sn_Current folio

10-Q 1 sn-20190630x10q.htm 10-Q sn_Current folio_10Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10‑Q

(Mark One)

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

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 ☒

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


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

Number of shares of Registrant’s common stock, par value $0.01 per share, outstanding as of August 12, 2019: 100,075,338

Sanchez Energy Corporation

Form 10‑Q

For the Quarterly Period Ended June 30, 2019

Table of Contents


	PART I
Item 1.	Financial Statements	9
	Condensed Consolidated Balance Sheets as of June 30, 2019 (Unaudited) and December 31, 2018	9
	Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2019 and 2018 (Unaudited)	10
	Condensed Consolidated Statements of Stockholders’ Deficit for the Six Months Ended June 30, 2019 and 2018 (Unaudited)	11
	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2019 and 2018 (Unaudited)	12
	Notes to the Condensed Consolidated Financial Statements (Unaudited)	13
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	44
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	64
Item 4.	Controls and Procedures	66
	PART II
Item 1.	Legal Proceedings	66
Item 1A.	Risk Factors	67
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	71
Item 3.	Defaults Upon Senior Securities	71
Item 4.	Mine Safety Disclosures	71
Item 5.	Other Information	71
Item 6.	Exhibits	72
SIGNATURES		73

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, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Important factors that could cause our actual results to differ materially from the expectations reflected in the forward‑looking statements include, among others:

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 form of orders described herein, 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;

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;

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

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

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

SOG’s ability to attract and retain personnel and other resources to perform its obligations under the Services Agreement;

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

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

the 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;

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

the extent to which our production, revenue and cash flow from operating activities are derived from oil and natural gas assets which are concentrated in a single geographic area;

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

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

our ability to manage the financial risks where we share with more than one party the costs of drilling, equipping, completing and operating wells, including with respect to the Comanche Assets (as defined in “Item 1. 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.

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.

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.

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 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.

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

Sanchez Energy Corporation

Condensed Consolidated Balance Sheets

(in thousands, except par value and share amounts)


	June 30,		December 31,
	2019		2018
ASSETS		(Unaudited)
Current assets:
Cash and cash equivalents	$	203,469	$	197,613
Oil and natural gas receivables		79,142		87,222
Joint interest billings receivables		25,173		33,263
Accounts receivable - related entities		6,938		6,099
Fair value of derivative instruments		5,571		15,714
Other current assets		16,173		33,070
Total current assets		336,466		372,981
Oil and natural gas properties, on the basis of successful efforts accounting:
Proved oil and natural gas properties		3,845,994		3,792,431
Unproved oil and natural gas properties		306,762		328,643
Total oil and natural gas properties		4,152,756		4,121,074
Less: Accumulated depreciation, depletion, amortization and impairment		(1,891,900)		(1,761,949)
Total oil and natural gas properties, net		2,260,856		2,359,125

Other assets:
Fair value of derivative instruments		7,929		12,102
Right of use assets, net		298,334		—
Investments (includes investment in SNMP measured at fair value of $5.1 million and $3.9 million as of June 30, 2019 and December 31, 2018, respectively)		15,828		16,664
Other assets		52,915		59,088
Total assets	$	2,972,328	$	2,819,960
LIABILITIES AND STOCKHOLDERS' DEFICIT
Current liabilities:
Accounts payable	$	14,251	$	32,382
Other payables		138,570		74,628
Accrued liabilities:
Capital expenditures		18,375		61,970
Other		115,031		102,728
Fair value of derivative instruments		11,083		706
Short term debt		—		304
Short term lease liabilities		101,742		—
Other current liabilities		19,114		75,581
Total current liabilities		418,166		348,299
Long term debt, net of premium, discount and debt issuance costs		2,387,487		2,395,408
Asset retirement obligations		48,083		46,175
Fair value of derivative instruments		839		366
Long term lease liabilities		199,688		—
Other liabilities		627		21,407
Total liabilities		3,054,890		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 June 30, 2019 and December 31, 2018)		479,719		452,828
Stockholders' deficit:
Preferred stock ($0.01 par value, 15,000,000 shares authorized; 624,503 and 1,838,985 shares issued and outstanding as of June 30, 2019 and December 31, 2018, respectively, of 4.875% Convertible Perpetual Preferred Stock, Series A; 2,511,013 and 3,527,830 shares issued and outstanding as of June 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; 100,075,554 and 87,328,424 shares issued and outstanding as of June 30, 2019 and December 31, 2018, respectively)		1,013		881
Additional paid-in capital		1,371,603		1,367,427
Accumulated deficit		(1,934,928)		(1,812,884)
Total stockholders' deficit		(562,281)		(444,523)
Total liabilities and stockholders' deficit	$	2,972,328	$	2,819,960

