date with the consent of the Required Lenders. The milestone date set forth in the Loan Agreement for the entry of the Final DIP Order was subsequently extended, as contemplated and permitted by the Amendment, by the Required Lenders until the earlier of (i) November 15, 2019 and (ii) the date on which any of the Debtors files any material motion with respect to the Debtors’ business operations without the prior written consent of the Required Lenders. The DIP Facility, as it was approved on an interim basis, contains the terms as set forth below (although certain of the below terms are subject to modification prior to final approval of the DIP Facility):

· a senior secured priming superpriority debtor-in-possession term loan facility in an aggregate principal amount of up to $350 million, consisting of (i) a new money, multiple draw term loan facility in the amount of $175 million (the “New Money DIP Loans”), backstopped by certain Secured Noteholders (the “Backstop Lenders”), $50 million of which was available on an interim basis upon entry of the Bankruptcy Court’s interim order (the “Interim DIP Order”); and (ii) a refinancing term loan effectuated by way of a conversion of $175 million of 7.25% Senior Secured Notes into obligations under the DIP Facility (the “Roll-Up Loans” and, together with the New Money DIP Loans, the “DIP Loans”);

· borrowings under the (i) New Money DIP Loans will bear interest at a rate per annum equal to adjusted LIBOR (subject to a 2% floor) plus 8.00% and (ii) Roll-Up Loans will bear interest at the non-default rate of the 7.25% Senior Secured Notes of 7.25% per annum;

· the Company has paid the Backstop Lenders a 5.00% fee in cash in exchange for their commitment to backstop the New Money DIP Loans, and the Company is also required to pay  (i) the DIP Lenders a 1.00% fee on the New Money DIP Loans payable upon the Debtors’ emergence from the Chapter 11 Cases and (ii) the DIP Lenders a 0.5% per annum commitment fee on undrawn New Money DIP Loans payable monthly;

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· the maturity of the DIP Facility is nine months after the Petition Date, subject to earlier termination upon occurrence of customary defaults;

· the proceeds of the New Money DIP Loans may be used for: (i) transaction costs, fees and expenses; (ii) working capital and general corporate purposes; (iii) bankruptcy-related costs and expenses (including restructuring fees and adequate protection payments); and (iv) subject to final approval of the Bankruptcy Court, refinancing all amounts existing under the Company’s existing Credit Agreement;

· the obligations under the New Money DIP Loans will be secured (subject to the Carve-Out (as defined below) and certain “first-out” obligations as set forth in the Interim DIP Order) on the following bases: (i) a superpriority administrative claim; (ii) a perfected first priority senior security interest and lien on all unencumbered property (subject to certain exceptions set forth in the DIP Facility and/or the Interim DIP Order); (iii) a perfected first priority, senior priming security interest and lien on all property subject to valid, perfected and nonavoidable prepetition liens securing the obligations under the 7.25% Senior Secured Notes (subject to certain exceptions as specified in the DIP Facility and/or the Interim DIP Order); and (iv) a perfected junior lien on certain other property subject to valid, perfected and unavoidable prepetition liens;

· the obligations under the Roll-Up Loans will be secured (subject to the Carve-Out and certain “first-out” obligations as set forth in the Interim DIP Order) on the following bases: (i) a superpriority administrative claim and (ii) a perfected first priority, senior priming security interest and lien on all property subject to valid, perfected and nonavoidable prepetition liens securing the obligations under the 7.25% Senior Secured Notes (subject to certain exceptions as specified in the DIP Facility and the Interim DIP Order);

· the Debtors’ Chapter 11 Cases are subject to certain milestones, including with respect to the filing and approvals of a disclosure statement and a Chapter 11 plan of reorganization;

· the DIP Facility will provide for certain customary covenants applicable to the Company, including covenants requiring (i) minimum liquidity in an amount of $15 million, subject to certain exclusions; (ii) beginning the first four-week period ending after the Petition Date, compliance with an approved operating debtor-in-possession budget (the “DIP Budget”), subject to permitted variance of 15% (with a variance of 25% for midstream-related disbursements for the first four-week test period), tested on a rolling four-week basis on disbursements excluding certain professional fees, DIP Facility interest and fees and adequate protection payments; and (iii) delivery of a rolling 13-week operating cash flow forecast updated every four weeks and a weekly DIP Budget variance report; and

· the Debtors’ obligations to the DIP Lenders and the liens and superpriority claims are subject in each case to a carve-out (the “Carve-Out”) that accounts for certain administrative, court and legal fees payable in connection with the Chapter 11 Cases.

In addition, the Interim DIP Order contemplates that under the terms of the Final DIP Order, we will be required to pay the approximately $18.1 million in interest that would have been due on August 15, 2019 under the indenture for the 7.25% Senior Secured Notes, and are required to continue to make the semi-annual interest payments as they come due under the indenture for the 7.25% Senior Secured Notes during the Chapter 11 Cases.

There can be no assurance that the DIP Facility will be approved on a final basis, on the terms described above, or at all.  We are in ongoing conversations with the DIP Lenders and other stakeholders regarding the terms of the Final DIP Order and the DIP Facility.

UnSub Tolling Agreement

On August 10, 2019, the Company entered into a tolling agreement (the “Tolling Agreement”) among Sanchez Energy Corporation, SN UR Holdings, SN EF UnSub Holdings, LLC (“SN UnSub Holdings”), SN Maverick (together with Sanchez Energy Corporation, SN UR Holdings and SN UnSub Holdings, the “Sanchez Parties”), GSO ST Holdings Associates LLC (“GSO LLC”) and GSO ST Holdings LP (together with GSO LLC, the “GSO Parties”).

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Pursuant to the terms of the Tolling Agreement, except for participating in, or filing pleadings in respect of, any matter pending before the applicable bankruptcy court, during the Tolling Period (as defined below), the GSO Parties agreed to not exercise any rights or remedies with respect to any Investor Redemption Event, as defined in the Amended and Restated Limited Liability Company Agreement of SN EF UnSub GP, LLC (“SN UnSub GP”), dated March 1, 2017 (the “LLC Agreement”), or the Amended and Restated Agreement of Limited Partnership of SN EF UnSub, LP, dated March 1, 2017, and all notice or cure periods that may exist with respect to any Investor Redemption Event (as such term defined in the LLC Agreement) will be tolled during the Tolling Period.

The Tolling Agreement expires on the calendar day following the occurrence of any of the following events (the “Tolling Period”): (1) the occurrence of any Bankruptcy Event (as defined in the LLC Agreement) with respect to SN UnSub Holdings; provided, however, that unless a notice of termination has been provided by the GSO Parties or there is less than five calendar days before the Order Deadline (as defined below), the Sanchez Parties will be obligated to provide the GSO Parties at least five business days’ written notice prior to commencement of a voluntary chapter 11 proceeding (a “Proceeding”) by SN UnSub Holdings; (2) the failure of Sanchez Energy Corporation, SN Maverick or SN UR Holdings, to the extent such party has commenced a Proceeding (the earliest commencement date of a Proceeding by Sanchez Energy Corporation, SN Maverick or SN UR Holdings, as applicable, the “Initial Petition Date”), to obtain a bankruptcy court order approving the Tolling Agreement by the 20th day after the Initial Petition Date (the “Order Deadline”), unless the parties agree to extend such date by written agreement (the Order Deadline was subsequently extended to September 24, 2019); or (3) the effectiveness of delivery by any party of a written notice of termination of the Tolling Period, with such notice to be effective on the fifth business day following delivery of notice to the other parties.

In the event that SN UnSub Holdings commences a Proceeding at any time, the parties have agreed that for all purposes the commencement by SN UnSub Holdings of a Proceeding will be deemed to have occurred on the Initial Petition Date immediately preceding the commencement of the Proceedings with respect to any other Sanchez entity.

On September 19, 2019, the Bankruptcy Court authorized the Debtors’ performance of their obligations under  the Tolling Agreement.

Liabilities Subject to Compromise

The Company’s condensed consolidated balance sheet includes amounts classified as “Liabilities subject to compromise,” which represent prepetition liabilities that have been allowed, or that the Company anticipates will be allowed, as claims in its Chapter 11 Cases. The amounts represent the Company’s current estimate of known or potential obligations to be resolved in connection with the Chapter 11 Cases. The differences between the liabilities the Company has estimated and the claims filed, or to be filed, will be investigated and resolved in connection with the claims resolution process. The Company will continue to evaluate these liabilities throughout the Chapter 11 Cases and adjust amounts as necessary. Such adjustments may be material.

The following table summarizes the components of liabilities subject to compromise included on the condensed consolidated balance sheet (in thousands):

	September 30, 2019
7.75% Notes, due June 2021	$	600,000
6.125% Notes, due January 2023		1,150,000
Credit Agreement(1)		7,922
7.25% Senior Secured Notes, due February 2023		500,000
Accounts payable		22,349
Other payables		18,329
Accrued interest payable		65,371
Other accrued expenses		34,135
Liabilities subject to compromise	$	2,398,106

(1) 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% through the Petition Date. The letter of credit remains outstanding and is undrawn as of September 30, 2019 but is currently proposed to be cash collateralized subject to entry of the Final DIP Order. 

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Prepetition Restructuring Charges

Any expenses incurred before the Petition Date and in relation to the Chapter 11 Cases are recorded as prepetition restructuring charges on our consolidated statements of operations.

Prepetition restructuring charges, which primarily consisted of professional, consulting and legal fees related to the Chapter 11 Cases, were $18.2 million and $41.9 million for the three and nine months ended September 30, 2019, respectively. There were no prepetition restructuring charges for the three or nine months ended September 30, 2018.

Reorganization Items

The Company has incurred and is expected to continue to incur substantial costs associated with the reorganization. These costs, which are expensed as incurred, are expected to significantly affect the Company’s results of operations. Reorganization items represent costs directly associated with the Chapter 11 Cases since the Petition Date. Such costs include accruals related to the DIP Facility and postpetition fees and expenses of court-approved legal and financial advisors, which are subject to Bankruptcy Court orders and/or oversight.

The following table summarizes the components of reorganization items included on the condensed consolidated statements of operations (in thousands):

	Three and Nine Months Ended
	September 30, 2019
DIP lender fee on initial borrowing	$	8,814
DIP Facility costs		4,512
Legal and other professional advisory fees		11,571
Unamortized deferred financing fees, discounts and premiums		30,424
Reorganization items(1)	$	55,321

(1) Includes $9.5 million of cash paid for reorganization items. 

Interest Expense

The Debtors have discontinued recording interest on debt instruments classified as subject to compromise as of the Petition Date. The contractual interest on liabilities subject to compromise not reflected in the condensed consolidated statements of operations was approximately $21.1 million, representing interest expense from the Petition Date through September 30, 2019. However, it is currently proposed that under the terms of the Final DIP Order, we will be required to pay the approximately $18.1 million in interest that would have been due on August 15, 2019 under the indenture for the Senior Secured 7.25% Notes and are required to continue making the semi-annual interest payments as they come due under the indenture for the 7.25% Senior Secured Notes during the Chapter 11 Cases.

Magnitude of Potential Claims

On  September 24, 2019, the Debtors filed with the Bankruptcy Court schedules and statements setting forth, among other things, our assets and liabilities, subject to the assumptions filed in connection therewith (the “Schedules and Statements”). The Debtors may subsequently decide to amend or modify the Schedules and Statements.

On October 24, 2019, the Debtors filed a motion to set a bar date to assist with the claims reconciliation process, proposing a bar date of December 13, 2019 and a governmental bar date of February 7, 2020. Through the claims resolution process, differences in amounts scheduled by the Debtors and claims filed by creditors will be investigated and resolved, including through the filing of objections with the Bankruptcy Court where appropriate. In light of the potential number and amount of claims filed, the claims resolution process may take considerable time to complete, and we expect that it will continue after our emergence from bankruptcy. Accordingly, the ultimate number and amount of allowed claims is not presently known, nor can the ultimate recovery with respect to allowed claims presently be ascertained.

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Effect of Filing on Creditors and Stockholders

Under the priority scheme established by the Bankruptcy Code, unless creditors agree otherwise, prepetition liabilities and postpetition liabilities must be satisfied in full or consensual agreement reached between parties before the holders of our existing common stock or preferred stock are entitled to receive or retain any property under a plan of reorganization. The ultimate recovery to creditors and/or stockholders, if any, will not be determined until confirmation and implementation of a plan or plans of reorganization. There can be no assurance as to what values, if any, will be ascribed in the Chapter 11 Cases to each of these constituencies or what types or amounts of distributions, if any, they would receive. A plan of reorganization could result in holders of our liabilities and/or securities, including our common stock and preferred stock, receiving no distribution on account of their interests and cancellation of their holdings. As discussed above, if certain requirements of the Bankruptcy Code are met, a plan of reorganization can be confirmed notwithstanding its rejection by the holders of our common stock or preferred stock and notwithstanding the fact that such holders do not receive or retain any property on account of their equity interests under the plan. Because of such possibilities, the value of the Debtors’ securities is highly speculative.

Appointment of Creditors’ Committee

On August 26, 2019, the Bankruptcy Court appointed the official committee of unsecured creditors (the “Creditors’ Committee”). The Creditors’ Committee and its legal representatives have a right to be heard on all matters that come before the Bankruptcy Court with respect to the Debtors.

Debtor Financial Statements

Condensed consolidated financial statements of the Debtors are set forth below. These condensed consolidated financial statements exclude the financial statements of the non-Debtors. Transactions and balances of receivables and payables between Debtors are eliminated in consolidation. However, the Debtors’ condensed consolidated balance sheet includes receivables from and payables to related non-Debtors.

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Debtors(1)

Condensed Consolidated Balance Sheets (Unaudited)

(in thousands)

	September 30,		December 31,
	2019		2018
ASSETS
Current assets:
Cash and cash equivalents	$	173,959	$	194,723
Oil and natural gas receivables		42,778		55,083
Joint interest billings receivables		10,969		33,261
Fair value of derivative instruments		367		5,154
Other current assets		20,978		28,617
Total current assets		249,051		316,838
Oil and natural gas properties, on the basis of successful efforts accounting:
Proved oil and natural gas properties		2,947,641		2,890,471
Unproved oil and natural gas properties		205,121		236,931
Total oil and natural gas properties		3,152,762		3,127,402
Less: Accumulated depreciation, depletion, amortization and impairment		(1,651,441)		(1,526,988)
Total oil and natural gas properties, net		1,501,321		1,600,414
Other assets:
Right of use assets, net		280,139		—
Investments		4,921		9,384
Investments in subsidiaries		338,097		337,475
Other assets		31,631		45,524
Total assets	$	2,405,160	$	2,309,635
LIABILITIES AND STOCKHOLDERS' DEFICIT
Current liabilities:
Debtor-in-possession financing	$	50,000	$	—
Accounts payable		14,372		32,382
Accounts payable - related entities		7,745		8,707
Other payables		16,230		74,595
Accrued liabilities:
Capital expenditures		5,194		54,317
Other		46,909		87,656
Fair value of derivative instruments		700		307
Short term lease liabilities		109,494		—
Other current liabilities		31,962		75,581
Total current liabilities		282,606		333,545
Long term debt, net of premium, discount and debt issuance costs		—		2,213,223
Asset retirement obligations		34,456		32,432
Long term lease liabilities		173,990		—
Liabilities subject to compromise		2,398,106		—
Other liabilities		1		21,407
Total liabilities		2,889,159		2,600,607
Stockholders' deficit:
Preferred stock		31		53
Common stock		1,014		881
Additional paid-in capital		1,371,698		1,367,427
Accumulated deficit		(1,856,742)		(1,659,333)
Total stockholders' deficit		(483,999)		(290,972)
Total liabilities and stockholders' deficit	$	2,405,160	$	2,309,635

(1) Sanchez Energy Corporation, SN Palmetto, LLC, SN Marquis LLC, SN Cotulla Assets, LLC, SN Operating, LLC, SN TMS, LLC, SN Catarina, LLC, Rockin L Ranch Company, LLC, SN Payables, LLC, SN EF Maverick, LLC  and SN UR Holdings, LLC.

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Debtors(1)

Condensed Consolidated Statements of Operations (Unaudited)

(in thousands)

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2019		2018		2019		2018
REVENUES:
Oil sales	$	69,597	$	113,183	$	242,064	$	323,019
Natural gas liquid sales		15,506		49,332		65,170		119,961
Natural gas sales		17,941		27,674		69,713		83,640
Sales and marketing revenues		7,283		7,012		18,103		16,910
Total revenues		110,327		197,201		395,050		543,530
OPERATING COSTS AND EXPENSES:
Oil and natural gas production expenses		51,196		47,262		154,064		138,322
Exploration expenses		146		2,668		4,724		3,171
Sales and marketing expenses		6,672		7,239		16,591		16,498
Production and ad valorem taxes		6,424		10,683		23,332		29,162
Depreciation, depletion, amortization and accretion		39,211		47,799		128,976		128,812
Impairment of oil and natural gas properties		9,597		3,103		18,206		3,543
General and administrative expenses		21,424		19,386		60,854		66,522
Prepetition restructuring charges		18,231		—		41,855		—
Total operating costs and expenses		152,901		138,140		448,602		386,030
Operating income (loss)		(42,574)		59,061		(53,552)		157,500
Other income (expense):
Interest income		220		1,129		1,442		3,397
Other income (expense)		(12,814)		(8,217)		(13,527)		1,186
Gain on sale of oil and natural gas properties		—		—		—		1,528
Interest expense		(19,591)		(40,659)		(101,693)		(121,856)
Equity in net earnings of subsidiaries		14,025		8,273		621		12,470
Net (gains) losses on commodity derivatives		2,774		(13,989)		(10,748)		(88,429)
Total other expense		(15,386)		(53,463)		(123,905)		(191,704)
Reorganization items		55,321		—		55,321		—
Net income (loss) before taxes		(113,281)		5,598		(232,778)		(34,204)
Income tax benefit		(833)		—		(23)		—
Net income (loss)	$	(112,448)	$	5,598	$	(232,755)	$	(34,204)

(1) Sanchez Energy Corporation, SN Palmetto, LLC, SN Marquis LLC, SN Cotulla Assets, LLC, SN Operating, LLC, SN TMS, LLC, SN Catarina, LLC, Rockin L Ranch Company, LLC, SN Payables, LLC, SN EF Maverick, LLC  and SN UR Holdings, LLC.