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

Sanchez Energy Corporation

Condensed Consolidated Statements of Operations (Unaudited)

(in thousands, except per share amounts)


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2019		2018		2019		2018
REVENUES:
Oil sales	$	128,380	$	156,544	$	256,408	$	311,935
Natural gas liquid sales		29,716		56,533		70,217		105,838
Natural gas sales		31,311		41,141		74,360		82,870
Sales and marketing revenues		5,676		5,096		10,820		9,897
Total revenues		195,083		259,314		411,805		510,540
OPERATING COSTS AND EXPENSES:
Oil and natural gas production expenses		75,747		77,644		156,702		149,592
Exploration expenses		3,548		516		4,818		549
Sales and marketing expenses		4,988		5,086		9,919		9,259
Production and ad valorem taxes		11,765		14,208		24,815		27,677
Depreciation, depletion, amortization and accretion		62,575		62,323		130,056		121,571
Impairment of oil and natural gas properties		9,214		194		13,147		1,142
General and administrative expenses		48,492		29,467		68,975		51,887
Total operating costs and expenses		216,329		189,438		408,432		361,677
Operating income (loss)		(21,246)		69,876		3,373		148,863
Other income (expense):
Interest income		603		1,528		1,226		2,270
Other income (expense)		(1,787)		6,715		(959)		10,143
Gain on sale of oil and natural gas properties		—		1,528		—		1,528
Interest expense		(44,561)		(44,590)		(89,115)		(88,510)
Net gains (losses) on commodity derivatives		14,396		(70,044)		(34,026)		(114,098)
Total other expense		(31,349)		(104,863)		(122,874)		(188,667)
Loss before income taxes		(52,595)		(34,987)		(119,501)		(39,804)
Income tax expense		374		—		810		—
Net loss		(52,969)		(34,987)		(120,311)		(39,804)
Less:
Preferred stock dividends		(2,325)		(3,987)		(4,841)		(7,974)
Preferred unit dividends and distributions		(12,500)		(12,500)		(25,000)		(22,408)
Preferred unit amortization		(7,358)		(6,189)		(14,391)		(12,119)
Net loss attributable to common stockholders	$	(75,152)	$	(57,663)	$	(164,543)	$	(82,305)

Net loss per common share - basic and diluted	$	(0.78)	$	(0.71)	$	(1.75)	$	(1.01)
Weighted average number of shares used to calculate net loss attributable to common stockholders - basic and diluted		96,697		81,787		94,194		81,356

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

Sanchez Energy Corporation

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	(156)		(1)	—		—	363		2		(1)		—		—
Non-cash stock-based compensation	—		—	—		—	—		—		158		—		158
Net loss	—		—	—		—	—		—		—		(52,969)		(52,969)
BALANCE, June 30, 2019	625	$	6	2,511	$	25	100,076	$	1,013	$	1,371,603	$	(1,934,928)	$	(562,281)

	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	—		—	—		—	—		—		—		(4,817)		(4,817)
BALANCE, March 31, 2018	1,839		18	3,528		35	85,173		858	$	1,366,283		(1,834,059)		(466,865)
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	$	(1,891,722)	$	(519,877)

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

Sanchez Energy Corporation

Condensed Consolidated Statements of Cash Flows (Unaudited)

(in thousands)


	Six Months Ended
	June 30,
	2019		2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(120,311)	$	(39,804)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		130,056		121,571
Impairment of oil and natural gas properties		13,147		1,142
Gain on sale of oil and natural gas properties		—		(1,528)
Stock-based compensation expense		359		8,395
Net losses on commodity derivative contracts		34,026		114,098
Net cash settlements paid on commodity derivative contracts		(5,831)		(39,306)
(Gain) loss on other derivatives		(276)		4,526
(Gain) loss on investments		836		(8,296)
Loss on sale of inventory		143		—
Loss on other assets		847		—
Amortization of deferred gain on Western Catarina Midstream Divestiture		—		(11,860)
Amortization of debt issuance costs		6,315		9,832
Accretion of debt discount, net		831		697
Changes in operating assets and liabilities:
Accounts receivable		17,259		15,314
Accounts receivable - related entities		(839)		(1,701)
Other payables		63,214		11,832
Accrued liabilities		7,460		16,531
Other current liabilities		(32,840)		(51,203)
Other assets and liabilities, net		(3,513)		5,054
Net cash provided by operating activities		110,883		155,294

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for the development of oil and natural gas properties		(81,585)		(307,665)
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		(596)		(3,710)
Proceeds from the sale of other assets		5,210		158
Net cash used in investing activities		(76,971)		(306,958)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		—		539,865
Repayment of borrowings		(15,223)		(103,174)
Financing costs		(148)		(13,208)
Preferred dividends paid		—		(7,974)
Cash paid to tax authority for employee stock-based compensation awards		(185)		(682)
Preferred unit dividends and distributions paid		(12,500)		(9,908)
Net cash provided by (used in) financing activities		(28,056)		404,919

Increase in cash and cash equivalents		5,856		253,255
Cash and cash equivalents, beginning of period		197,613		184,434
Cash and cash equivalents, end of period	$	203,469	$	437,689

NON-CASH INVESTING AND FINANCING ACTIVITIES:
Change in asset retirement obligations	$	2	$	860
Change in accrued capital expenditures		(41,061)		8,166
ROU assets obtained in exchange for operating lease obligations		351,891		—
SUPPLEMENTAL DISCLOSURE:
Cash paid for interest	$	82,019	$	63,658

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

Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

Note 1. Organization and Business

Liquidity and Chapter 11 Cases

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 discussed, 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 uncertain and low commodity price environment. In connection with this reduction in development activity, the Company’s oil and natural gas production has declined in recent quarters. Moreover, commodity prices remain depressed. Declining production and continued low prices have adversely impacted revenues and cash flow, which has led to a reduction in forecasted liquidity. Furthermore, the Company has significant interest expense 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”). In anticipation of potential looming liquidity constraints, the Company commenced discussions with its bondholders, other stakeholders and potential third-party investors with respect to 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 in order to preserve liquidity and continue discussions with its stakeholders. Discussions with the Company’s stakeholders continued throughout the grace period. Although the Company has not 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.

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 have 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 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. The Company expects ordinary course operations to continue substantially uninterrupted during the Chapter 11 Cases. SN EF UnSub, LP (“SN UnSub”), its general partner, and certain other unrestricted subsidiaries of the Company are not included in the Chapter 11 Cases.

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. Absent an order of the Bankruptcy Court, substantially all of the Debtors’ pre-petition liabilities are subject to settlement under the Bankruptcy Code.

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 pre-petition 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 pre-petition 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 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 the 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. The Debtors have not yet made any formal determinations with respect to the assumption or rejection of any executory contracts or unexpired leases.

Following the Petition Date, the Company and the other Debtors have continued to engage with their 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. However, there can be no assurances that the Company will be able to reorganize its capital structure on terms acceptable to the Company, its creditors or other stakeholders, or at all.

Ability to Continue as a Going Concern

With the significant reduction of our capital budget, we currently expect that the Company’s cash flows, cash on hand and any financing 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 Company’s filing of the Bankruptcy Petitions described above constitutes 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. In addition, the Company’s filing of the Bankruptcy Petitions constitutes a termination event with respect to the Company’s (other than SN UnSub’s) hedge agreements, which permits the counterparties to such hedge agreements to terminate the outstanding hedges, which termination events are not stayed under the Bankruptcy Cases.

Debtor-in-Possession Credit Agreement

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 (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, 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 contains the following terms, subject to the Final DIP Order (as defined below):

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 would be available on an interim basis upon entry of the Bankruptcy Court’s interim order (the “Interim DIP Order”); and (ii) a refinancing term loan in the amount of $175 million (the “Roll-Up Loans” and, together with the New Money DIP Loans, the “DIP Loans”) offered pro rata to all Secured Noteholders who are New Money Lenders prior to the entry of the Interim DIP Order;

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

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; (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 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);

disclosure statement 155 days after the Petition Date; (v) entry of the Bankruptcy Court’s order confirming the Chapter 11 plan of reorganization 225 days after the Petition Date; and (vi) the effective date of the Chapter 11 plan of reorganization 255 days after the Petition Date;

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.

The DIP Facility has been approved by the Bankruptcy Court on an interim basis subject to submitting an appropriate form of order. We anticipate closing the DIP Facility and borrowing the initial $50 million of the New Money DIP Loans thereunder promptly following the Bankruptcy Court’s entry of the Interim DIP Order.

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 and, together with the 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 (“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 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 the Company, SN Maverick or SN UR Holdings, to the extent such party has commenced a Proceeding (the earliest commencement date of a Proceedings by the Company, 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; 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 Holdings commences a Proceeding at any time, the parties have agreed that for all purposes the commencement by 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.

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 June 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.

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.