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Debtors(1)

Condensed Consolidated Statements of Cash Flows (Unaudited)

(in thousands)

	Nine Months Ended
	September 30,
	2019			2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(232,755)	$	(34,204)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		128,976		128,812
Impairment of oil and natural gas properties		18,206		3,543
Gain on sale of oil and natural gas properties		—		(1,528)
Stock-based compensation expense		355		4,344
Net losses on commodity derivative contracts		10,748		88,429
Net cash settlements paid on commodity derivative contracts		(3,559)		(55,147)
(Gain) loss on other derivatives		(308)		7,141
Loss on investments		4,464		3,361
Loss (gain) on sale of inventory		143		(571)
Loss on other assets		858		—
Loss on prepaid asset impairment		11,755		—
Amortization of deferred gain on Western Catarina Midstream Divestiture		—		(17,790)
Equity in net earnings of subsidiaries		(621)		(12,470)
Amortization of debt issuance costs		5,386		9,859
Accretion of debt discount, net		1,019		1,112
Reorganization items		39,238		—
Changes in operating assets and liabilities:
Accounts receivable		35,686		75
Accounts receivable - related entities		(962)		9,259
Other payables		(40,452)		8,537
Accrued liabilities		54,915		12,980
Other current liabilities		(20,518)		(12,532)
Other assets and liabilities, net		5,260		(2,390)
Net cash provided by operating activities		17,834		140,820
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for the development of oil and natural gas properties		(91,375)		(379,321)
Proceeds from the sale of oil and natural gas properties		—		1,425
Payments for purchases of other assets		(736)		(9,573)
Proceeds from the sale of other assets		5,199		3,642
Net cash used in investing activities		(86,912)		(383,827)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings, including borrowings under DIP Facility		57,922		539,865
Repayment of borrowings		—		(95,000)
Financing costs, including borrowings under DIP Facility		(9,410)		(12,484)
Cash paid to tax authority for employee stock-based compensation awards		(198)		(705)
Preferred dividends paid		—		(11,961)
Net cash provided by (used in) financing activities		48,314		419,715
(Decrease) increase in cash and cash equivalents		(20,764)		176,708
Cash and cash equivalents, beginning of period		194,723		171,052
Cash and cash equivalents, end of period	$	173,959	$	347,760

(1) Sanchez Energy Corporation, SN Palmetto, LLC, SN Marquis LLC, SN Cotulla Assets, LLC, SN Operating, LLC, SN TMS, LLC, SN Catarina, LLC, Rockin L Ranch Company, LLC, SN Payables, LLC, SN EF Maverick, LLC  and SN UR Holdings, LLC.

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Ability to Continue as a Going Concern

We currently expect that the Company’s cash flows, cash on hand and any financing that we are able to obtain through the DIP Facility should provide sufficient liquidity for the Company during the pendency of the Chapter 11 Cases. However, the significant risks and uncertainties related to the Company’s liquidity and Chapter 11 Cases described above raise substantial doubt about the Company’s ability to continue as a going concern. The condensed consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The condensed consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. If the Company cannot continue as a going concern, adjustments to the carrying values and classification of its assets and liabilities and the reported amounts of income and expenses could be required and could be material.

Covenant Violations

The Debtors’ filing of the Bankruptcy Petitions described above constituted an event of default that accelerated the Company’s obligations under the Credit Agreement, its 7.75% Notes, its 6.125% Notes and its 7.25% Senior Secured Notes (each term as defined below). Additionally, other events of default, including cross-defaults, are present under these debt instruments. Under the Bankruptcy Code, the creditors under these debt agreements are stayed from taking any action against the Company as a result of an event of default. Neither SN UnSub nor its general partner are parties to the Chapter 11 Cases, and the Chapter 11 Cases did not result in an event of default under the SN UnSub Credit Agreement (as defined below). See “—Note 7. Debt” for additional details about the Company’s debt.

Additionally, the filing of the Bankruptcy Petitions described above constituted an event of default that generally allows counterparties to certain of the Company’s derivative contracts (excluding the counterparties to SN UnSub’s derivative contracts) to unilaterally terminate contracts to their scheduled settlement date(s) and pursue remedies, which are not subject to the automatic stay. In August 2019, as a result of the Chapter 11 Cases, one of our counterparties terminated its derivative contracts with the Company (excluding SN UnSub’s derivative contracts), resulting in a net payable of approximately $1.1 million due to the counterparty.

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.

Disaggregation of Revenue

We recognized revenue of $162.5 million and  $277.7 million for the three months ended September 30,  2019 and 2018, respectively, and revenue of $574.4 million and $788.3 million for the nine months ended September 30,  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.

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, MMBtu of natural gas, barrel of NGL 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.

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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, with costs to purchase and transport the commodity presented as Sales and Marketing Expenses, in each case within 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, MMBtu of natural gas, barrel of NGL 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 September 30,  2019 and December 31, 2018, our receivables from contracts with customers were $69.3 million and $87.2 million, respectively.

Note 5. Cash and Cash Equivalents

As of September 30, 2019 and December 31, 2018, cash and cash equivalents consisted of the following (in thousands):

	September 30,		December 31,
	2019		2018
Cash at banks	$	179,265	$	66,426
Money market funds		273		131,187
Total cash and cash equivalents	$	179,538	$	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.

Note6. Oil and Natural Gas Properties

Impairment of Oil and Natural Gas Properties  —The Company recorded a proved property impairment of $4.3 million during the nine months ended September 30, 2019. The Company did  not record proved property impairments during the three months ended September 30, 2019 or the three and nine months ended September 30, 2018. Changes in

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production rates, levels of reserves, future development costs, and other factors will impact the Company’s actual impairment analyses in future periods. 

Unproved Properties—The Company recorded impairment to our unproved oil and natural gas properties of $9.8 million and $18.6 million for the three and nine months ended September 30, 2019, respectively, and $3.1 million and $4.3 million for the three and nine months ended September 30, 2018, respectively, due to acreage expirations from changes in the development plan.

Note 7. Debt

As of September 30, 2019 and December 31, 2018, the Company’s outstanding debt consisted of the following (in thousands):

			September 30,		December 31,
	Interest Rate	Maturity Date	2019		2018
Short Term Debt:
Debtor-in-possession financing(1)	Variable	June 11, 2020	$	50,000	$	—
SR Credit Agreement(2)(3)	Variable	-	$	—	$	304
Total short term debt			$	50,000	$	304
Long Term Debt:
7.75% Notes	7.75%	June 15, 2021	$	600,000	$	600,000
SN UnSub Credit Agreement(2)	Variable	March 1, 2022		150,000		167,500
4.59% Non-Recourse Subsidiary Term Loan(2)	4.59%	August 31, 2022		3,527		3,803
SR Credit Agreement(2)	Variable	October 31, 2022		22,941		23,187
6.125% Notes	6.125%	January 15, 2023		1,150,000		1,150,000
Credit Agreement(4)	Variable	February 14, 2023(5)		7,922		—
7.25% Senior Secured Notes	7.25%	February 15, 2023(6)		500,000		500,000
				2,434,390		2,444,490
Unamortized discount on Additional 7.75% Notes(7)				—		(2,222)
Unamortized premium on Additional 6.125% Notes(7)				—		1,090
Unamortized discount on 7.25% Senior Secured Notes(7)				—		(4,241)
Unamortized debt issuance costs(7)				(9,512)		(43,709)
Total long term debt				2,424,878		2,395,408
Less liabilities subject to compromise(8)				(2,257,922)		—
Total long term debt not subject to compromise			$	166,956	$	2,395,408

(1) Incurred interest at a weighted-average rate of approximately 10.1% for the postpetition period ended September 30, 2019. 

(2) Represents debt instruments which are non-recourse to Sanchez Energy Corporation and its restricted subsidiaries.

(3) Incurred interest at a weighted-average rate of approximately 5.9% and 6.9% for the nine months ended September 30, 2019 and the year ended December 31, 2018, respectively. 

(4) 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% through the Petition Date. The letter of credit remains outstanding and is undrawn as of September 30, 2019 but is currently proposed to be cash collateralized subject to entry of the Final DIP Order.

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(5) The Credit Agreement would mature on the earlier of (i) February 14, 2023 or (ii) the 91st day prior to the scheduled maturity of any “material indebtedness,” which is defined to include, without limitation, any indebtedness arising in connection with the 7.75% Notes, 6.125% Notes or the 7.25% Senior Secured Notes. The 7.75% Notes would mature on June 15, 2021; therefore, the Credit Agreement would, as of September 30, 2019, mature on March 15, 2021.

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

(7) Approximately $30.4 million in net discounts, premiums and debt issuance costs were reclassified as reorganization items in connection with the filing of the Bankruptcy Petitions.

(8) The Company’s 7.75% Notes, 6.125% Notes, Credit Agreement, and 7.25% Senior Secured Notes were classified as liabilities subject to compromise at September 30, 2019. 

The components of interest expense are as follows (in thousands):

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2019		2018		2019		2018
Interest on SR Credit Agreement	$	(342)	$	(360)	$	(917)	$	(1,188)
Interest on Senior Notes		(17,704)		(38,296)		(94,299)		(110,158)
Interest and commitment fees on SN UnSub Credit Agreement		(1,952)		(2,131)		(6,383)		(6,634)
Interest on Non-Recourse Subsidiary Term Loan		(31)		(46)		(116)		(140)
Interest, commitment fees and letter of credit fees on Credit Agreement		(106)		(32)		(389)		(726)
Interest on DIP Facility		(600)		—		(600)		—
Amortization of debt issuance costs		(1,961)		(2,873)		(8,275)		(12,706)
Amortization of discounts and premium on Senior Notes		(188)		(416)		(1,019)		(1,112)
Total interest expense	$	(22,884)	$	(44,154)	$	(111,998)	$	(132,664)

On July 15, 2019, the Company elected to defer making an interest payment of approximately $35.2 million on the Company’s 6.125% Notes to continue ongoing discussions with certain of its bondholders and other stakeholders regarding a restructuring transaction. The indenture governing the 6.125% Notes provided for a 30-day grace period, which expired on August 14, 2019, to make the scheduled interest payment before such non-payment constituted an event of default under the indenture, which would have entitled the trustee under such indenture or the holders of at least 25% in aggregate principal amount of the outstanding 6.125% Notes to accelerate the maturity thereof. Such event of default would have triggered events of default under the Company’s indentures governing the 7.75% Notes, the 7.25% Senior Secured Notes and the Credit Agreement. The Debtors filed the Bankruptcy Petitions prior to expiration of the grace period. Further, the Debtors have discontinued recording interest on debt instruments classified as subject to compromise as of the Petition Date.

Credit Facilities

DIP Facility

“—Note 3. Chapter 11 Cases” for information on the Company’s DIP Facility.

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.

On July 10, 2019, the Company borrowed the remaining $7.9 million available under the Credit Agreement. Additionally, 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, as of September 30, 2019, remains

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outstanding and is undrawn but is currently proposed to be cash collateralized subject to entry of the Final DIP Order. Further, subject to entry of the Final DIP Order, a portion of the proceeds from the DIP Facility will be used to pay off all $7.9 million of borrowings outstanding under the Credit Agreement and cash collateralize the approximate $17.1 million letter of credit issued under our Credit Agreement. The automatic stay under the Bankruptcy Code does not apply to letters of credit issued under the Credit Agreement and third-party beneficiaries may draw on the letter of credit if permitted by its terms.

The filing of the Bankruptcy Petitions also constituted an event of default which automatically accelerated the Company’s obligations under the Credit Agreement. However, under the Bankruptcy Code, the lenders under the Credit Agreement are stayed from taking any action against the Company as a result of these defaults.

During the existence of an event of default and the Chapter 11 Cases, we have no borrowing capacity under the Credit Agreement, even if any available borrowing capacity remained under the Credit Agreement. In addition, as discussed above, subject to entry of the Final DIP Order, we anticipate paying off the borrowings outstanding under the Credit Agreement in full.

SN UnSub Credit Agreement

On March 1, 2017, 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 May 23, 2019, as part of the most recent semi-annual redetermination, the borrowing base under the SN UnSub Credit Agreement was decreased from $315 million to $240 million. As of September 30, 2019, there were approximately $150.0 million of borrowings and no letters of credit outstanding under the SN UnSub Credit Agreement. The next regularly scheduled borrowing base redetermination is expected in the fourth quarter 2019. Based upon current commodity prices and other factors, we believe that the borrowing base under the SN UnSub Credit Agreement will likely be decreased at the next redetermination and may be decreased at future redeterminations, and any or all such decreases may be material. Were the lenders under the SN UnSub Credit Agreement to reduce the borrowing base to an amount below the current outstanding borrowings of SN UnSub, and provided no waiver is granted by those lenders, SN UnSub would be required at its election to repay the deficiency within 30 days (in a single installment) to 180 days (in six equal monthly installments), pledge additional oil and natural gas assets as security for the amount of debt outstanding, or seek such other remedies available under the SN UnSub Credit Agreement. Inability to do so would have a material adverse effect on SN UnSub’s liquidity, financial condition and results of operations.

As of September 30, 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 September 30, 2019,  there was approximately $22.9 million outstanding under the SR Credit Agreement, and SRAI was in compliance with the financial covenants of the SR Credit Agreement.

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 would 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.

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The filing of the Bankruptcy Petitions constituted an event of default that accelerated the Company’s obligations under the 7.75% Notes. However, under the Bankruptcy Code, holders of the 7.75% Notes are stayed from taking any action against the Company as a result of the default.

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 would 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.

The filing of the Bankruptcy Petitions constituted an event of default that accelerated the Company’s obligations under the 6.125% Notes. However, under the Bankruptcy Code, holders of the 6.125% Notes are stayed from taking any action against the Company as a result of the default.

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.

The filing of the Bankruptcy Petitions constituted an event of default that accelerated the Company’s obligations under the 7.25% Senior Secured Notes. However, under the Bankruptcy Code, holders of the 7.25% Senior Secured Notes are stayed from taking any action against the Company as a result of the default.

Note 8. Derivative Instruments

Hedging activities, which, as of September 30, 2019 are regulated by, as applicable, the terms of the DIP Facility, the Credit Agreement, the SN UnSub Credit Agreement and SN UnSub’s organizational documents, are intended to 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. As of September 30, 2019, 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 DIP Facility or Credit Agreement are, in each case, collateralized by the assets securing the applicable facility, and, therefore, did not as of September 30, 2019 require the posting of cash collateral. As of September 30, 2019, any derivatives that are, as applicable, with (x) non-lenders (or non-lender affiliates) under the SN UnSub Credit Agreement or (y) counterparties that are not designated as secured under the DIP Facility and Credit Agreement are, in each case, unsecured and do not require the posting of cash or other collateral. As of September 30, 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. Following the filing of the Bankruptcy Petitions, our ability to enter into derivatives is limited.  

The following table presents open derivative positions for the periods indicated as of September 30, 2019:

	October 1 - December 31, 2019		2020		2021
Oil positions:
Fixed price swaps (NYMEX WTI):
Hedged volume (Bbls)		580,000		1,105,860		650,400
Average price ($/Bbl)	$	52.41	$	55.29	$	54.23
Natural gas positions:
Fixed price swaps (NYMEX Henry Hub):
Hedged volume (MMBtu)		3,362,000		6,934,150		4,212,000
Average price ($/MMBtu)	$	2.87	$	2.67	$	2.56

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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 nine months ended September 30, 2019 and the year ended December 31, 2018 (in thousands):

	Nine Months Ended		Year Ended
	September 30,		December 31,
	2019		2018
Fair value of commodity derivatives, beginning of period	$	21,194	$	(54,255)
Net losses on oil derivatives		(28,167)		(9,878)
Net gains (losses) on natural gas derivatives		6,266		(17,897)
Net settlements paid (received) on commodity derivative contracts:
Oil		13,479		100,120
Natural gas		(3,689)		3,104
Fair value of commodity derivatives, end of period	$	9,083	$	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 September 30, 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 a loss of approximately $1.1 million for the three months ended September 30, 2018. The Company did not record any gains or losses for the three months ended September 30, 2019 as the contracts had expired or terminated. For the nine months ended September 30, 2019 and 2018, the Company recorded a gain of approximately $0.3 million and a loss of $7.1 million, 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. For the nine months ended September 30, 2019, the Company recorded an immaterial net gain due to settlement gains, which were partially offset by mark-to-market losses.  The Company did not record any gains or losses for the three months ended September 30, 2019. For the three and nine months ended September 30, 2018, the Company recorded approximate net gains of $0.4 million and $1.9 million, respectively, primarily related to mark-to-market gains. Any gains or losses related to the earnout derivative are recorded as a component of other income (expense) in the condensed consolidated statement of operations.