In February 2016, the FASB issued ASU 2016-02 “Leases (ASC 842),” effective for annual and interim periods for public companies beginning after December 15, 2018, with a modified retrospective approach to be used for implementation. The standard updates the previous lease guidance by requiring the recognition of a ROU asset and lease liability on the statement of financial position for all leases with lease terms of more than 12 months. The lease liability represents the discounted obligation to make future minimum lease payments and the corresponding ROU asset represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Recognition, measurement and presentation of expenses and cash flows arising from a lease will depend on classification as an operating or a finance lease. The Company adopted this standard effective January 1, 2019. We elected the package of practical expedients permitting us to not reassess under the new standard our prior conclusions regarding lease identification, lease classification and initial direct costs, the practical expedient to not separate lease and non– lease components for all of our existing lessee arrangements, and to elect an accounting policy to not apply the recognition requirements of Topic 842 to our short term leases. We did not elect the practical expedient for use of hindsight in determining the lease term and assessing impairment of our ROU assets. Adoption of Topic 842 resulted in the recognition of ROU assets and lease liabilities for operating leases on the balance sheet and the derecognition of the deferred gain previously recorded on a sale-leaseback transaction as a cumulative effect adjustment to retained earnings on January 1, 2019. Amounts recognized at January 1, 2019 for operating leases were as follows (in thousands):


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

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

Note 3. Leases

We determine if an arrangement is a lease at inception. To the extent that we determine an arrangement represents a lease, we classify that lease as an operating lease or a finance lease. We currently do not have any finance leases. We capitalize our operating leases on our consolidated balance sheet through a ROU asset and a corresponding lease liability. ROU assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. Short term leases that have an initial term of one year or less are not capitalized but are disclosed below. Short term lease costs exclude expenses related to leases with a lease term of one month or less.

Our operating leases are reflected as operating lease ROU assets, short term operating lease liabilities and long term operating lease liabilities on our consolidated balance sheet. Operating lease ROU assets and liabilities are

recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term. In addition to the present value of lease payments, the operating lease ROU asset also includes any lease payments made to the lessor prior to lease commencement less any lease incentives and initial direct costs incurred. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term.

Nature of Leases

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

Midstream Gathering and Processing Facilities

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

Field Equipment and Vehicles

We enter into daywork contracts for drilling rigs with third parties to support our drilling activities. Our drilling rig arrangements are typically structured with a term that is in effect until drilling operations are completed on a specified well or well pad in accordance with the development plan. Upon mutual agreement with the contractor, we typically have the option to extend the contract term for additional wells or well pads by providing thirty days’ notice prior to the end of the original contract term. We have concluded that our drilling rig arrangements represent operating leases with lease terms of five to 12 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 are capitalized as part of oil and natural gas properties on the balance sheet as incurred.

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

We rent our vehicle fleet for our drilling and operations personnel. Our vehicle agreements have non-cancellable lease terms of 18 months. We have concluded that our vehicle agreements represent operating leases with a

lease term that equals the primary non-cancellable contract term. Generally upon completion of the primary term, both parties have substantive rights to terminate the lease.

Significant Judgments

Discount Rate

Our leases typically do not provide an implicit rate. Accordingly, we are required to use our estimated incremental borrowing rate in determining the present value of lease payments based on the information available at commencement date. Our estimated incremental borrowing rate reflects a reasonable projection of the interest that we would expect to pay to borrow, on a collateralized basis, over a similar term, an amount equal to the lease payments in a similar economic environment. The Company gives consideration to various factors, including the terms of the Company’s outstanding debt instruments, publicly available data for instruments with similar characteristics and other information, together with internally generated estimates, assumptions and judgment to determine the Company’s incremental borrowing rate 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 six months ended June 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		Six Months Ended
	June 30, 2019		June 30, 2019
Operating lease expense	$	24,497	$	49,928
Short term and variable lease expense		7,538		15,969
Total lease expense	$	32,035	$	65,897

Operating lease cost(1)	$	1,641	$	3,057
Short term and variable lease cost(1)		1,017		1,061
Total lease cost	$	2,658	$	4,118

(1)

Represents capital expenditures related to the use of drilling rigs for the three and six months ended June 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):


	Six Months Ended
	June 30, 2019
Operating cash flows from operating leases	$	65,897
Investing cash flows from operating leases		4,118
ROU assets obtained in exchange for operating lease obligations		351,891
Amortization of ROU assets		(53,557)

Weighted average remaining lease term (years)		3.4
Weighted average discount rate		10%

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


July 1, 2019 through December 31, 2019	$	64,801
2020		113,613
2021		80,474
2022		60,249
2023		26,847
Thereafter		9,797
Total lease payments		355,781
Less: Imputed interest		54,351
Total lease liabilities	$	301,430

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


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

Note 4. Revenue Recognition

Revenue from Contracts with Customers

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

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

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

Disaggregation of Revenue

We recognized revenue of $195.1 million and $259.3 million for the three months ended June 30, 2019 and 2018, respectively, and revenue of $411.8 million and $510.5 million for the six months ended June 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.

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

appropriately depicts how the nature, amount, timing and uncertainty of revenue and cash flows are affected by economic factors.

Oil, Natural Gas and NGL Revenues

We recognize revenue from the sale of oil, natural gas and NGLs in the period that the performance obligations are satisfied. Our performance obligations are primarily comprised of the delivery of oil, natural gas or NGLs at a delivery point. Each barrel of oil, 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.

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

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

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

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

Sales and Marketing Revenue

Beginning in 2018, we entered into commodity purchase transactions with certain third parties and then subsequently sold the purchased commodity as separate revenue streams. We believe an opportunity exists, from time to time, to participate in additional economic benefits and operational efficiencies in support of our upstream activities by purchasing and reselling production from others, to a limited extent, in order to utilize existing firm transportation arrangements. We retain control of the purchased hydrocarbons prior to delivery to the purchaser. The Company has concluded that we are the principal in these arrangements and therefore we recognize revenue on a gross basis as Sales and Marketing Revenues, 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 June 30, 2019 and December 31, 2018, our receivables from contracts with customers were $79.1 million and $87.2 million, respectively.

Note 5. Cash and Cash Equivalents

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


	June 30,		December 31,
	2019		2018
Cash at banks	$	37,564	$	66,426
Money market funds		165,905		131,187
Total cash and cash equivalents	$	203,469	$	197,613

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

Note 6. Oil and Natural Gas Properties

Impairment of Oil and Natural Gas Properties —We recorded a proved property impairment of $4.3 million during the three and six months ended June 30, 2019. We did not record a proved property impairment during the three and six months ended June 30, 2018. Changes in production rates, levels of reserves, future development costs, and other factors will impact our actual impairment analyses in future periods.

Unproved Properties—We recorded impairment to our unproved oil and natural gas properties of $4.9 million and $8.8 million for the three and six months ended June 30, 2019, respectively, and $0.2 million and $1.1 million for the three and six months ended June 30, 2018, respectively, due to acreage expirations from changes in the development plan.

Note 7. Debt

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


			June 30,		December 31,
	Interest Rate	Maturity Date	2019		2018
Short Term Debt:
SR Credit Agreement(1)(2)	Variable	-	$	—	$	304
Total short term debt			$	—	$	304

Long Term Debt:
7.75% Notes	7.75%	June 15, 2021	$	600,000	$	600,000
SN UnSub Credit Agreement(1)	Variable	March 1, 2022		153,000		167,500
4.59% Non-Recourse Subsidiary Term Loan(1)	4.59%	August 31, 2022		3,630		3,803
SR Credit Agreement(1)	Variable	October 31, 2022		22,941		23,187
6.125% Notes	6.125%	January 15, 2023		1,150,000		1,150,000
Credit Agreement(3)	Variable	February 14, 2023(4)		—		—
7.25% Senior Secured Notes	7.25%	February 15, 2023(5)		500,000		500,000
				2,429,571		2,444,490
Unamortized discount on Additional 7.75% Notes				(1,770)		(2,222)
Unamortized premium on Additional 6.125% Notes				955		1,090
Unamortized discount on 7.25% Senior Secured Notes				(3,727)		(4,241)
Unamortized debt issuance costs				(37,542)		(43,709)
Total long term debt			$	2,387,487	$	2,395,408

(1)

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

(2)

Incurred interest at a weighted-average rate of approximately 6.0% and 6.8% for the six months ended June 30, 2019 and the year ended December 31, 2018, respectively.

(3)

A standby letter of credit in the amount of approximately $17.1 million was issued under the Credit Agreement on January 10, 2019 and incurred fees at a rate of 3.25% for the six months ended June 30, 2019. The letter of credit remains outstanding and is undrawn as of June 30, 2019.

(4)

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 June 30, 2019, mature on March 15, 2021.

(5)

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.

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2019		2018		2019		2018
Interest on SR Credit Agreement	$	(350)	$	(480)	$	(575)	$	(828)
Interest on Senior Notes		(38,297)		(38,297)		(76,594)		(71,861)
Interest and commitment fees on SN UnSub Credit Agreement		(2,147)		(2,202)		(4,431)		(4,503)
Interest on Non-Recourse Subsidiary Term Loan		(43)		(47)		(86)		(94)
Interest, commitment fees and letter of credit fees on Credit Agreement		(149)		(30)		(283)		(695)
Amortization of debt issuance costs		(3,160)		(3,118)		(6,315)		(9,832)
Amortization of discounts and premium on Senior Notes		(415)		(416)		(831)		(697)
Total interest expense	$	(44,561)	$	(44,590)	$	(89,115)	$	(88,510)

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 provides for a 30-day grace period, which expired on August 14, 2019, to make the scheduled interest payment before such non-payment constitutes 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 Company filed its Chapter 11 Cases prior to expiration of the grace period.