The following table sets forth a reconciliation of the changes in fair value of the Company’s embedded and earnout derivatives for the nine months ended September 30, 2019 and the year ended December 31, 2018, respectively (in thousands):

	Nine Months Ended		Year Ended
	September 30,		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  a 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):

	September 30, 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	$	6,389	$	(126)	$	6,263
Long term asset		9,361		(15)		9,346
Total asset	$	15,750	$	(141)	$	15,609
Offsetting Derivative Liabilities:
Current liability	$	826	$	(126)	$	700
Long term liability		15		(15)		—
Total liability	$	841	$	(141)	$	700

	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

The filing of Bankruptcy Petitions described above constituted an event of default that generally allows counterparties to certain of the Company’s derivative contracts (excluding the counterparties to SN UnSub’s derivative contracts) to unilaterally terminate contracts to their scheduled settlement date(s) and pursue remedies, which are not subject to the automatic stay. In August 2019, as a result of the Chapter 11 Cases, one of our counterparties terminated its derivative contracts with the Company (excluding SN UnSub’s derivative contracts), resulting in a net payable of approximately $1.1 million due to the counterparty.

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 September 30,  2019,  we believe this ownership represents approximately 6% 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 a gain of $0.6 million and a loss of $1.4 million related to the investment in Lonestar for the three and nine months ended September 30, 2019, respectively, and the Company recorded a loss of $1.0 million and a gain of $5.7 million related to the investment in Lonestar for the three and nine months ended September 30, 2018, 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

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investment. As of September 30,  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 September 30, 2019.

A subsidiary of the Company owns 2,272,727 common units of SNMP. As of September 30, 2019, we believe this ownership represents approximately 11.3% 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 and nine months ended September 30, 2019, the Company recorded losses of $4.3 million and $3.1 million, respectively, related to the investment in SNMP. In addition, for the nine months ended September 30, 2019, the Company recorded dividend income of approximately $0.7 million from quarterly distributions on the SNMP common units. The Company did not record any dividend income from quarterly distributions on the SNMP common units for the three months ended September 30, 2019. For the three and nine months ended September 30, 2018, the Company recorded losses related to the investment in SNMP of approximately $10.7 million and $9.1 million, respectively. Further, for the three and nine months ended September 30, 2018, we recorded dividend income of approximately $1.0 million and $3.2 million, respectively. 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 September 30, 2019 and December 31, 2018 (in thousands):

	As of September 30, 2019
	Active Market
	for Identical		Observable		Unobservable		Total
	Assets		Inputs		Inputs		Carrying
	(Level 1)		(Level 2)		(Level 3)		Value
Cash equivalents:
Cash equivalents	$	273	$	—	$	—	$	273
Equity investments:
Investment in SNMP		841		—		—		841
Investment in Lonestar		4,080		—		—		4,080
Oil derivative instruments:
Swaps		—		5,919		—		5,919
Natural gas derivative instruments:
Swaps		—		3,164		—		3,164
Other:
Earnout derivative asset		—		—		5,826		5,826
Total	$	5,194	$	9,083	$	5,826	$	20,103

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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 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
Natural 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

September 30, 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. 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 September 30, 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 September 30, 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):

	Nine Months Ended		Year Ended
	September 30,		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, March,  June, July and September 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 nine months ended September 30, 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 recorded proved property impairments of $4.3 million and $6.6 million during the nine months ended September 30, 2019 and the year ended December 31, 2018,  respectively, related to oil and natural gas properties in the TMS. The carrying value of the impaired proved properties was reduced to a fair value of $11.0 million and $10.5 million for the nine months ended September 30, 2019 and year ended December 31, 2018,  respectively, estimated using inputs characteristic of a Level 3 fair value measurement.

Fair Value of Other Financial Instruments

The carrying amounts of our oil and natural gas receivables, accounts payable not subject to compromise and accrued liabilities approximate fair value due to their highly liquid nature. The registered 7.75% Notes and 6.125% Notes are traded in an active market, and as such, are classified as Level 1 financial instruments. As of September 30, 2019, the estimated fair values of the 7.75% Notes and 6.125% Notes were $37.8 million and $74.1 million, respectively, and were calculated using quoted market prices based on trades of such debt as of that date. The 7.25% Senior Secured Notes are traded in an active market under Rule 144A by institutional investors, and as such, are classified as Level 1 financial instruments. As of September 30, 2019, the estimated fair value of the 7.25% Senior Secured Notes was $369.3 million and was calculated using quoted market prices based on observed trades of such debt as of that date.

We believe that the carrying values of long term debt for the Credit Agreement, SN UnSub Credit Agreement and SR Credit Agreement approximate their fair values because the interest rates on the debt approximate market interest rates for debt with similar terms. These debts are classified as Level 2 inputs in the fair value hierarchy and represent the amounts at which the instruments could be valued in an exchange during a current transaction between willing parties.

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Note 11. Asset Retirement Obligations

The changes in the asset retirement obligation for the nine months ended September 30, 2019 and the year ended December 31, 2018 were as follows (in thousands):

	Nine Months Ended		Year Ended
	September 30,		December 31,
	2019		2018
Abandonment liability, beginning of period	$	46,175	$	36,098
Liabilities incurred during period		275		1,965
Divestitures		(147)		(158)
Revisions		—		5,077
Accretion expense		2,879		3,193
Abandonment liability, end of period	$	49,183	$	46,175

Note 12. Related Party Transactions

Sanchez Oil and Gas Corporation

Expenses allocated to the Company from SOG for G&A expenses and oil and natural gas production expenses for the three months ended September 30, 2019 and 2018 were $17.3 million and $15.3 million, respectively, and expenses allocated to the Company for G&A expenses and oil and natural gas production expenses for the nine months ended September 30, 2019 and 2018 were $52.6 million and $48.8 million, respectively.

As of September 30, 2019 and December 31, 2018, the Company had a net receivable from SOG and its affiliates of $10.2 million and $6.1 million, respectively, which is reflected as “Accounts receivable—related entities” in the condensed consolidated balance sheets. The net receivable as of September 30, 2019 and December 31, 2018 consists primarily of advances related to G&A expenses and other costs paid to SOG in the ordinary course.

Sanchez Midstream Partners

As of September 30, 2019 and December 31, 2018, the Company had a net payable to SNMP of approximately $3.8 million and $6.1 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 September 30, 2019 and December 31, 2018 (in thousands):

	September 30,		December 31,
	2019		2018
Capital expenditures	$	7,232	$	61,970
Other:
General and administrative expenses		20,635		19,460
Production taxes		2,483		5,157
Ad valorem taxes		6,655		445
Lease operating expenses		34,782		24,138
Interest payable		376		47,866
Other accrued liabilities		1,367		5,662
Total accrued liabilities	$	73,530	$	164,698

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The following information summarizes other payables as of September 30, 2019 and December 31, 2018 (in thousands):

	September 30,		December 31,
	2019		2018
Revenue payable	$	14,963	$	71,296
Production tax payable		448		3,443
Other		1,328		(111)
Total other payables	$	16,739	$	74,628

The following information summarizes other current liabilities as of September 30, 2019 and December 31, 2018 (in thousands):

	September 30,		December 31,
	2019		2018
Operated prepayment liability	$	31,921	$	51,844
Deferred gain on Western Catarina Midstream Divestiture - short term		—		23,720
Phantom compensation payable - short term		40		17
Total other current liabilities	$	31,961	$	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 September 30, 2019, based on the initial conversion price, approximately 1,440,343 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 Board. Subject to certain conditions, the Company may, at its option, pay dividends in cash and, subject to certain additional 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 September 30, 2019 have been accrued. Pursuant to the terms of the DIP Facility, the Company may not pay any dividends on, make any distribution or payment on account of, redeem or acquire any shares of Series A Preferred Stock.

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 September 30, 2019, based on the initial conversion price, approximately 5,763,071 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. Subject to certain conditions, the Company may, at its option, pay dividends in cash and, subject to certain additional 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 September 30, 2019 have been accrued. Pursuant to the terms of the DIP Facility, the Company may not pay any dividends on, make any distribution or payment on account of, redeem or acquire any shares of Series B Preferred Stock.

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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. As of June 14, 2019, 155,929 shares of Series A Preferred Stock converted into 362,535 shares of our common stock, at the election of the holders thereof. On July 29, 2019, 5,000 shares of Series A Preferred Stock converted into 11,625 shares of our common stock, at the election of the holder thereof. On September 30, 2019, 45,000 shares of Series B Preferred Stock converted into 105,165 shares of our common stock, at the election of the holder thereof.

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 quarterly dividend accruals on its Series A Preferred Stock and Series B Preferred Stock by approximately $1.6 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 Maverick, along with Gavilan Resources, LLC (“Gavilan”), an entity controlled by The Blackstone Group Inc., 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,” with such acquisition, the “Comanche Acquisition”).

At the closing of the Comanche Acquisition, certain funds managed or advised by GSO Capital Partners L.P. (“GSO”) 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 September 30, 2019 and December 31, 2018, respectively, (in thousands):

	Nine Months Ended		Year Ended
	September 30,		December 31,
	2019		2018
Mezzanine equity, beginning balance	$	452,828	$	427,512
Accretion of discount		22,029		25,316
Dividends accrued		37,500		50,000
Dividends prepaid (1)		—		(2,592)
Dividends/distributions paid (1)		(37,500)		(47,408)
Mezzanine equity, ending balance	$	474,857	$	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. 

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Earnings (Loss) Per Share—The following table shows the computation of basic and diluted net loss per share for the three and nine months ended September 30, 2019 and 2018 (in thousands, except per share amounts):

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2019		2018		2019		2018
Net income (loss)	$	(112,448)	$	5,598	$	(232,755)	$	(34,204)
Less:
Preferred stock dividends		(2,312)		(3,987)		(7,153)		(11,961)
Preferred unit dividends and distributions		(12,500)		(12,500)		(37,500)		(34,908)
Preferred unit amortization		(7,638)		(6,458)		(22,029)		(18,577)
Net loss attributable to common stockholders	$	(134,898)	$	(17,347)	$	(299,437)	$	(99,650)
Weighted average number of unrestricted outstanding common shares used to calculate basic and dilutive net loss per share(1)(2)		97,395		82,073		95,272		81,597
Net loss per common share - basic and diluted	$	(1.39)	$	(0.21)	$	(3.14)	$	(1.22)

(1) The three and nine months ended September 30, 2018 exclude 1,840,007 and 2,591,553  shares, respectively, of weighted average restricted stock and 12,520,179 shares of common stock resulting from an assumed conversion of the Company's Series A Preferred Stock and Series B Preferred Stock from the calculation of the denominator for diluted loss per common share as these shares were anti-dilutive.

(2) The three and nine months ended September 30, 2019 exclude 433,369 and 942,551 shares, respectively, of weighted average restricted stock and 7,306,402 and 8,757,574 shares, respectively, of common stock resulting from an assumed conversion of the Company's Series A Preferred Stock and Series B Preferred Stock from the calculation of the denominator for diluted loss 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 stock 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 and nine months ended September 30, 2019, the Company did not issue any shares of restricted common stock pursuant to the LTIP.

During the three months ended September 30, 2019, the Company did not issue any shares of phantom stock pursuant to the LTIP. During the nine months ended September 30, 2019, the Company issued an immaterial number of shares of phantom stock pursuant to the LTIP to certain employees of SOG, 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.

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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				Nine Months Ended
	September 30,				September 30,
	2019		2018		2019		2018
Restricted stock awards, directors	$	—	$	305	$	42	$	932
Restricted stock awards, non-employees		45		(862)		270		1,957
Performance awards		51		(842)		83		(12)
Phantom stock awards		(101)		(2,652)		(40)		1,467
Total stock-based compensation expense	$	(5)	$	(4,051)	$	355	$	4,344

Based on the $0.03 per share closing price of the Company’s common stock on September 30, 2019, there was approximately $0.3 million of unrecognized compensation cost related to the non‑vested restricted shares outstanding. The cost is expected to be recognized over an average period of approximately 1.7 years.

Based on the $0.03 per share closing price of the Company’s common stock on September 30, 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 1.5 years.

Based on the $0.03 per share closing price of the Company’s common stock on September 30, 2019, there was less than $0.1 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 1.7 years.

Based on the estimated per share price of the common stock underlying the Performance Awards on September 30, 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 2.3 years.

Based on the estimated per share price of the common stock underlying the PBPS Awards on September 30, 2019, there was less than $0.1 million of unrecognized compensation cost related to the PBPS Awards. The cost is estimated to be recognized over a weighted average period of approximately 1.1 years.

A summary of the status of the non-vested restricted shares for the three and nine months ended September 30, 2019 and 2018 is presented below (in thousands):

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2019	2018	2019	2018
Non-vested common stock, beginning of period	2,714	5,767	5,024	4,897
Granted	—	146	—	3,303
Vested	(51)	(59)	(2,164)	(2,218)
Forfeited	(24)	(414)	(221)	(542)
Non-vested common stock, end of period	2,639	5,440	2,639	5,440

As of September 30, 2019, approximately 8.4 million shares remained available for future issuance to participants under the LTIP.

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A summary of the status of the non‑vested phantom stock and PAPS for the three and nine months ended September 30, 2019 and 2018 is presented below (in thousands):

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2019	2018	2019	2018
Non-vested phantom stock and PAPS, beginning of period	2,857	5,888	5,125	3,589
Granted	—	253	7	3,905
Vested	(60)	(46)	(1,874)	(1,197)
Forfeited	(58)	(465)	(519)	(667)
Non-vested phantom stock and PAPS, end of period	2,739	5,630	2,739	5,630

Note 16. Income Taxes

The Company used a year-to-date effective tax rate method for recording income taxes for the nine month periods ended September 30, 2019 and 2018. This method is based on our determination at September 30, 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 September 30, 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 nine months ended September 30, 2019 and 2018 was approximately 0% and  0%, respectively. The difference between the statutory federal income taxes calculated using a U.S. Federal statutory corporate income tax rate of 21% and the Company’s effective tax rates 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 September 30, 2019. The Company will continue to assess the valuation allowance against deferred tax assets considering all available information obtained in future reporting periods.

At September 30, 2019, the Company had no material uncertain tax positions.

Note 17. Commitments and Contingencies

Stockholder 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. On August 16, 2019 a suggestion of bankruptcy was filed in the Derivative Action by the Company, and there has been no activity in the case since that time. Given the status and the preliminary state of the Derivative Action, 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.

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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. During the commitment period ending June 30, 2019, the Company drilled 13 wells that may be counted toward the next annual drilling commitment period, which began on July 1, 2019. Furthermore, our 2019 capital budget and current plans include the additional activity needed to fulfill the commitment to drill at least one well in any 120-day period and the activity needed, when combined with expected activity in the first half of 2020, to comply with the 50-well annual drilling commitment for the period July 1, 2019 to June 30, 2020.

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 for a default fee of $0.2 million for each 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.

Palmetto Drilling Commitment

Marathon Oil EF LLC (“Marathon”) is the operator and other lessee of our Palmetto acreage position. In the Palmetto 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 the lessees thereof to (i) complete six gross (three net) wells and drill and complete an additional four gross (two net) wells during the 2019 calendar year and (ii) drill and complete up to 10 gross (five net) wells, depending on commodity pricing in each calendar year beginning in 2020. If the lessees under such leases fail to complete and equip the required number of wells in a given year (after applying any qualifying additional wells from previous years and any required additional wells drilled and completed prior to the applicable extension cutoff date in the following year), the leases terminate as to all lands and depths not included within a retained tract at the end of the applicable calendar year, as further described in, and pursuant to the terms and conditions of, each such lease. For the 2019 commitment, Marathon has completed six gross wells and drilled four gross wells that are currently in the process of completion, thereby satisfying the 2019 development commitment and complying with applicable lease requirements necessary to maintain our Palmetto acreage position if timely completed.

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 to our midstream counterparties. As of September 30, 2019, the Company had approximately $406.3 million in future commitments related to oil and natural gas gathering and transportation agreements ($140.6 million for 2019 through 2021, $128.8 million from 2022 through 2024, and $136.9 million under commitments expiring after December 31, 2024, in the aggregate) and approximately $40.5 million in future commitments related to natural gas processing agreements ($39.8 million for 2019 through 2021,

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and $0.7 million from 2022 through 2024, in the aggregate) that are not recorded in the accompanying condensed consolidated balance sheets.

For the three and nine months ended September 30, 2019, the Company incurred expenses related to deficiency fees of approximately $3.6 million and $7.5 million, respectively, and for the three and nine months ended September 30, 2018, the Company incurred expenses related to deficiency fees of approximately $1.6 million and $3.8 million, respectively. These expenses are reported on the condensed consolidated statements of operations in the “Oil and natural gas production expenses” line item. We expect to incur additional expenses related to our volume commitments in connection with our reduced capital activity.