Credit Facilities

Third Amended and Restated Credit Agreement

On February 14, 2018, the Company entered into a revolving credit facility, providing for a $25 million first-out senior secured working capital and letter of credit facility (the “Credit Agreement”), which amended and restated the Company’s previous credit facility in its entirety.

As of June 30, 2019, there were no outstanding borrowings under the Credit Agreement. However, on January 10, 2019, a standby letter of credit was issued on our behalf by the lender under the Credit Agreement in the amount of approximately $17.1 million. This letter of credit, as of June 30, 2019, remains outstanding and is undrawn. On July 10, 2019, the Company borrowed the remaining $7.9 million available under the Credit Agreement. Subject to entry of the Final DIP Order, a portion of 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 an approximate $17.1 million letter of credit issued under our Credit Agreement.

As of June 30, 2019, the Company was in compliance with the covenants of the Credit Agreement. The filing of the Bankruptcy Petitions also constitutes 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 all 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 June 30, 2019, there were approximately $153.0 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 may be decreased at the next redetermination or at a future redetermination, and 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 June 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 June 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.

The filing of the Bankruptcy Petitions constitutes 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 constitutes 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 constitutes 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 June 30, 2019, are governed by the terms of our Credit Agreement, the SN UnSub Credit Agreement and SN UnSub’s organizational documents, as applicable, 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 June 30, 2019, any derivatives that are with (a) lenders, or affiliates of lenders, to the SN UnSub Credit Agreement, or (b) counterparties designated as secured with and under the Credit Agreement are, in each case, collateralized by the assets securing the applicable facility, and, therefore, do not, as of June 30, 2019, require the posting of cash collateral. As of June 30, 2019, any derivatives that are with (x) non-lender counterparties, as designated under the SN UnSub Credit Agreement, or (y) counterparties that are not designated as secured under the Credit Agreement are, in each case, unsecured and do not require the posting of cash or other collateral. As of June 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 Chapter 11 Cases, our ability to enter into derivatives is limited.

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


	July 1 - December 31, 2019		2020		2021
Oil positions:
Fixed price swaps (NYMEX WTI):
Hedged volume (Bbls)		1,546,000		1,055,560		416,200
Average price ($/Bbl)	$	51.87	$	55.36	$	55.68

Natural gas positions:
Fixed price swaps (NYMEX Henry Hub):
Hedged volume (MMBtu)		8,654,000		6,893,150		2,805,000
Average price ($/MMBtu)	$	2.91	$	2.67	$	2.67

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


	Six Months Ended		Year Ended
	June 30,		December 31,
	2019		2018
Fair value of commodity derivatives, beginning of period	$	21,194	$	(54,255)
Net losses on oil derivatives		(39,091)		(9,878)
Net gains (losses) on natural gas derivatives		5,064		(17,897)
Net settlements paid (received) on commodity derivative contracts:
Oil		8,619		100,120
Natural gas		(34)		3,104
Fair value of commodity derivatives, end of period	$	(4,248)	$	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 June 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 $6.1 million for the three months ended June 30, 2018. The Company did not record any gains or losses for the three months ended June 30, 2019 as the contracts had expired or terminated. For the six months ended June 30, 2019 and 2018, the Company recorded a gain of approximately $0.3 million and a loss of $6.1 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. The Company recorded immaterial settlement gains for the three months ended June 30, 2019. For the six months ended June 30, 2019, the Company recorded an immaterial net gain due to settlement gains, which were partially offset by mark-to-market losses. For the three and six months ended June 30, 2018, the Company recorded approximate net gains of $1.3 million and $1.5 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 six months ended June 30, 2019 and the year ended December 31, 2018, respectively (in thousands):


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


	June 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	$	5,571	$	—	$	5,571
Long term asset		7,960		(31)		7,929
Total asset	$	13,531	$	(31)	$	13,500
Offsetting Derivative Liabilities:
Current liability	$	11,083	$	—	$	11,083
Long term liability		870		(31)		839
Total liability	$	11,953	$	(31)	$	11,922


	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

Other than SN UnSub’s derivative contracts, the Company’s derivative contracts may be terminated unilaterally by the counterparty as a result of the Bankruptcy Petitions.

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 June 30, 2019, this ownership represents approximately 6.0% 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 losses related to the investment in Lonestar for the three and six months ended June 30, 2019 of approximately $2.6 million and $2.0 million, respectively, and the Company recorded gains related to the investment in Lonestar for the three and six months ended June 30, 2018 of approximately $6.7 million and $6.2 million, respectively. Any gains or losses related to the investment in Lonestar are recorded as a component of other income (expense) in the condensed consolidated statement of operations.