Loss Contingencies

To the extent we are able to assess the likelihood of a negative outcome for a contingency, whether it be the loss or impairment of an asset or the incurrence of a liability, our assessments of such likelihood range from remote to probable. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue an undiscounted liability equal to the estimated amount. If a range of probable loss amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then we accrue an undiscounted liability equal to the minimum amount in the range. In addition, we estimate legal fees that we expect to incur associated with loss contingencies and accrue those costs when they are material and probable of being incurred.

We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when the likelihood of loss is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material to our consolidated financial statements, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss.

For the three and nine months ended September 30, 2019, we recorded a loss on impairment of a prepaid asset of $11.8 million.

Other Commitments and Contingencies

The filing of the Bankruptcy Petitions automatically stayed certain actions against the Company, including actions to collect prepetition liabilities or to exercise control over the property of the Company’s bankruptcy estates. The Company sought and obtained authorization from the Bankruptcy Court to pay certain prepetition claims. The Company is paying all of its postpetition obligations in the ordinary course of business, notwithstanding the filing of the Bankruptcy Petitions. In addition, the filing of the Bankruptcy Petitions may allow the Company to assume, assign or reject certain commitments as executory contracts. See “—Note 3. Chapter 11 Cases” for additional information.

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, SN Services, LLC, SN Terminal, LLC, SN Midstream, LLC, SN Comanche Manager, LLC, SN UnSub GP, SN UnSub Holdings, 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 September 30, 2019 such guarantor subsidiaries were 100% 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

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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.

The guarantor subsidiaries, along with non-guarantor subsidiary SN UR Holdings, LLC in addition to Sanchez Energy Corporation, constitute Debtors in the Chapter 11 Cases. Although the filing of the Bankruptcy Petitions triggered defaults on the Debtors’ debt obligations, creditors are stayed from taking any actions against the Debtors as a result of such defaults, subject to certain limited exceptions permitted by the Bankruptcy Code. Substantially all of the Debtors’ prepetition liabilities are subject to settlement and compromise under the Bankruptcy Code. See “—Note 3. Chapter 11 Cases” and “—Note 7. Debt” for additional information.

A summary of the condensed consolidated guarantor balance sheets as of September 30, 2019 and December 31, 2018 is presented below (in thousands):

	September 30, 2019
Assets	Parent Company		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Total current assets	$	243,889	$	122,817	$	106,561	$	(172,357)	$	300,910
Total oil and natural gas properties, net		60		1,498,844		717,321		—		2,216,225
Investment in subsidiaries		1,609,093		—		(7,278)		(1,601,815)		—
Other assets		52,146		259,623		33,906		—		345,675
Total Assets	$	1,905,188	$	1,881,284	$	850,510	$	(1,774,172)	$	2,862,810
Liabilities and Stockholders' Equity
Current liabilities	$	77,254	$	202,889	$	189,010	$	(172,357)	$	296,796
Long term liabilities		2,370,695		235,861		181,680		—		2,788,236
Mezzanine equity		—		—		474,857		—		474,857
Total stockholders' equity (deficit)		(542,761)		1,442,534		4,963		(1,601,815)		(697,079)
Total Liabilities and Stockholders' Equity (Deficit)	$	1,905,188	$	1,881,284	$	850,510	$	(1,774,172)	$	2,862,810

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	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

A summary of the condensed consolidated guarantor statements of operations for the three and nine months ended September 30, 2019 and 2018 is presented below (in thousands):

	Three Months Ended September 30, 2019
	Parent Company		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Total revenues	$	—	$	110,327	$	52,219	$	—	$	162,546
Total operating costs and expenses		(35,928)		(116,966)		(45,410)		90		(198,214)
Other income (expense)		(27,494)		1,533		3,759		(90)		(22,292)
Reorganization items		(55,321)		—		—		—		(55,321)
Income (loss) before income taxes		(118,743)		(5,106)		10,568		—		(113,281)
Income tax benefit		(833)		—		—		—		(833)
Equity in income (loss) of subsidiaries		5,462		—		—		(5,462)		—
Net income (loss)	$	(112,448)	$	(5,106)	$	10,568	$	(5,462)	$	(112,448)

	Three Months Ended September 30, 2018
	Parent Company		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Total revenues	$	—	$	197,203	$	80,507	$	—	$	277,710
Total operating costs and expenses		(16,717)		(126,573)		(49,969)		134		(193,125)
Other income (expense)		(52,165)		794		(27,482)		(134)		(78,987)
Income (loss) before income taxes		(68,882)		71,424		3,056		—		5,598
Equity in income (loss) of subsidiaries		74,480		—		—		(74,480)		—
Net income (loss)	$	5,598	$	71,424	$	3,056	$	(74,480)	$	5,598

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	Nine Months Ended September 30, 2019
	Parent Company		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Total revenues	$	—	$	395,050	$	179,300	$	—	$	574,350
Total operating costs and expenses		(90,587)		(358,005)		(158,412)		360		(606,644)
Other income (expense)		(123,907)		2,188		(23,084)		(360)		(145,163)
Reorganization items		(55,321)		—		—		—		(55,321)
Income (loss) before income taxes		(269,815)		39,233		(2,196)		—		(232,778)
Income tax benefit		(23)		—		—		—		(23)
Equity in income (loss) of subsidiaries		37,037		—		—		(37,037)		—
Net income (loss)	$	(232,755)	$	39,233	$	(2,196)	$	(37,037)	$	(232,755)

	Nine Months Ended September 30, 2018
	Parent Company		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Total revenues	$	—	$	543,529	$	244,722	$	—	$	788,251
Total operating costs and expenses		(56,967)		(334,408)		(163,833)		406		(554,802)
Other income (expense)		(200,124)		(4,469)		(62,654)		(406)		(267,653)
Income (loss) before income taxes		(257,091)		204,652		18,235		—		(34,204)
Equity in income (loss) of subsidiaries		222,887		—		—		(222,887)		—
Net income (loss)	$	(34,204)	$	204,652	$	18,235	$	(222,887)	$	(34,204)

A summary of the condensed consolidated guarantor statements of cash flows for the nine months ended September 30, 2019 and 2018 is presented below (in thousands):

	Nine Months Ended September 30, 2019
	Parent Company		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Net cash provided by (used in) operating activities	$	(166,502)	$	233,600	$	32,652	$	—	$	99,750
Net cash provided by (used in) investing activities		109,510		(81,169)		(34,665)		(103,893)		(110,217)
Net cash provided by (used in) financing activities		48,315		(159,599)		(217)		103,893		(7,608)
Net increase (decrease) in cash and cash equivalents		(8,677)		(7,168)		(2,230)		—		(18,075)
Cash and cash equivalents, beginning of period		68,762		58,429		70,422		—		197,613
Cash and cash equivalents, end of period	$	60,085	$	51,261	$	68,192	$	—	$	179,538

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	Nine Months Ended September 30, 2018
	Parent Company		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Net cash provided by (used in) operating activities	$	(175,586)	$	326,068	$	99,044	$	—	$	249,526
Net cash provided by (used in) investing activities		(136,290)		(396,492)		(58,365)		137,325		(453,822)
Net cash provided by (used in) financing activities		419,714		128,026		(21,881)		(137,325)		388,534
Net increase (decrease) in cash and cash equivalents		107,838		57,602		18,798		—		184,238
Cash and cash equivalents, beginning of period		86,937		29,046		68,451		—		184,434
Cash and cash equivalents, end of period	$	194,775	$	86,648	$	87,249	$	—	$	368,672

Note 19. Variable Interest Entities (“VIE”)

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 September 30, 2019 and December 31, 2018, was in each case 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 September 30, 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 September 30, 2019 and December 31, 2018, was approximately $0.8 million and $3.9 million, respectively.

Below is a comparison of the carrying amounts of the assets and liabilities of the VIE and the Company’s maximum exposure to loss as of September 30, 2019 and December 31, 2018 (in thousands):

	September 30,		December 31,
	2019		2018
Beginning balance	$	11,189	$	32,507
Gain (loss) from change in fair value of investment in SNMP		(3,068)		(21,318)
Maximum exposure to loss	$	8,121	$	11,189

Note 20. 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

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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-cancellable lease terms of approximately four 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 three to 10 years. We have concluded that these agreements represent operating leases with a lease term that equals the primary non-cancellable contract term. Generally upon completion of the primary term, both parties have the right 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 operating leases with lease terms of six to 18 months. For those arrangements with terms of less than one year, we have determined those arrangements to be short term operating leases. 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 is 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. Generally upon completion of the primary term, both parties have the right 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. Generally upon completion of the primary term, both parties have the right to terminate the lease.

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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 for purposes of making these calculations.

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 and nine months ended September 30, 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		Nine Months Ended
	September 30, 2019		September 30, 2019
Operating lease expense	$	25,069	$	74,997
Short term and variable lease expense		4,688		20,657
Total lease expense	$	29,757	$	95,654
Operating lease cost(1)	$	3,118	$	6,175
Short term lease cost(1)		191		1,187
Variable lease cost(1)		—		65
Total lease cost	$	3,309	$	7,427

(1) Represents capital expenditures related to the use of drilling rigs for the three and nine months ended September 30, 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):

	Nine Months Ended
	September 30, 2019
Operating cash flows from operating leases	$	95,654
Investing cash flows from operating leases		7,427
ROU assets obtained in exchange for operating lease obligations		361,648
Amortization of ROU assets		(81,509)
Weighted average remaining lease term (years)		3.1
Weighted average discount rate		10%

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As of September 30,  2019, minimum future payments, including imputed interest, for our long term operating leases under ASC 842 are as follows (in thousands):

October 1, 2019 through December 31, 2019	$	34,228
2020		119,293
2021		80,513
2022		60,269
2023		26,847
Thereafter		9,797
Total lease payments		330,947
Less: Imputed interest		47,463
Total lease liabilities	$	283,484

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 21. Subsequent Events

On October 22, 2019, the Debtors filed a motion for entry of an order authorizing rejection of an office sublease. The Bankruptcy Court has not yet ruled on the motion.

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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

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 have other producing properties and undeveloped acreage, including in the Tuscaloosa Marine Shale (“TMS”) in Mississippi and Louisiana, as well as other locations in Louisiana and Texas, which may offer potential future development opportunities. As of September 30, 2019, we held approximately 435,000 gross (233,000 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 or divestiture of such properties will generally depend on the circumstances and market conditions at the time we consider such opportunities. As discussed below, we are currently operating our business as debtors-in-possession in accordance with the applicable provisions of the Bankruptcy Code (as defined below).

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.

As previously disclosed, the Company substantially reduced its capital expenditures from approximately $593 million in 2018 to a budgeted amount of $100 to $150 million for 2019 in order to preserve capital in the current low and uncertain commodity price environment. As discussed in “Part I, Item 1. Notes to the Condensed Consolidated Financial Statements—Note 17. Commitments and Contingencies,” the Company is party to certain agreements that require it to meet annual drilling and development commitments to maintain undeveloped leasehold positions. To reduce its capital expenditures by this magnitude in 2019, the Company exercised privileges under certain of such agreements (primarily by utilizing well “banks” achieved through drilling and developing wells in excess of the quantity required to maintain the related acreage during prior annual periods) and negotiated deferral arrangements. If the Company is unable to negotiate additional extensions, deferrals, waivers or other similar arrangements to delay or otherwise reduce the activity necessary to maintain such undeveloped leasehold positions, it may be unable to continue to hold capital expenditures at comparable low levels in future years. As a result, the Company may be required to seek additional funding sources in order to pursue development plans which would maintain certain of its undeveloped acreage.

In addition, commodity prices remain depressed, and the Company’s oil, natural gas and NGL production has declined in connection with reduced development activity.  Lower commodity prices and declining production have adversely impacted the Company’s revenues and cash flow. This has led to a reduction in forecasted liquidity, which has affected the Company’s ability to service the significant obligations associated with its high level of indebtedness.

To improve its liquidity and position the Company for future success, Sanchez Energy undertook a review of various strategic alternatives with its advisors and Board of Directors (the “Board”) beginning in 2018. In anticipation of potential liquidity constraints, the Company commenced discussions with its bondholders, other stakeholders and potential third-party investors on a restructuring transaction to reduce the Company’s debt and strengthen its overall financial flexibility. On July 15, 2019, the Company elected to defer making an interest payment of approximately $35.2 million on the Company’s 6.125% Notes (as defined below) for a 30-day grace period, which expired on August 14, 2019, in order to preserve liquidity and continue discussions with stakeholders. The Debtors filed their Bankruptcy Petitions (as defined below) on August 11, 2019, prior to the expiration of the grace period. Although the Company has not yet reached an agreement with any of its stakeholders on the terms of a comprehensive restructuring transaction, the Company obtained additional financing pursuant to the DIP Facility (as defined below) on an interim basis, as discussed below.

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Voluntary Reorganization Under Chapter 11

On August 11, 2019 (the “Petition Date”), Sanchez Energy Corporation, SN Palmetto, LLC, SN Marquis LLC, SN Cotulla Assets, LLC, SN Operating, LLC, SN TMS, LLC, SN Catarina, LLC, Rockin L Ranch Company, LLC, SN Payables, LLC, SN EF Maverick, LLC (“SN Maverick”) and SN UR Holdings, LLC (“SN UR Holdings”) (collectively, the “Debtors”) filed voluntary petitions (the “Bankruptcy Petitions”) for reorganization under Chapter 11 of the U.S. Bankruptcy Code (the “Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). The Debtors filed a motion with the Bankruptcy Court seeking to jointly administer all of the Debtors’ chapter 11 cases (the “Chapter 11 Cases”) under the caption In re Sanchez Energy Corporation, Case No. 19-34508. The Debtors also filed various motions with the Bankruptcy Court, which were approved, seeking authorization to continue to operate their businesses as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. Additionally, the Bankruptcy Court has granted certain other relief requested by the Debtors, including interim relief allowing the Company to use its cash to fund the Chapter 11 Cases and to borrow an initial $50 million pursuant to the DIP Facility (as defined below), and giving the Company the authority to, among other things, continue to pay certain vendors and other third parties. During the pendency of the Chapter 11 Cases, all transactions outside the ordinary course of the Company’s business require prior approval of the Bankruptcy Court. The Company expects ordinary course operations to continue substantially uninterrupted during the Chapter 11 Cases. SN UnSub, its general partner, and certain other unrestricted subsidiaries of the Company are not included in the Chapter 11 cases and are classified as “non-Debtors.”

Subject to certain exceptions, under the Bankruptcy Code, the filing of the Bankruptcy Petitions automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or filing of other actions against the Debtors or their property to recover, collect or secure a claim arising prior to the date of the Bankruptcy Petitions. Accordingly, although the filing of the Bankruptcy Petitions triggered defaults on the Debtors’ debt obligations, creditors are stayed from taking any actions against the Debtors as a result of such defaults, subject to certain limited exceptions permitted by the Bankruptcy Code. Substantially all of the Debtors’ prepetition liabilities are subject to settlement and compromise under the Bankruptcy Code.

Under the Bankruptcy Code, unless creditors agree otherwise, prepetition liabilities and postpetition liabilities must be satisfied in full before the holders of the Company’s existing stockholders are entitled to receive or retain any property under a plan of reorganization. The ultimate recovery to creditors and/or stockholders, if any, will not be determined until confirmation and implementation of a plan or plans of reorganization. There can be no assurance as to what values, if any, will be ascribed in the Chapter 11 Cases to each of these constituencies or what types or amounts of settlements, if any, they will receive. A plan of reorganization could result in holders of the Debtors’ liabilities and/or stockholders receiving no settlement on account of their interests and cancellation of their holdings.

For the duration of the Company’s Chapter 11 Cases, the Company’s operations and ability to develop and execute its business plan are subject to the risks and uncertainties associated with the Chapter 11 Cases as described in Part II, Item 1A in our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2019. As a result of these risks and uncertainties, the number, amount or composition, as applicable, of the Company’s stock and stockholders, assets, liabilities, officers and/or directors could be significantly different following the outcome of the Chapter 11 Cases, and the description of the Company’s operations, properties and capital plans included in this quarterly report may not accurately reflect its operations, properties and capital plans following the Chapter 11 Cases.

Executory Contracts

Subject to certain exceptions, under the Bankruptcy Code, the Debtors may assume, assign or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and certain other conditions. Generally, the rejection of an executory contract or unexpired lease is treated as a prepetition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Debtors of performing their future obligations under such executory contract or unexpired lease but entitles the contract counterparty or lessor to a prepetition general unsecured claim for damages caused by such deemed breach. Counterparties to such rejected contracts or leases may assert unsecured claims in the Bankruptcy Court against the applicable Debtors’ estate for such damages. Generally, the assumption of an executory contract or unexpired lease requires the Debtors to cure existing monetary defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. Accordingly, any description of an executory contract or unexpired lease with the Debtor in this quarterly report, including where

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applicable a quantification of a Debtor’s obligations under any such executory contract or unexpired lease with the Debtor, is qualified by any overriding rejection rights such Debtor has under the Bankruptcy Code. Further, nothing herein is or shall be deemed an admission with respect to any claim amounts or calculations arising from the rejection of any executory contract or unexpired lease and the Debtors expressly preserve all of their rights with respect thereto. With limited exceptions, the Debtors have not yet made formal determinations with respect to the assumption or rejection of executory contracts or unexpired leases.