A subsidiary of the Company owns 100 Class A Units of Gavilan Resources Holdco, LLC (“GRHL”). Tranches representing 20% of the Class A Units vest on each of the first five anniversaries from March 1, 2017. The Class A Units are entitled to distributions from Available Cash, as defined in and subject to the provisions of the GRHL amended and restated limited liability company agreement. The Company accounts for the investment in GRHL as a cost method investment. As of June 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 June 30, 2019.

A subsidiary of the Company owns 2,272,727 common units of SNMP. As of June 30, 2019, this ownership represents approximately 11.8% 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 six months ended June 30, 2019, the Company recorded gains of $0.2 million and $1.2 million, respectively, related to the investment in SNMP. In addition, for the three and six months ended June 30, 2019, the Company recorded dividend income of approximately $0.3 million and $0.7 million, respectively, from quarterly distributions on the SNMP common units. For the three and six months ended June 30, 2018, the Company recorded gains related to the investment in SNMP of approximately $3.3 million and $1.6 million, respectively. Further, for the three and six months ended June 30, 2018, we recorded dividend income of approximately $1.0 million and $2.0 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 June 30, 2019 and December 31, 2018 (in thousands):


	As of June 30, 2019
	Active Market
	for Identical		Observable		Unobservable		Total
	Assets		Inputs		Inputs		Carrying
	(Level 1)		(Level 2)		(Level 3)		Value
Cash equivalents:
Cash equivalents	$	165,905	$	—	$	—	$	165,905
Equity investments:
Investment in SNMP		5,114		—		—		5,114
Investment in Lonestar		3,435		—		—		3,435
Oil derivative instruments:
Swaps		—		(9,865)		—		(9,865)
Gas derivative instruments:
Swaps		—		5,617		—		5,617
Other:
Earnout derivative asset		—		—		5,826		5,826
Total	$	174,454	$	(4,248)	$	5,826	$	176,032


	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
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

June 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 June 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 June 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.

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):


	Six Months Ended		Year Ended
	June 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 and June 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 six months ended June 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 six months ended June 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 six months ended June 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 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 June 30, 2019, the estimated fair values of the 7.75% Notes and 6.125% Notes were $39.3 million and $46.0 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 June 30, 2019, the estimated fair value of the 7.25% Senior Secured Notes was $375.0 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.

Note 11. Asset Retirement Obligations

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


	Six Months Ended		Year Ended
	June 30,		December 31,
	2019		2018
Abandonment liability, beginning of period	$	46,175	$	36,098
Liabilities incurred during period		149		1,965
Divestitures		(147)		(158)
Revisions		—		5,077
Accretion expense		1,906		3,193
Abandonment liability, end of period	$	48,083	$	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 June 30, 2019 and 2018 were $17.3 million and $15.6 million, respectively, and expenses allocated to the Company for G&A expenses and oil and natural gas production expenses for the six months ended June 30, 2019 and 2018 were $35.2 million and $33.5 million, respectively.

As of June 30, 2019 and December 31, 2018, the Company had a net receivable from SOG and its affiliates of $6.9 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 June 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 June 30, 2019 and December 31, 2018, the Company had a net payable to SNMP of approximately $4.6 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 June 30, 2019 and December 31, 2018 (in thousands):


	June 30,		December 31,
	2019		2018
Capital expenditures	$	18,375	$	61,970
Other:
General and administrative expenses		20,843		19,460
Production taxes		3,324		5,157
Ad valorem taxes		9,364		445
Lease operating expenses		28,467		24,138
Interest payable		47,796		47,866
Other accrued liabilities		5,237		5,662
Total accrued liabilities	$	133,406	$	164,698

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


	June 30,		December 31,
	2019		2018
Revenue payable	$	129,790	$	71,296
Production tax payable		4,385		3,443
Other		4,395		(111)
Total other payables	$	138,570	$	74,628

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


	June 30,		December 31,
	2019		2018
Operated prepayment liability	$	19,585	$	51,844
Deferred gain on Western Catarina Midstream Divestiture - short term		—		23,720
Phantom compensation payable - short term		(471)		17
Total other current liabilities	$	19,114	$	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 June 30, 2019, based on the initial conversion price, approximately 1,451,968 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. The Company may, at its option, pay dividends in cash and, subject to certain conditions, common stock or any combination thereof. Dividends are cumulative and, beginning with the three month period ended March 31, 2019, the Board determined to suspend the dividend on our Series A Preferred Stock. Dividends accumulated through June 30, 2019 have been accrued.