Process for Plan of Reorganization

Following the Petition Date, the Company has continued to engage with stakeholders in pursuit of a comprehensive restructuring transaction.  The Company believes the Chapter 11 Cases provide the most expeditious manner in which to effect a capital structure solution. In order to successfully exit the Chapter 11 Cases, we will need to obtain confirmation by the Bankruptcy Court of a plan (or plans) of reorganization that satisfies the requirements of the Bankruptcy Code. A plan of reorganization would, among other things, resolve the Debtors’ prepetition obligations, set forth the revised capital structure of the newly reorganized entity and provide for corporate governance subsequent to exit from the Chapter 11 Cases. However, there can be no assurance that the Company will be able to reorganize its capital structure on terms acceptable to the Company, the other Debtors, their creditors or other stakeholders, or at all.

The Debtors have the exclusive right for 120 days after the Petition Date to file a plan of reorganization (the “Exclusive Filing Period”), and if the Debtors’ plan of reorganization is filed within the Exclusive Filing Period, the Debtors also have the exclusive right for 180 days after the Petition Date to solicit acceptances and rejections regarding such plan of reorganization, in each case, subject to extension for cause by the Bankruptcy Court. If the Exclusive Filing Period lapses, any party in interest may file a plan of reorganization for any of the Debtors.

In addition to being voted on by holders of impaired claims and equity interests, a plan of reorganization must satisfy certain requirements of the Bankruptcy Code and must be confirmed by the Bankruptcy Court in order to become effective. A plan of reorganization would be accepted by holders of claims against and equity interests in the Company if (i) more than one-half in number and at least two-thirds in dollar amount of allowed claims actually voting in each class of claims impaired by the plan have voted to accept the plan and (ii) at least two-thirds in amount of allowed equity interests actually voting in each class of equity interests impaired by the plan has voted to accept the plan. A class of claims or equity interests that does not receive or retain any property under the plan on account of such claims or interests is deemed to have voted to reject the plan.

Under certain circumstances set forth in Section 1129(b) of the Bankruptcy Code, the Bankruptcy Court may confirm a plan even if such plan has not been accepted by all impaired classes of claims and equity interests. The precise requirements and evidentiary showing for confirming a plan notwithstanding its rejection by one or more impaired classes of claims or equity interests depends upon a number of factors, including the status and seniority of the claims or equity interests in the rejecting class (i.e., secured or unsecured claims, subordinated or senior claims, preferred or common stock). Generally, with respect to common stock or preferred stock interests, a plan may be “crammed down” even if the stockholders receive no recovery if the proponent of the plan demonstrates that (1) no class junior to the common stock or class or series of preferred stock, as applicable, is receiving or retaining property under the plan and (2) no class of claims or interests senior to the common stock or class or series of preferred stock, as applicable is being paid more than in full.

The timeline for the Debtors to file a plan of reorganization will depend on the timing and outcome of numerous other ongoing matters in the Chapter 11 Cases. There can be no assurance at this time that the Debtors will be able to successfully develop, confirm and consummate a plan of reorganization or other alternative restructuring transactions, that satisfies the conditions of the Bankruptcy Code and is confirmed by the Bankruptcy Court, or that any such plan will be implemented successfully.

Magnitude of Potential Claims

On September  24, 2019, the Debtors filed with the Bankruptcy Court schedules and statements setting forth, among other things, our assets and liabilities, subject to the assumptions filed in connection therewith (the “Schedules and Statements”). The Debtors may subsequently decide to amend or modify the Schedules and Statements.

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On October 24, 2019, the Debtors filed a motion to set a bar date to assist with the claims reconciliation process, proposing a bar date of December 13, 2019 and a governmental bar date of February 7, 2020. Through the claims resolution process, differences in amounts scheduled by the Debtors and claims filed by creditors will be investigated and resolved, including through the filing of objections with the Bankruptcy Court where appropriate. In light of the potential number and amount of claims filed, the claims resolution process may take considerable time to complete, and we expect that it will continue after our emergence from bankruptcy. Accordingly, the ultimate number and amount of allowed claims is not presently known, nor can the ultimate recovery with respect to allowed claims presently be ascertained.

Effect of Filing on Creditors and Stockholders

Under the priority scheme established by the Bankruptcy Code, unless creditors agree otherwise, prepetition liabilities and postpetition liabilities must be satisfied in full or consensual agreement reached between parties before the holders of our existing common stock or preferred stock are entitled to receive or retain any property under a plan of reorganization. The ultimate recovery to creditors and/or stockholders, if any, will not be determined until confirmation and implementation of a plan or plans of reorganization. There can be no assurance as to what values, if any, will be ascribed in the Chapter 11 Cases to each of these constituencies or what types or amounts of distributions, if any, they would receive. A plan of reorganization could result in holders of our liabilities and/or securities, including our common stock and preferred stock, receiving no distribution on account of their interests and cancellation of their holdings. As discussed above, if certain requirements of the Bankruptcy Code are met, a plan of reorganization can be confirmed notwithstanding its rejection by the holders of our common stock or preferred stock and notwithstanding the fact that such holders do not receive or retain any property on account of their equity interests under the plan. Because of such possibilities, the value of the Debtors’ securities is highly speculative.

Appointment of Creditors’ Committee

On August 26, 2019, the Bankruptcy Court appointed the official committee of unsecured creditors (the “Creditors’ Committee”). The Creditors’ Committee and its legal representatives have a right to be heard on all matters that come before the Bankruptcy Court with respect to the Debtors.

Ability to Continue as a Going Concern

We currently expect that the Company’s cash flows, cash on hand and any financing that we are able to obtain through the DIP Facility should provide sufficient liquidity for the Company during the pendency of the Chapter 11 Cases. However, the significant risks and uncertainties related to the Company’s liquidity and Chapter 11 Cases described above raise substantial doubt about the Company’s ability to continue as a going concern. The condensed consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The condensed consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. If the Company cannot continue as a going concern, adjustments to the carrying values and classification of its assets and liabilities and the reported amounts of income and expenses could be required and could be material.

Covenant Violations

The Debtors’ filing of the Bankruptcy Petitions described above constituted an event of default that accelerated the Company’s obligations under its Credit Agreement, its 7.75% Notes, its 6.125% Notes and its 7.25% Senior Secured Notes. Additionally, other events of default, including cross-defaults, are present under these debt instruments. Under the Bankruptcy Code, the creditors under these debt agreements are stayed from taking any action against the Company as a result of an event of default. Neither SN UnSub nor its general partner are parties to the Chapter 11 Cases, and the Chapter 11 Cases did not result in an event of default under the SN UnSub Credit Agreement. See “Part I, Item 1. Notes to the Condensed Consolidated Financial Statements—Note 7. Debt” for additional details about the Company’s debt.

Additionally, the filing of Bankruptcy Petitions described above constituted an event of default that generally allows counterparties to certain of the Company’s derivative contracts (excluding the counterparties to SN UnSub’s derivative contracts) to unilaterally terminate contracts to their scheduled settlement date(s) and pursue remedies, which are not subject to the automatic stay. In August 2019, as a result of the Chapter 11 Cases, one of our counterparties

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terminated its derivative contracts with the Company (excluding SN UnSub’s derivative contracts), resulting in a net payable of approximately $1.1 million due to the counterparty.

DIP Facility

In connection with the Bankruptcy Petitions, the Debtors filed a motion seeking, among other things, interim and final approval of debtor-in-possession financing on terms and conditions set forth in a proposed Senior Secured Debtor-in-Possession Term Loan Credit Agreement (as amended, supplemented or otherwise modified, the “DIP Facility”) among Sanchez Energy Corporation, as borrower, the financial institutions or other entities from time to time parties thereto, as lenders (the “DIP Lenders”), and Wilmington Savings Fund Society, FSB (“WSFS”), as administrative agent and collateral agent (the “DIP Agent”). The initial lenders under the DIP Facility are members of an ad hoc group of certain holders of the 7.25% Senior Secured Notes (the “Secured Noteholders”) or affiliates of such Secured Noteholders. The DIP Facility was approved by the Bankruptcy Court on an interim basis and the Company closed and borrowed an initial $50 million of new money loans thereunder on August 19, 2019, following the Bankruptcy Court’s entry of an interim order approving the DIP Facility on August 16, 2019. On September 19, 2019, the Bankruptcy Court declined to grant final approval of the DIP Facility at that time, and the Debtors, the DIP Lenders and certain other stakeholders are in ongoing discussions regarding the terms of the DIP Facility that will be presented to the Bankruptcy Court again for final approval at a subsequent hearing. The Company’s ability to access the remaining additional principal amount of new term loans under the DIP Facility is subject to the final approval of the Bankruptcy Court. On September 24, 2019, the Company, the DIP Agent and the Required Lenders (as defined in the DIP Facility) entered into an amendment to the DIP Facility (the “Amendment”). By its terms, the Amendment was effective as of September 20, 2019. The Amendment provided for, among other things, an extension to October 2, 2019  of the milestone date set forth in the DIP Facility for the entry of a final order of the Bankruptcy Court authorizing the Debtors’ entry into the DIP Facility and the other transactions contemplated by the DIP Facility (the “Final DIP Order”) and provided for the further extension of such milestone date with the consent of the Required Lenders. The milestone date set forth in the Loan Agreement for the entry of the Final DIP Order was subsequently extended, as contemplated and permitted by the Amendment, by the Required Lenders until the earlier of (i) November 15, 2019 and (ii) the date on which any of the Debtors files any material motion with respect to the Debtors’ business operations without the prior written consent of the Required Lenders. The DIP Facility, as it was approved on an interim basis, contains the terms as set forth below (although certain of the below terms are subject to modification prior to final approval of the DIP Facility):

· a senior secured priming superpriority debtor-in-possession term loan facility in an aggregate principal amount of up to $350 million, consisting of (i) a new money, multiple draw term loan facility in the amount of $175 million (the “New Money DIP Loans”), backstopped by certain Secured Noteholders (the “Backstop Lenders”), $50 million of which was available on an interim basis upon entry of the Bankruptcy Court’s interim order (the “Interim DIP Order”); and (ii) a refinancing term loan effectuated by way of a conversion of $175 million of 7.25% Senior Secured Notes into obligations under the DIP Facility (the “Roll-Up Loans” and, together with the New Money DIP Loans, the “DIP Loans”);

· borrowings under the (i) New Money DIP Loans will bear interest at a rate per annum equal to adjusted LIBOR (subject to a 2% floor) plus 8.00% and (ii) Roll-Up Loans will bear interest at the non-default rate of the 7.25% Senior Secured Notes of 7.25% per annum;

· the Company has paid the Backstop Lenders a 5.00% fee in cash in exchange for their commitment to backstop the New Money DIP Loans, and the Company is also required to pay (i) the DIP Lenders a 1.00% fee on the New Money DIP Loans payable upon the Debtors’ emergence from the Chapter 11 Cases and (ii) the DIP Lenders a 0.5% per annum commitment fee on undrawn New Money DIP Loans payable monthly;

· the maturity of the DIP Facility is nine months after the Petition Date, subject to earlier termination upon occurrence of customary defaults;

· the proceeds of the New Money DIP Loans may be used for: (i) transaction costs, fees and expenses; (ii) working capital and general corporate purposes; (iii) bankruptcy-related costs and expenses (including restructuring fees and adequate protection payments); and (iv) subject to final approval of the Bankruptcy Court, refinancing all amounts existing under the Company’s existing Credit Agreement;

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· the obligations under the New Money DIP Loans will be secured (subject to the Carve-Out (as defined below) and certain “first-out” obligations as set forth in the Interim DIP Order) on the following bases: (i) a superpriority administrative claim; (ii) a perfected first priority senior security interest and lien on all unencumbered property (subject to certain exceptions set forth in the DIP Facility and/or the Interim DIP Order); (iii) a perfected first priority, senior priming security interest and lien on all property subject to valid, perfected and nonavoidable prepetition liens securing the obligations under the 7.25% Senior Secured Notes (subject to certain exceptions as specified in the DIP Facility and/or the Interim DIP Order); and (iv) a perfected junior lien on certain other property subject to valid, perfected and unavoidable prepetition liens;

· the obligations under the Roll-Up Loans will be secured (subject to the Carve-Out and certain “first-out” obligations as set forth in the Interim DIP Order) on the following bases: (i) a superpriority administrative claim and (ii) a perfected first priority, senior priming security interest and lien on all property subject to valid, perfected and nonavoidable prepetition liens securing the obligations under the 7.25% Senior Secured Notes (subject to certain exceptions as specified in the DIP Facility and the Interim DIP Order);

· the Debtors’ Chapter 11 Cases are subject to certain milestones, including with respect to the filing and approvals of a disclosure statement and a Chapter 11 plan of reorganization;

· the DIP Facility will provide for certain customary covenants applicable to the Company, including covenants requiring (i) minimum liquidity in an amount of $15 million, subject to certain exclusions; (ii) beginning the first four-week period ending after the Petition Date, compliance with an approved operating debtor-in-possession budget (the “DIP Budget”), subject to permitted variance of 15% (with variance of 25% for midstream-related disbursements for the first four-week test period), tested on a rolling four-week basis on disbursements excluding certain professional fees, DIP Facility interest and fees and adequate protection payments; and (iii) delivery of a rolling 13-week operating cash flow forecast updated every four weeks and a weekly DIP Budget variance report; and

· the Debtors’ obligations to the DIP Lenders and the liens and superpriority claims are subject in each case to a carve-out (the “Carve-Out”) that accounts for certain administrative, court and legal fees payable in connection with the Chapter 11 Cases.

In addition, the Interim DIP Order contemplates that under the terms of the Final DIP Order, we will be required to pay the approximately $18.1 million in interest that would have been due on August 15, 2019 under the indenture for the Senior Secured 7.25% Notes, and are required to continue to make the semi-annual interest payments as they come due under the indenture for the Senior Secured 7.25% Notes during the Chapter 11 Cases.

There can be no assurance that the DIP Facility will be approved on a final basis, on the terms described above, or at all.  We are in ongoing conversations with the DIP Lenders and other stakeholders regarding the terms of the Final DIP Order and the DIP Facility.

Derivative Contracts

The filing of Bankruptcy Petitions described above constituted an event of default that generally allows counterparties to certain of the Company’s derivative contracts (excluding the counterparties to SN UnSub’s derivative contracts) to unilaterally terminate contracts to their scheduled settlement date(s) and pursue remedies, which are not subject to the automatic stay. In August 2019, as a result of the Bankruptcy Petitions, one of our counterparties terminated its derivative contracts with the Company (excluding SN UnSub’s derivative contracts), resulting in a net payable of approximately $1.1 million due to the counterparty.

Basis of Presentation

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

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Core Properties

Eagle Ford Shale

We and our predecessor entities have a long history in the Eagle Ford Shale, where, as of September 30, 2019, we had assembled approximately 435,000 gross (233,000 net) leasehold acres.

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.

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, the Company had achieved a 30-well bank at Comanche that was applied toward the annual development commitment for the period that extended from September 1, 2018 to August 31, 2019. The Company completed and equipped an additional 63 wells at Comanche between September 1, 2018 and August 31, 2019, resulting in a total of 93 wells that were applied toward the 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, and has completed and equipped 30 wells that can be applied toward the development commitment for the period September 1, 2019 to August 31, 2020. The Company completed and equipped an additional six wells at Comanche between September 1, 2019 and September 30, 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 Resources, LLC (“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. On the Petition Date, the arbitrator was notified by letter of the filing of the Bankruptcy Petitions and of the automatic stay under the Bankruptcy Code.

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.

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. For the commitment period ending June 30, 2019, the Company drilled a total of 63 wells toward the annual drilling commitment of 50 wells. Accordingly, the Company met all of its 50-well annual drilling commitment for the period July 1, 2018 to June 30, 2019 and initiated a bank of 13 wells that will be counted toward the next annual drilling commitment period. We drilled four additional wells in the Catarina area during the third quarter 2019, bringing our total to 17 wells toward the commitment period July 1, 2019 to June 30, 2020. Furthermore, our 2019 drilling activities from July 1, 2019 to the present date and our capital budget and current plans include the additional activity needed to fulfill the commitment to drill at least one well in any 120-day period and the activity needed, when combined with expected activity in the first half of 2020, to comply with the 50-well annual drilling commitment for the period July 1, 2019 to June 30, 2020.

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We have approximately 58,000 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 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.

Marathon Oil EF LLC (“Marathon”) is the operator and other lessee of our Palmetto acreage position. In the Palmetto 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 the lessees thereof to (i) complete six gross (three net) wells and drill and complete an additional four gross (two net) wells during the 2019 calendar year and (ii) drill and complete up to 10 gross (five net) wells, depending on commodity pricing in each calendar year beginning in 2020. If the lessees under such leases fail to complete and equip the required number of wells in a given year (after applying any qualifying additional wells from previous years and any required additional wells drilled and completed prior to the applicable extension cutoff date in the following year), the leases terminate as to all lands and depths not included within a retained tract at the end of the applicable calendar year, as further described in, and pursuant to the terms and conditions of, each such lease. For the 2019 commitment, Marathon has completed six gross wells and drilled four gross wells that are currently in the process of completion, thereby satisfying the 2019 development commitment and complying with applicable lease requirements necessary to maintain our Palmetto acreage position if timely completed.

Tuscaloosa Marine Shale

As of September 30, 2019, we owned approximately 12,400 net acres in the TMS. Although TMS development is currently challenged due to well costs and commodity prices, we believe that the TMS play may offer significant future development potential as changes in technology, commodity prices and service costs occur.

Recent Developments

Please see the first paragraph under “Business Overview,” “—Voluntary Reorganization Under Chapter 11” and  “—DIP Facility” above, in addition to the other matters discussed above regarding our Bankruptcy Petitions and related matters.

UnSub Tolling Agreement

On August 10, 2019, the Company entered into a tolling agreement (the “Tolling Agreement”) among Sanchez Energy Corporation, SN UR Holdings, SN EF UnSub Holdings, LLC (“SN UnSub Holdings”), SN Maverick (together with Sanchez Energy Corporation, SN UR Holdings and SN UnSub Holdings, the “Sanchez Parties”), GSO ST Holdings Associates LLC (“GSO LLC”) and GSO ST Holdings LP (together with GSO LLC, the “GSO Parties”).

Pursuant to the terms of the Tolling Agreement, except for participating in, or filing pleadings in respect of, any matter pending before the applicable bankruptcy court, during the Tolling Period (as defined below), the GSO Parties agreed to not exercise any rights or remedies with respect to any Investor Redemption Event, as defined in the Amended and Restated Limited Liability Company Agreement of SN EF UnSub GP, LLC, dated March 1, 2017 (the “LLC Agreement”), or the Amended and Restated Agreement of Limited Partnership of SN EF UnSub, LP, dated March 1, 2017, and all notice or cure periods that may exist with respect to any Investor Redemption Event (as such term is defined in the LLC Agreement) will be tolled during the Tolling Period.

The Tolling Agreement expires on the calendar day following the occurrence of any of the following events (the “Tolling Period”): (1) the occurrence of any Bankruptcy Event (as defined in the LLC Agreement) with respect to SN UnSub Holdings; provided, however, that unless a notice of termination has been provided by the GSO Parties or there is less than five calendar days before the Order Deadline (as defined below), the Sanchez Parties will be obligated to provide the GSO Parties at least five business days’ written notice prior to commencement of a voluntary chapter 11 proceeding (a “Proceeding”) by SN UnSub Holdings; (2) the failure of Sanchez Energy Corporation, SN Maverick or SN UR Holdings, to the extent such party has commenced a Proceeding (the earliest commencement date of a Proceeding by Sanchez Energy Corporation, SN Maverick or SN UR Holdings, as applicable, the “Initial Petition Date”), to obtain a bankruptcy court order approving the Tolling Agreement by the 20th day after the Initial Petition Date (the “Order Deadline”), unless the parties agree to extend such date by written agreement (the Order Deadline was subsequently extended to September 24, 2019); or (3) the effectiveness of delivery by any party of a written notice of

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termination of the Tolling Period, with such notice to be effective on the fifth business day following delivery of notice to the other parties.

In the event that SN UnSub Holdings commences a Proceeding at any time, the parties have agreed that for all purposes the commencement by SN UnSub Holdings of a Proceeding will be deemed to have occurred on the Initial Petition Date immediately preceding the commencement of the Proceedings with respect to any other Sanchez entity.

On September 19, 2019, the Bankruptcy Court authorized the Debtors’ performance of their obligations under  the Tolling Agreement.

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. Although commodity and capital markets showed signs of improvement, oil prices experienced a significant decline in the fourth quarter 2018 and have remained volatile in 2019 through the present date. 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. The Company set its 2019 capital budget at a range of $100 million to $150 millionfor development and optimization activities in our core areas, which represents a substantial reduction from capital expenditures of approximately $593 million in 2018. We generally 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. As discussed in “Part I, Item 1. Notes to the Condensed Consolidated Financial Statements—Note 17. Commitments and Contingencies,” the Company is party to certain agreements that require it to meet annual drilling and development commitments to maintain undeveloped leasehold positions. To reduce its capital expenditures by this magnitude in 2019, the Company exercised privileges under certain of such agreements (primarily by utilizing well “banks” achieved through drilling and developing wells in excess of the quantity required to maintain the related acreage during prior annual periods) and negotiated deferral arrangements. If the Company is unable to negotiate additional extensions, deferrals, waivers or other similar arrangements to delay or otherwise reduce the activity necessary to maintain such undeveloped leasehold positions, it may be unable to continue to hold capital expenditures at comparable low levels in future years. As a result, the Company may be required to seek additional funding sources in order to pursue development plans which would maintain certain of its undeveloped acreage.

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. In anticipation of potential liquidity constraints, the Company commenced discussions with its bondholders, other stakeholders and potential third-party investors on a restructuring transaction to reduce the Company’s debt and strengthen its overall financial flexibility.  On July 15, 2019, the Company elected to defer making an interest payment of approximately $35.2 million on the Company’s 6.125% Notes for a 30-day grace period which expired on August 14, 2019, in order to preserve liquidity and continue discussions with stakeholders. On the Petition Date, prior to the expiration of the grace period, the Company and other Debtors filed the Bankruptcy Petitions with the Bankruptcy Court and were authorized to continue to operate their businesses as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

Although the Company has not yet reached an agreement with any of its stakeholders on the terms of a comprehensive restructuring transaction, the Company obtained additional financing pursuant to the DIP Facility on an interim basis. Following the Petition Date, the Company has continued to engage with stakeholders in pursuit of a comprehensive restructuring transaction.  The Company believes the Chapter 11 Cases provide the most expeditious manner in which to effect a capital structure solution. In order to successfully exit the Chapter 11 Cases, we will need to obtain confirmation by the Bankruptcy Court of a plan (or plans) of reorganization that satisfies the requirements of the Bankruptcy Code. A plan of reorganization would, among other things, resolve the Debtors’ prepetition obligations, set forth the revised capital structure of the newly reorganized entity and provide for corporate governance subsequent to exit from the Chapter 11 Cases. However, there can be no assurance that the Company will be able to reorganize its capital structure on terms acceptable to the Company and the other Debtors, their creditors or other stakeholders, or at all.

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Results of Operations

Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 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				Decrease
	September 30,				2019 vs. 2018
	2019		2018		$		%
Net Production:
Oil (MBbls)		1,926		2,300		(374)	(16)	%
Natural gas liquids (MBbls)		2,029		2,473		(444)	(18)	%
Natural gas (MMcf)		11,404		13,174		(1,770)	(13)	%
Total oil equivalent (MBoe)		5,856		6,969		(1,113)	(16)	%
Average Sales Price Excluding Derivatives(1):
Oil ($ per Bbl)	$	55.04	$	70.11	$	(15.07)	(21)	%
Natural gas liquids ($ per Bbl)		11.17		28.30		(17.13)	(61)	%
Natural gas ($ per Mcf)		2.33		3.00		(0.67)	(22)	%
Oil equivalent ($ per Boe)	$	26.51	$	38.84	$	(12.33)	(32)	%
Average Sales Price Including Derivatives(2):
Oil ($ per Bbl)	$	53.64	$	55.19	$	(1.55)	(3)	%
Natural gas liquids ($ per Bbl)		11.17		28.30		(17.13)	(61)	%
Natural gas ($ per Mcf)		2.55		3.19		(0.64)	(20)	%
Oil equivalent ($ per Boe)	$	26.49	$	34.29	$	(7.80)	(23)	%
Revenues from Production(1)(3):
Oil sales	$	106,016	$	161,243	$	(55,227)	(34)	%
Natural gas liquids sales		22,675		69,995		(47,320)	(68)	%
Natural gas sales		26,572		39,460		(12,888)	(33)	%
Total revenues from production	$	155,263	$	270,698	$	(115,435)	(43)	%

(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
	September 30,
	2019		2018
Net Production:
Oil (MBbls)
Comanche		917		1,011
Catarina		672		891
Maverick		220		347
Palmetto		95		25
TMS / Other		22		26
Total		1,926		2,300
Natural gas liquids (MBbls)
Comanche		807		932
Catarina		1,191		1,531
Maverick		4		3
Palmetto		27		7
Total		2,029		2,473
Natural gas (MMcf)
Comanche		4,644		4,895
Catarina		6,589		8,235
Maverick		20		10
Palmetto		151		34
Total		11,404		13,174
Net production volumes:
Total oil equivalent (MBoe)		5,856		6,969
Average daily production (Boe/d)		63,652		75,750
Average sales price (1):
Oil ($ per Bbl)	$	55.04	$	70.11
Natural gas liquids ($ per Bbl)	$	11.17	$	28.30
Natural gas ($ per Mcf)	$	2.33	$	3.00
Oil equivalent ($ per Boe)	$	26.51	$	38.84
Average unit costs per Boe:
Oil and natural gas production expenses	$	12.76	$	10.85
Production and ad valorem taxes	$	1.68	$	2.18
General and administrative expenses	$	3.57	$	3.06
Depreciation, depletion, amortization and accretion	$	9.88	$	9.75
Impairment of oil and natural gas properties	$	1.67	$	0.45

(1) Excludes the realized impact of derivative instrument settlements.

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Net Production. Production decreased from 6,969 MBoe for the three months ended September 30, 2018 to 5,856 MBoe for the three months ended September 30, 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 September 30,
	2019		2018
	# Wells	MBoe	# Wells	MBoe
Comanche	1,782	2,498	1,701	2,758
Catarina	460	2,961	441	3,795
Palmetto	81	147	86	38
Maverick	66	227	66	352
TMS / Other	46	23	47	26
Total	2,435	5,856	2,341	6,969

For the three months ended September 30, 2019 and 2018, 33% of our production was oil, 35% was NGLs and 32% was natural gas.

Revenues from Production. Sales revenue for oil, NGLs and natural gas from production totaled $155.3 million and $270.7 million for the three months ended September 30, 2019 and 2018, respectively. Sales revenue for oil, NGLs and natural gas for the three months ended September 30, 2019 decreased $55.2 million, $47.3 million and $12.9 million, respectively, as compared to the three months ended September 30, 2018.  These decreases were due to decreases in production, as discussed above, as well as decreases in average realized prices as compared to the comparable period of 2018.

Sales and Marketing Revenues. The Company recorded sales and marketing revenues of $7.3 million and $7.0 million during the three months ended September 30, 2019 and 2018, respectively.  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 September 30, 2018 to the three months ended September 30, 2019 (in thousands, except average sales price).

	Production Volume						Three Months Ended		Revenue
	Three Months Ended September 30,						September 30, 2018		Decrease
	2019		2018		Difference		Average Sales Price		from Production
Oil (MBbls)		1,926		2,300		(374)	$	70.11	$	(26,220)
NGLs (MBbls)		2,029		2,473		(444)	$	28.30	$	(12,567)
Natural gas (MMcf)		11,404		13,174		(1,770)	$	3.00	$	(5,302)
Total oil equivalent (MBoe)		5,856		6,969		(1,113)	$	38.84	$	(44,089)
	Average Sales Price per  Unit						Three Months Ended		Revenue
	Three Months Ended September 30,						September 30, 2019		Decrease
	2019		2018		Difference		Production Volume		from Price
Oil (MBbls)	$	55.04	$	70.11	$	(15.07)		1,926	$	(29,007)
NGLs (MBbls)	$	11.17	$	28.30	$	(17.13)		2,029	$	(34,753)
Natural gas (MMcf)	$	2.33	$	3.00	$	(0.67)		11,404	$	(7,586)
Total oil equivalent (MBoe)	$	26.51	$	38.84	$	(12.33)		5,856	$	(71,346)

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Additionally, a 10% increase or decrease in our average realized sales prices for the three months ended September 30, 2019, excluding the impact of derivatives, would have increased or decreased our revenues by approximately $15.5 million.

Operating Costs and Expenses

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

	Three Months Ended				Increase (Decrease)
	September 30,				2019 vs. 2018
	2019		2018		$		%
Oil and natural gas production expenses	$	74,740	$	75,594	$	(854)	(1)	%
Exploration expenses		164		2,698		(2,534)	(94)	%
Sales and marketing expenses		6,672		7,239		(567)	(8)	%
Production and ad valorem taxes		9,867		15,221		(5,354)	(35)	%
Depreciation, depletion, amortization and accretion		57,864		67,944		(10,080)	(15)	%
Impairment of oil and natural gas properties		9,761		3,117		6,644	*
General and administrative expenses(1)		20,915		21,312		(397)	(2)	%
Prepetition restructuring charges		18,231		—		18,231	*
Total operating costs and expenses		198,214		193,125		5,089	3	%
Interest income		221		1,130		(909)	(80)	%
Other expense		(12,829)		(7,677)		(5,152)	67	%
Interest expense		(22,884)		(44,154)		21,270	(48)	%
Net gains (losses) on commodity derivatives		13,200		(28,286)		41,486	*
Reorganization items		55,321		—		55,321	*
Income tax benefit		(833)		—		(833)	*

*Variances deemed to be not meaningful

(1) Includes non-cash stock-based compensation expense of $0.1 million and non-cash stock-based compensation benefit  $1.4 million for the three months ended September 30, 2019 and 2018, respectively.

Oil and Natural Gas Production Expenses. Oil and natural gas production expenses are the costs incurred to produce our oil and natural gas, as well as the daily costs incurred to maintain our producing properties. Our oil and natural gas production expenses decreased to $74.7 million ($12.76 per Boe) for the three months ended September 30, 2019, as compared to $75.6 million ($10.85 per Boe) for the same period in 2018.  Upon adoption of ASC 842 on January 1, 2019, the Western Catarina Midstream deferred gain was derecognized. During the three months ended September 30, 2018, the Company recognized a benefit of approximately $5.9 million related to the amortization of the Western Catarina Midstream deferred gain, and oil and natural gas production expenses, excluding the amortization of the Western Catarina Midstream deferred gain, were approximately $81.5 million ($11.70 per Boe). The decrease in oil and natural gas production expenses from the three months ended September 30, 2018, excluding the amortization of the Western Catarina Midstream deferred gain, compared to the three months ended September 30, 2019 is primarily attributable to a decrease in production. The increase in oil and natural gas production expenses per Boe for the three months ended September 30, 2019 compared to the three months ended September 30, 2018 is primarily related to a decrease in production.

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 $0.2 million and $2.7 million during the three months ended September 30, 2019 and 2018, respectively. The decrease in our exploration expenses for the three months ended September 30, 2019 as compared to the same period in 2018 was primarily due to a decrease in activity leading to reduced exploratory geological and geophysical seismic costs.

Sales and Marketing Expenses. The Company incurred sales and marketing expenses of approximately $6.7 million and $7.2 million for the three months ended September 30, 2019 and 2018, respectively.  We believe an opportunity exists, from time to time, to participate in additional economic benefits and operational efficiencies in

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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 $9.9 million ($1.68 per Boe) and $15.2 million ($2.18 per Boe) for the three months ended September 30, 2019 and 2018, respectively. The decrease in production and ad valorem taxes in the third quarter 2019 compared to the same period in 2018 was primarily due to the decrease in production taxes based on the corresponding decrease in revenue during the period.

Depreciation, Depletion, Amortization and Accretion. Depreciation, depletion, amortization and accretion  expense decreased $10.0 million from $67.9 million ($9.75 per Boe) for the three months ended September 30, 2018 to $57.9 million ($9.88 per Boe) for the three months ended September 30, 2019. The decrease in expense represented an approximate $10.8 million decrease from lower production which was partially offset by a $0.8 million increase due to a higher depletion rate.

Impairment of Oil and Natural Gas Properties. We did not record proved property impairments for the three months ended September 30, 2019 or 2018. We recorded impairment of $9.8 million and $3.1 million to our unproved oil and natural gas properties for the three months and ended September 30, 2019 and 2018, respectively, due to acreage expiration from changes in the development plan. Significant declines in commodity prices, further changes to the Company’s drilling plans or reductions in proved reserve estimates could result in proved property impairments in the future, and such impairments could be substantial.

General and Administrative Expenses. Our G&A expenses totaled $20.9 million ($3.57 per Boe) for the three months ended September 30, 2019 compared to $21.3 million ($3.06 per Boe) for the same period in 2018. This decrease was primarily the result of lower professional, consulting and legal expenses, not related to restructuring activities, and a reduction in employee headcount.  

Prepetition Restructuring Charges. Any expenses incurred before the Petition Date and in relation to the Chapter 11 Cases are recorded as prepetition restructuring charges on our condensed consolidated statements of operations. Prepetition restructuring charges totaled $18.2 million for the three months ended September 30, 2019, which primarily consisted of professional, consulting and legal fees. There were no prepetition restructuring charges for the three months ended September 30, 2018. 

Other Expense. For the three months ended September 30, 2019 and 2018, respectively, other expense totaled $12.8 million compared to other expense of $7.7 million for the three months ended September 30, 2018. The other expense during the three months ended September 30, 2019 relates primarily to an $11.8 million loss on impairment of a prepaid asset.  Additionally, we experienced a loss of $4.3 million associated with the decrease in fair value of the investment in SNMP, which was partially offset by a gain of $0.6 million associated with the increase in fair value of the investment in Lonestar. For the comparable period of 2018, we did not experience any losses on impairment of prepaid assets, and we experienced losses of $10.7 million and  $1.0 million associated with the decreases in fair value of the investments in Lonestar and SNMP, respectively. Additionally, for the three month period ended September 30, 2019, we recorded $2.4 million of income from equipment rentals, we did not record any dividend income from the SNMP common units and we did not experience any gains or losses on embedded derivatives. For the three months ended September 30, 2018, we recorded income from equipment rentals of $3.0 million, dividend income of $1.1 million from the SNMP common units, and a loss on embedded derivatives of $1.1 million.

Interest Expense. For the three months ended September 30, 2019, interest expense totaled $22.9 million and included $2.0 million in amortization of debt issuance costs. For the three months ended September 30, 2018, interest expense totaled $44.2 million and included $2.9 million in amortization of debt issuance costs. As of the Petition Date we discontinued recording interest expense on all debt instruments classified as liabilities subject to compromise, which was the primary driver in the decrease in interest expense. However, it is currently proposed that under the terms of the Final DIP Order, we will be required to pay the approximately $18.1 million in interest that would have been due on August 15, 2019 under the indenture for the 7.25% Senior Secured Notes and are required to continue making the semi-

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annual interest payments as they come due under the indenture for the 7.25% Senior Secured Notes during the Chapter 11 Cases. Additionally as of the Petition Date, we expensed the related unamortized debt issuance costs as reorganization items.

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 September 30, 2019, we recognized a net gain of $13.2 million on our commodity derivative contracts, which included mark-to-market gains on unsettled oil derivatives of $15.8 million and mark-to-market losses on unsettled natural gas derivatives of $2.5 million. In addition, during the three months ended September 30, 2019, we experienced net settlement losses of $0.1 million, which included settlement losses of $2.7 million on our oil derivative contracts and settlement gains of $2.6 million on our natural gas derivative contracts. The mark-to-market gains and losses were a result of the decreases and increases, respectively, in estimated future commodity prices as compared to the estimated future prices at the prior measurement date. The settlement losses and gains during the period were primarily a result of increases and decreases, respectively, in commodity prices from the time the positions were entered into until the time of settlement. During the three months ended September 30, 2018, we recognized a net loss of $28.3 million on our commodity derivative contracts, which included mark-to-market gains on our oil derivative contracts of $6.0 million and mark-to-market losses on our natural gas derivative contracts of $2.5 million. In addition, during the three months ended September 30, 2018, we experienced settlement losses on our oil derivative contracts of $34.3 million partially offset by settlement gains of $2.5 million on our natural gas derivative contracts.

Reorganization Items. The Company has incurred and is expected to continue to incur significant costs associated with the reorganization. These costs, which are expensed as incurred, are expected to significantly affect the Company’s results of operations. Reorganization items represent costs directly associated with the Chapter 11 Cases since the Petition Date. Such costs include accruals related to the DIP Facility and postpetition fees and expenses of court-approved legal and financial advisors, which are subject to Bankruptcy Court orders and/or oversight.

The following table summarizes the components of reorganization items included on the condensed consolidated statement of operations (in thousands):

	Three Months Ended
	September 30, 2019
DIP lender fee on initial borrowing	$	8,814
DIP Facility costs		4,512
Legal and other professional advisory fees		11,571
Unamortized deferred financing fees, discounts and premiums		30,424
Reorganization items	$	55,321

Income Tax Benefit.  For the three months ended September 30, 2019, the Company recorded an income tax benefit of $0.8 million, and our effective tax rate was approximately 0.7%. The Company did not record an income tax expense or benefit for the three months ended September 30, 2018, and our effective tax rate was 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.

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Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018

Net Production and Revenues from Production

The following table summarizes net 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):

	Nine Months Ended				Increase (Decrease)
	September 30,				2019 vs. 2018
	2019		2018		$		%
Net Production:
Oil (MBbls)		6,375		7,198		(823)	(11)	%
Natural gas liquids (MBbls)		6,539		7,363		(824)	(11)	%
Natural gas (MMcf)		36,657		41,373		(4,716)	(11)	%
Total oil equivalent (MBoe)		19,024		21,457		(2,433)	(11)	%
Average Sales Price Excluding Derivatives(1):
Oil ($ per Bbl)	$	56.85	$	65.74	$	(8.89)	(14)	%
Natural gas liquids ($ per Bbl)		14.21		23.88		(9.67)	(40)	%
Natural gas ($ per Mcf)		2.75		2.96		(0.21)	(7)	%
Oil equivalent ($ per Boe)	$	29.24	$	35.95	$	(6.71)	(19)	%
Average Sales Price Including Derivatives(2):
Oil ($ per Bbl)	$	55.08	$	53.75	$	1.33	2	%
Natural gas liquids ($ per Bbl)		14.21		23.88		(9.67)	(40)	%
Natural gas ($ per Mcf)		2.82		3.16		(0.34)	(11)	%
Oil equivalent ($ per Boe)	$	28.78	$	32.32	$	(3.54)	(11)	%
Revenues from Production(1)(3):
Oil sales	$	362,424	$	473,178	$	(110,754)	(23)	%
Natural gas liquids sales		92,891		175,833		(82,942)	(47)	%
Natural gas sales		100,932		122,330		(21,398)	(17)	%
Total revenues from production	$	556,247	$	771,341	$	(215,094)	(28)	%

(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:

	Nine Months Ended
	September 30,
	2019		2018
Net Production:
Oil (MBbls)
Comanche		2,962		3,350
Catarina		2,435		2,491
Maverick		713		1,201
Palmetto		203		82
TMS / Other		62		74
Total		6,375		7,198
Natural gas liquids (MBbls)
Comanche		2,543		2,993
Catarina		3,931		4,325
Maverick		13		20
Palmetto		52		25
Total		6,539		7,363
Natural gas (MMcf)
Comanche		14,176		16,429
Catarina		22,123		24,716
Maverick		73		94
Palmetto		285		134
Total		36,657		41,373
Net production volumes:
Total oil equivalent (MBoe)		19,024		21,457
Average daily production (Boe/d)		69,685		78,597
Average sales price (1):
Oil ($ per Bbl)	$	56.85	$	65.74
Natural gas liquids ($ per Bbl)	$	14.21	$	23.88
Natural gas ($ per Mcf)	$	2.75	$	2.96
Oil equivalent ($ per Boe)	$	29.24	$	35.95
Average unit costs per Boe:
Oil and natural gas production expenses	$	12.17	$	10.49
Production and ad valorem taxes	$	1.82	$	2.00
General and administrative expenses	$	3.48	$	3.41
Depreciation, depletion, amortization and accretion	$	9.88	$	8.83
Impairment of oil and natural gas properties	$	1.20	$	0.20

(1) Excludes the realized impact of derivative instrument settlements.

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Net Production. Production decreased from 21,457 MBoe for the nine months ended September 30, 2018 to 19,024 MBoe for the nine months ended September 30, 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:

	Nine Months Ended September 30,
	2019		2018
	# Wells	MBoe	# Wells	MBoe
Comanche	1,782	7,868	1,701	9,082
Catarina	460	10,053	441	10,935
Palmetto	81	738	86	129
Maverick	66	303	66	1,237
TMS / Other	46	63	47	74
Total	2,435	19,025	2,341	21,457

For the nine months ended September 30, 2019 and 2018, 34% of our production was oil, 34% was NGLs and 32% was natural gas.

Revenues from Production. Sales revenue foroil, NGLs and natural gas from production totaled $556.2 million and $771.3 million for the nine months ended September 30, 2019 and 2018, respectively. Sales revenue for oil,  NGLs and natural gas decreased $110.8 million, $82.9 million and $21.4 million, respectively, as compared to the nine months ended September 30, 2018.  These decreases were due to decreases in production, as discussed above, as well as decreases in average realized prices as compared to the comparable period of 2018.

Sales and Marketing Revenues. The Company recorded sales and marketing revenues of $18.1 million and $16.9 million during the nine months ended September 30, 2019 and 2018, respectively. 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 nine months ended September 30, 2018 to the nine months ended September 30, 2019 (in thousands, except average sales price).

	Production Volume						Nine Months Ended		Revenue
	Nine Months Ended September 30,						September 30, 2018		Decrease
	2019		2018		Difference		Average Sales Price		from Production
Oil (MBbls)		6,375		7,198		(823)	$	65.74	$	(54,102)
NGLs (MBbls)		6,539		7,363		(824)	$	23.88	$	(19,678)
Natural gas (MMcf)		36,657		41,373		(4,716)	$	2.96	$	(13,944)
Total oil equivalent (MBoe)		19,024		21,457		(2,433)	$	35.95	$	(87,724)
	Average Sales Price per  Unit						Nine Months Ended		Revenue
	Nine Months Ended September 30,						September 30, 2019		Increase/(Decrease)
	2019		2018		Difference		Production Volume		from Price
Oil (MBbls)	$	56.85	$	65.74	$	(8.89)		6,375	$	(56,652)
NGLs (MBbls)	$	14.21	$	23.88	$	(9.67)		6,539	$	(63,264)
Natural gas (MMcf)	$	2.75	$	2.96	$	(0.21)		36,657	$	(7,454)
Total oil equivalent (MBoe)	$	29.24	$	35.95	$	(6.71)		19,024	$	(127,370)

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 $55.6 million.

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Operating Costs and Expenses

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

	Nine Months Ended				Increase (Decrease)
	September 30,				2019 vs. 2018
	2019		2018			$	%
Oil and natural gas production expenses	$	231,441	$	225,186	$	6,255	3	%
Exploration expenses		4,983		3,247		1,736	53	%
Sales and marketing expenses		16,591		16,498		93	1	%
Production and ad valorem taxes		34,682		42,898		(8,216)	(19)	%
Depreciation, depletion, amortization and accretion		187,920		189,515		(1,595)	(1)	%
Impairment of oil and natural gas properties		22,906		4,259		18,647	*
General and administrative expenses(1)		66,266		73,199		(6,933)	(9)	%
Prepetition restructuring charges		41,855		—		41,855	*
Total operating costs and expenses		606,644		554,802		51,842	9	%
Interest income		1,447		3,400		(1,953)	(57)	%
Other income (expense)		(13,785)		2,467		(16,252)	*
Gain on sale of oil and natural gas properties		—		1,528		(1,528)	*
Interest expense		(111,998)		(132,664)		20,666	(16)	%
Net losses on commodity derivatives		(20,827)		(142,384)		121,557	(85)	%
Reorganization items		55,321		—		55,321	*
Income tax benefit		(23)		—		(23)	*

*Variances deemed to be not meaningful

(1) Includes non-cash stock-based compensation expense of $0.4 million and $2.9 million for the nine months ended September 30, 2019 and 2018, respectively. 

Oil and Natural Gas Production Expenses. Oil and natural gas production expenses are the costs incurred to produce our oil and natural gas, as well as the daily costs incurred to maintain our producing properties. Our oil and natural gas production expenses increased to approximately $231.4 million ($12.17 per Boe) for the nine months ended September 30, 2019 as compared to $225.2 million ($10.49 per Boe) for the same period in 2018. Upon adoption of ASC 842 on January 1, 2019, the Western Catarina Midstream deferred gain was derecognized. During the nine months ended September 30, 2018, the Company recognized a benefit of approximately $17.8 million related to the amortization of the Western Catarina Midstream deferred gain, and oil and natural gas production expenses, excluding the amortization of the Western Catarina Midstream deferred gain, were approximately $243.0 million ($11.32 per Boe). The decrease in oil and natural gas production expenses from the nine months ended September 30, 2018, excluding the amortization of the Western Catarina Midstream deferred gain, compared to the nine months ended September 30, 2019 is primarily attributable to a decrease in production. The decrease in oil and natural gas production expenses was slightly offset by an increase in transportation expenses from an increase in gathering and transportation rates on volumes produced outside of the dedicated acreage in Catarina. The increase in oil and natural gas production expenses per Boe for the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018 is primarily related to an increase in marketing and transportation expenses from an increase in gathering and transportation rates on volumes produced outside of the dedicated acreage in Catarina during January and April 2019 and a decrease in production.

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 $5.0 million and  $3.2 million during the nine months ended September 30, 2019 and 2018, respectively. The increase in our exploration expenses for the nine months ended September 30, 2019 as compared to the same period in 2018 was due to an increase in our exploratory geological and geophysical seismic costs and an increase in our delay rentals for the first half of 2019.

Sales and Marketing Expenses. The Company incurred sales and marketing expenses of approximately $16.6 million and $16.5 million for the nine months ended September 30, 2019 and 2018, respectively. We believe an

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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 $34.7 million ($1.82 per Boe) and  $42.9 million ($2.00 per Boe) for the nine months ended September 30, 2019 and 2018, respectively. The decrease in production and ad valorem taxes in the first nine months of 2019 compared to the same period in 2018 was primarily due to the corresponding decrease in revenues during the period.

Depreciation, Depletion, Amortization and Accretion. Depreciation, depletion, amortization and accretion expense decreased $1.6 million from $189.5 million ($8.83 per Boe) for the nine months ended September 30, 2018 to $187.9 million ($9.88 per Boe) for the nine months ended September 30, 2019.  The decrease in expense represented an approximate $21.5 million decrease from lower production which was partially offset by a $19.9 million increase due to a higher depletion rate.

Impairment of Oil and Natural Gas Properties. We recorded a proved property impairment of $4.3 million for the nine months ended September 30, 2019. We did not record a proved property impairment for the nine months ended September 30, 2018. We recorded impairment of $18.6 million and  $4.3 million to our unproved oil and natural gas properties for the nine months ended September 30, 2019 and 2018, respectively, due to acreage expiration from changes in the development plan. Significant declines in commodity prices, further changes to the Company’s drilling plans or reductions in proved reserve estimates could result in proved property impairments in the future, and such impairments could be substantial.

General and Administrative Expenses. Our G&A expenses totaled $66.3 million ($3.48 per Boe) for the nine months ended September 30, 2019 compared to $73.2 million ($3.41 per Boe) for the same period in 2018. This decrease was primarily the result of lower professional, consulting and legal expenses, not related to restructuring activities, and a reduction in employee headcount.  Additionally, we experienced a decrease in our stock-based compensation expense for the three months ended September 30, 2019 as compared to the same period in 2018 resulting from a decrease in the Company’s stock price. Offsetting these decreases, we experienced increases in salaries and wages resulting from employee retention and executive compensation programs.

Prepetition Restructuring Charges. Any expenses incurred before the Petition Date and in relation to the Chapter 11 Cases are recorded as prepetition restructuring charges on our condensed consolidated statements of operations. Prepetition restructuring charges totaled $41.9 million for the nine months ended September 30, 2019, which primarily consisted of professional, consulting and legal fees. There were no prepetition restructuring charges for the nine months ended September 30, 2018.

Other Income (Expense). For the nine months ended September 30, 2019, other expense totaled $13.8 million compared to other income of $2.5 million for the nine months ended September 30, 2018. The other expense during the nine months ended September 30, 2019 relates primarily to an $11.8 million loss on impairment of a prepaid asset and $1.2 million in shortfall and idle rig costs.  For the comparable period of 2018, we did not experience any losses on impairment of prepaid assets or idle rig costs. Additionally, for the nine months ended September 30, 2019 we experienced losses of $3.1 million and $1.4 million associated with the decreases in fair value of the investments in SNMP and Lonestar, respectively. For the nine months ended September 30, 2018, we experienced a loss of $9.1 million and a gain of $5.7 million associated with the decreases and increases in fair value of the investments in SNMP and Lonestar, respectively. Further, we received $2.6 million in income from equipment rentals during the nine months ended September 30, 2019 as compared to $7.3 million for the comparable period of 2018, we experienced a gain on our embedded derivative contracts of $0.3 million for the nine months ended September 30, 2019 as compared to a loss of $7.1 million for the comparable period of 2018, and we recorded dividend income of approximately $0.7 million from quarterly distributions on the SNMP common units as compared to $3.2 million for the comparable period of 2018.

Interest Expense. For the nine months ended September 30, 2019, interest expense totaled $112.0 million and included $8.3 million in amortization of debt issuance costs. For the nine months ended September 30, 2018, interest

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expense totaled $132.7 million and included $12.7 million in amortization of debt issuance costs. As of the Petition Date, we discontinued recording interest expense on all debt instruments classified as liabilities subject to compromise, which was the primary driver in the decrease in interest expense. However, it is currently proposed that under the terms of the Final DIP Order, we will be required to pay the approximately $18.1 million in interest that would have been due on August 15, 2019 under the indenture for the 7.25% Senior Secured Notes and are required to continue making the semi-annual interest payments as they come due under the indenture for the 7.25% Senior Secured Notes during the Chapter 11 Cases. Additionally as of the Petition Date, we expensed the related unamortized debt issuance costs as reorganization items.

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 nine months ended September 30, 2019, we recognized a net loss of $20.8 million on our commodity derivative contracts, which included net losses of $8.7 million associated with the settlements of commodity derivative contracts and mark-to-market losses of $12.1 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 estimated future prices at the prior measurement date. 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 nine months ended September 30, 2018, we recognized a net loss of $142.4 million on our commodity derivative contracts, which included mark-to-market losses on oil and natural gas derivative contracts of $50.0 million and $14.5 million, respectively. In addition, during the nine months ended September 30, 2018 we experienced settlement losses on our oil commodity derivative contracts of $86.3 million, which were partially offset by settlement gains of $8.5 million on our natural gas derivative contracts.

Reorganization Items. The Company has incurred and is expected to continue to incur significant costs associated with the reorganization. These costs, which are expensed as incurred, are expected to significantly affect the Company’s results of operations. Reorganization items represent costs directly associated with the Chapter 11 Cases since the Petition Date. Such costs include accruals related to the DIP Facility and postpetition fees and expenses of court-approved legal and financial advisors, which are subject to Bankruptcy Court orders and/or oversight.

The following table summarizes the components of reorganization items included on the condensed consolidated statement of operations (in thousands):

	Nine Months Ended
	September 30, 2019
DIP lender fee on initial borrowing	$	8,814
DIP Facility costs		4,512
Legal and other professional advisory fees		11,571
Unamortized deferred financing fees, discounts and premiums		30,424
Reorganization items	$	55,321

Income Tax Benefit.  For the nine months ended September 30, 2019, the Company recorded an income tax benefit of less than $0.1 million and our effective tax rate was approximately 0%. The Company did not record an income tax expense or benefit for the nine months ended September 30, 2018, and our effective tax rate was 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 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 September 30, 2019, our critical accounting policies were consistent with those discussed in our 2018 Annual Report.

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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 G&A 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, in addition to reduced production levels from our decreased capital expenditures budget, 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. On the Petition Date, the Debtors filed the Bankruptcy Petitions with the Bankruptcy Court and were authorized to continue to operate their businesses as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. See  “Part I, Item 1. Notes to the Condensed Consolidated Financial Statements—Note 3. Chapter 11 Cases—Voluntary Reorganization Under Chapter 11” and above in “—Business Overview—Voluntary Reorganization Under Chapter 11” for additional information.

As of September 30, 2019, we had approximately $179.5 million in cash and cash equivalents  and $90.0 million in available borrowing capacity under the SN UnSub Credit Agreement, resulting in aggregate liquidity of approximately $269.5 million. Borrowings under the DIP Facility are not available to SN UnSub or our other non-Debtor subsidiaries, and borrowings under the SN UnSub Credit Agreement are not available to the Debtors or any other non-Debtor subsidiary other than SN UnSub.

The Debtors’ filing of the Bankruptcy Petitions described above constituted an event of default that accelerated the Company’s obligations under the Credit Agreement, its 7.75% Notes, its 6.125% Notes and its 7.25% Senior Secured Notes  (approximately $2.3 billion in aggregate principal). We do not have sufficient liquidity to pay such accelerated amounts. Additionally, other events of default, including cross-defaults, are present under these debt instruments. Under the Bankruptcy Code, the creditors under these debt agreements are stayed from taking any action against the Company as a result of an event of default. See “Part I, Item 1. Notes to the Condensed Consolidated Financial Statements—Note 7. Debt” for additional details about the Company’s debt. The significant risks and uncertainties related to the Company’s liquidity and Chapter 11 Cases described under “Business Overview” raise substantial doubt about the Company’s ability to continue as a going concern. See above under “Business Overview” for a description of these and other developments. In addition, during the existence of an event of default under the Credit Agreement and the Chapter 11 Cases, we have no borrowing capacity under the Credit Agreement, even if any available borrowing capacity remained under the Credit Agreement (although, as noted below, we anticipate paying off the Credit Agreement in full subject to final approval of the Bankruptcy Court).

Neither SN UnSub nor its general partner are parties to the Chapter 11 Cases, and the Chapter 11 Cases did not result in an event of default under the SN UnSub Credit Agreement. On May 23, 2019, as part of the most recent semi-annual redetermination, the borrowing base under the SN UnSub Credit Agreement was decreased from $315 million to $240 million. As of September 30, 2019, there were approximately $150.0 million of borrowings and no letters of credit outstanding under the SN UnSub Credit Agreement. The next regularly scheduled borrowing base redetermination is expected in the fourth quarter 2019. Based upon current commodity prices and other factors, we believe that the borrowing base under the SN UnSub Credit Agreement will likely be decreased at the next redetermination and may be decreased at future redeterminations, and any or all such decreases may be material. Were the lenders under the SN UnSub Credit Agreement to reduce the borrowing base to an amount below the current outstanding borrowings of SN UnSub, and provided no waiver is granted by those lenders, we would be required at our election to repay the deficiency

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within 30 days (in a single installment) to 180 days (in six equal monthly installments), pledge additional oil and natural gas assets as security for the amount of debt outstanding, or seek such other remedies available under the SN UnSub Credit Agreement, in which case we may not be able to satisfy the liquidity requirements of SN UnSub.

The DIP Facility was approved by the Bankruptcy Court on an interim basis and the Company closed and borrowed an initial $50 million of new money loans thereunder on August 19, 2019, following the Bankruptcy Court’s entry of an interim order approving the DIP Facility on August 16, 2019. On September 19, 2019, the Bankruptcy Court declined to grant final approval of the DIP Facility at that time, and the Debtors, the DIP Lenders and certain other stakeholders are in ongoing discussions regarding the terms of the DIP Facility that will be presented to the Bankruptcy Court again for final approval at a subsequent hearing. The Company’s ability to access the remaining additional principal amount of new term loans under the DIP Facility is subject to the final approval of the Bankruptcy Court. On September 24, 2019, the Company, the DIP Agent and the Required Lenders entered into the Amendment. By its terms, the Amendment was effective as of September 20, 2019. The Amendment provided for, among other things, an extension to October 2, 2019  of the milestone date set forth in the DIP Facility for the entry of a final order of the Bankruptcy Court authorizing the Debtors’ entry into the DIP Facility and the other transactions contemplated by the Final DIP Order and provided for the further extension of such milestone date with the consent of the Required Lenders. The milestone date set forth in the Loan Agreement for the entry of the Final DIP Order was subsequently extended, as contemplated and permitted by the Amendment, by the Required Lenders until the earlier of (i) November 15, 2019 and (ii) the date on which any of the Debtors files any material motion with respect to the Debtors’ business operations without the prior written consent of the Required Lenders.

We currently expect that the Company’s cash flows, cash on hand and any financing that we are able to obtain through the DIP Facility will be sufficient to fund our anticipated 2019 operating needs. However, there can be no assurance that the Company’s cash flows, cash on hand and any financing we are able to obtain through the DIP Facility will be sufficient to continue to fund its operations or to allow the Company to continue as a going concern until a Chapter 11 plan of reorganization is confirmed by the Bankruptcy Court or an alternative restructuring transaction is approved by the Bankruptcy Court and consummated. In addition, if we are required under the Final DIP Order to pay the past due interest, and to continue making the semi-annual interest payments due, under the indenture for the 7.25% Senior Secured Notes during the Chapter 11 Cases, or we fail to negotiate additional extensions, deferrals, waivers or other similar arrangements to delay or otherwise reduce the activity required to maintain undeveloped leasehold positions as discussed above, then that requirement or failure to negotiate could further limit our flexibility in planning for, or reacting to, changes in our business and the oil and natural gas exploration and production industry and could have a material adverse effect on our business, financial condition or results of operations.  We have incurred significant professional fees and other costs in connection with our evaluation of strategic alternatives and preparation for the Chapter 11 Cases and expect that we will continue to incur significant professional fees and costs throughout our Chapter 11 Cases. The Company’s long-term liquidity requirements, the adequacy of its capital resources and its ability to continue as a going concern are difficult to predict at this time and ultimately cannot be determined until a Chapter 11 plan of reorganization has been confirmed, if at all, by the Bankruptcy Court. The Debtors are subject to such liquidity risks as well as the other risks and uncertainties associated with the Chapter 11 Cases as described in Part II, Item 1A in our Form 10-Q for the quarter ended June 30, 2019.

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.

Cash Flows

Our cash flows for the nine months ended September 30, 2019 and 2018 (in thousands) are as follows:

	Nine Months Ended
	September 30,
	2019		2018
Cash Flow Data:
Net cash provided by operating activities	$	99,750	$	249,526
Net cash used in investing activities	$	(110,217)	$	(453,822)
Net cash (used in) provided by financing activities	$	(7,608)	$	388,534

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Net Cash Provided by Operating Activities. Net cash provided by operating activities was $99.8 million for the nine months ended September 30, 2019 compared to cash provided by operating activities of $249.5 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 $110.2 million for the nine months ended September 30, 2019 compared to $453.8 million for the same period in 2018. Capital expenditures incurred for drilling and leasehold activities for the nine months ended September 30, 2019 totaled $61.2 million, and cash paid for capital expenditures was $114.7 million. The capital expenditures incurred are primarily associated with bringing 48 gross wells on-line during the first three quarters of 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 $5.2 million from the sale of certain other assets. During the nine months ended September 30, 2018, capital expenditures incurred for drilling and leasehold activities totaled $479.0 million and cash paid for capital expenditures was $452.3 million. The capital expenditures incurred are primarily associated with bringing 172 gross wells on-line. In addition, we received $2.8 million related to the post-closing adjustments for the Comanche Acquisition during the nine months ended September 30, 2018.

Net Cash Used in or Provided by Financing Activities. Net cash flows used in financing activities totaled $7.6 million for the nine months ended September 30, 2019 compared net cash flows provided by financing activities of $388.5 million for the same period in 2018. During the nine months ended September 30, 2019, we had borrowings of $50.0 million under our DIP Facility and $7.9 million under our Credit Facility. Additionally, we made payments of $18.3 million on the SN UnSub Credit Agreement and our other debt agreements and made payments of $37.5 million for distributions to holders of the SN UnSub Preferred Units. During the nine months ended September 30, 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 and payments on the SN UnSub Credit Agreement of $8.0 million. We also made payments of $22.4 million for distributions to holders of the SN UnSub Preferred Units and paid dividends on our Series A and B Preferred Stock of $12.0 million.

Off‑Balance Sheet Arrangements

As of September 30, 2019, we did not have any off‑balance sheet arrangements.

Commitments and Contractual Obligations

Refer to “Part I, Item 1. Notes to the Condensed Consolidated Financial Statements—Note 17. Commitments and Contingencies.”

There have been no material changes in our contractual obligations during the nine months ended September 30, 2019, other than those disclosed in “Part I, Item 1. Notes to the Condensed Consolidated Financial Statements—Note 17. Commitments and Contingencies.”

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.

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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, as applicable, 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, as of September 30, 2019 are regulated by, as applicable, the terms of the DIP Facility, the Credit Agreement, the SN UnSub Credit Agreement and SN UnSub’s organizational documents, are intended to 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. As of September 30, 2019, 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 DIP Facility or Credit Agreement are, in each case, collateralized by the assets securing the applicable facility, and, therefore, did not as of September 30, 2019 require the posting of cash collateral. As of September 30, 2019, any derivatives that are, as applicable, with (x) non-lenders (or non-lender affiliates) under the SN UnSub Credit Agreement or (y) counterparties that are not designated as secured under the DIP Facility and 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 September 30, 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 September 30, 2019, the fair value of our commodity derivative contracts was a net asset of approximately $9.1 million. A 10% increase or decrease in the oil and natural gas index prices above the September 30, 2019 prices

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would result in a decrease or increase, respectively, in the fair value of our commodity derivative contracts of $15.1 million. On a consolidated basis as of September 30, 2019, the Company has hedged approximately 580,000 Bbls of its remaining 2019 oil production and 3,362,000 MMBtu of its remaining 2019 natural gas production. As of September 30, 2019, SN UnSub’s production represents approximately 68% of the hedged oil volumes and approximately 73% of the hedged natural gas volumes. 

The filing of Bankruptcy Petitions described above constituted an event of default that generally allows counterparties to certain of the Company’s derivative contracts (excluding the counterparties to SN UnSub’s derivative contracts) to unilaterally terminate contracts to their scheduled settlement date(s) and pursue remedies, which are not subject to the automatic stay. In August 2019, as a result of the Chapter 11 Cases, one of our counterparties terminated its derivative contracts with the Company (excluding SN UnSub’s derivative contracts), resulting in a net payable of approximately $1.1 million due to the counterparty.

Following the filing of the Bankruptcy Petitions, our ability to enter into derivatives is limited. For further information, see “Part II, Item 1A. Risk Factors—We have significant exposure to fluctuations in commodity prices since only a portion of our estimated future production is covered by commodity derivatives and we may not be able to enter into commodity derivatives covering our estimated future production on favorable terms or at all” included in our Form 10-Q for the quarter ended June 30, 2019.

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 September 30, 2019, the substantial majority of our credit exposure was with investment grade counterparties. We believe exposure to losses related to credit risk at September 30, 2019 was not material, which is consistent with all periods presented.

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Interest Rate Risk

As of September 30, 2019, we had $50.0 million outstanding under the DIP Facility, $7.9 million outstanding under the Credit Agreement, $150.0 million outstanding under the SN UnSub Credit Agreement and $22.9 million outstanding under the SR Credit Agreement, all of which carry variable interest rates. The DIP Facility, with respect to the New Money DIP Loans, bears interest at a variable rate, and the Roll-Up Loans, if and when approved, will bear interest at a fixed rate. Our Senior Notes bear interest at fixed interest rates. As of September 30, 2019, a one percent change in the interest rates on the SN UnSub Credit Agreement would result in an approximately $1.5 million change in annual interest expense, and a one percent change in the interest rates on the SR Credit Agreement or DIP Facility would be insignificant.  Further, as of the Petition Date, we discontinued recording interest expense on all debt instruments classified as liabilities subject to compromise. We believe our exposure to interest-related losses at September 30, 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.

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 September 30, 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.  

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

For a description of our material pending legal proceedings as of September 30, 2019, please refer to (i) “Part I, Item 1. Notes to the Condensed Consolidated Financial Statements—Note 17. Commitments and Contingencies.” and (ii) the “Business Overview” of “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” 

The filing of the Bankruptcy Petitions automatically stayed certain actions against the Company, including actions to collect prepetition liabilities or to exercise control over the property of the Company’s bankruptcy estates. The Company sought and obtained authorization from the Bankruptcy Court to pay certain prepetition claims. The Company is paying all of its postpetition obligations in the ordinary course of business notwithstanding the filing of the Bankruptcy Petitions. If a Chapter 11 plan of reorganization is confirmed, it will provide for the treatment of claims against the Company’s bankruptcy estates, including prepetition liabilities that have not otherwise been satisfied or addressed during the Chapter 11 Cases. There can be no assurance at this time that the Debtors will be able to successfully develop, confirm and consummate a plan of reorganization or other alternative restructuring transactions

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that satisfies the conditions of the Bankruptcy Code and is confirmed by the Bankruptcy Court, or that any such plan or transactions will be implemented successfully.

Item 1A. Risk Factors

Carefully consider the risk factors under the caption “Risk Factors” under Part I, Item 1A in our 2018 Annual Report and under Part II, Item 1A in our Form 10-Q for the quarter ended June 30, 2019, 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
July 1, 2019 - July 31, 2019	1,362	$ 0.11	—	—
August 1, 2019 - August 31, 2019	10,480	$ 0.08	—	—
September 1, 2019 - September 30, 2019	1,227	$ 0.02	—	—
Total	13,069	$ 0.08	—	—

(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

See “Part I, Item 1. Notes to the Condensed Consolidated Financial Statements—Note 3.  Chapter 11 Cases— Covenant Violations” which is incorporated in this item by reference.

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. Subject to certain conditions, the Company may, at its option pay dividends in cash and, subject to certain additional conditions, common stock or any combination thereof. Dividends are cumulative. 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 the date of filing this report have been accrued. The amount and total arrearage on the Series A Preferred Stock as of the date of filing of this report is approximately $1.4 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. Subject to certain conditions, the Company may, at its option pay dividends in cash and, subject to certain additional conditions, common stock or any combination thereof. Dividends are cumulative. 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 the date of filing this report have been accrued. The amount and total arrearage on the Series B Preferred Stock as of the date of filing of this report is approximately $7.4 million.

Pursuant to the terms of the DIP Facility, the Company may not pay any dividends on, make any distribution or payment on account of, redeem or acquire any shares of Series A Preferred Stock, Series B Preferred Stock or common stock.

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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)		Senior Secured Debtor-in-Possession Term Loan Credit Agreement dated as of August 16, 2019, among Sanchez Energy Corporation, a debtor and debtor-in-possession under Chapter 11 of Bankruptcy Code, as borrower, the several lenders from time to time parities thereto, and Wilmington Savings Fund Society, FSB as administrative Agent and collateral agent.
10.2	(a)		Tolling Agreement dated August 10. 2019, by and among SN UR Holdings, LLC, SN EF UnSub Holdings, LLC, SN EF Maverick, LLC, Sanchez Energy Corporation, GSO ST Holdings Associates LLC, and GSO ST Holdings LP.
10.3	(a)		First Amendment to Senor Secured Debtor-in-Possession Term Loan Credit Agreement dated September 24, 2019, by and among Sanchez Energy Corporation, the required lenders party thereto, and Wilmington Savings Fund Society, FSB, as administrative agent and collateral agent.
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 November 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)

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