Series B Preferred Stock

Each share of Series B Preferred Stock is convertible at any time at the option of the holder thereof at an initial conversion rate of 2.337 shares of common stock per share of Series B Preferred Stock (which is equal to an initial conversion price of $21.40 per share of common stock) and is subject to specified adjustments. As of June 30, 2019,

based on the initial conversion price, approximately 5,868,235 shares of common stock would be issuable upon conversion of all of the outstanding shares of the Series B Preferred Stock.

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

Preferred Stock Conversions

On February 12, 2019, 72,500 shares of Series A Preferred Stock converted into 168,563 shares of our common stock and 245,832 shares of Series B Preferred Stock converted into 574,510 shares of our common stock at the election of the holders thereof. From March 6 to March 8, 2019, 563,832 shares of Series A Preferred Stock converted into 1,310,914 shares of our common stock and 770,986 shares of Series B Preferred Stock converted into 1,801,798 shares of our common stock, at the election of the holders thereof. On March 26, 2019, 422,222 shares of Series A Preferred Stock converted into 981,667 shares of our common stock, at the election of the holders thereof. 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.

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, L.P., completed the acquisition of approximately 318,000 gross (155,000 net) acres comprised of 252,000 gross (122,000 net) Eagle Ford Shale acres and 66,000 gross (33,000 net) acres of deep rights only, which includes the Pearsall Shale, representing an approximate 49% average working interest therein (the “Comanche Assets,” 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 June 30, 2019 and December 31, 2018, respectively, (in thousands):


	Six Months Ended		Year Ended
	June 30,		December 31,
	2019		2018
Mezzanine equity, beginning balance	$	452,828	$	427,512
Accretion of discount		14,391		25,316
Dividends accrued		25,000		50,000
Dividends prepaid (1)		—		(2,592)
Dividends/distributions paid (1)		(12,500)		(47,408)
Mezzanine equity, ending balance	$	479,719	$	452,828

(1)

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

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2019		2018		2019		2018
Net loss	$	(52,969)	$	(34,987)	$	(120,311)	$	(39,804)
Less:
Preferred stock dividends		(2,325)		(3,987)		(4,841)		(7,974)
Preferred unit dividends and distributions		(12,500)		(12,500)		(25,000)		(22,408)
Preferred unit amortization		(7,358)		(6,189)		(14,391)		(12,119)
Net loss attributable to common stockholders	$	(75,152)	$	(57,663)	$	(164,543)	$	(82,305)
Weighted average number of unrestricted outstanding common shares used to calculate basic and dilutive net loss per share(1)(2)		96,697		81,787		94,194		81,356
Net loss per common share - basic and diluted	$	(0.78)	$	(0.71)	$	(1.75)	$	(1.01)

(1)

The three and six months ended June 30, 2018 exclude 2,484,202 and 756,417 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 six months ended June 30, 2019 exclude 852,132 and 1,578,418 shares, respectively, of weighted average restricted stock and 7,678,756 and 9,495,186 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 six months ended June 30, 2019, the Company did not issue any shares of restricted common stock pursuant to the LTIP.

During the three months ended June 30, 2019, the Company did not issue any shares of phantom stock pursuant to the LTIP. During the six months ended June 30, 2019, the Company issued an immaterial number of shares of phantom stock pursuant to the LTIP to certain employees of SOG (including the Company’s officers), with whom the Company has a services agreement. These shares of phantom stock vest in equal annual amounts over a three year period.

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

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

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2019		2018		2019		2018
Restricted stock awards, directors	$	23	$	330	$	42	$	627
Restricted stock awards, non-employees		151		3,023		226		2,819
Performance awards		(16)		1,298		32		830
Phantom stock awards		(72)		5,017		61		4,119
Total stock-based compensation expense	$	86	$	9,668	$	361	$	8,395

Based on the $0.10 per share closing price of the Company’s common stock on June 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 1.9 years.

Based on the $0.10 per share closing price of the Company’s common stock on June 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 1.8 years.

Based on the $0.10 per share closing price of the Company’s common stock on June 30, 2019, there was approximately $0.2 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 1.9 years.

Based on the estimated per share price of the common stock underlying the Performance Awards on June 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 2.5 years.

Based on the estimated per share price of the common stock underlying the PBPS Awards on June 30, 2019, there was approximately $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 1.3 years.

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


	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2019	2018	2019	2018
Non-vested common stock, beginning of period	3,948	3,684	5,024	4,897
Granted	—	2,676	-	3,156
Vested	(1,165)	(542)	(2,113)	(2,159)
Forfeited	(69)	(51)	(197)	(127)
Non-vested common stock, end of period	2,714	5,767	2,714	5,767

As of June 30, 2019, approximately 8.3 million shares remained available for future issuance to participants under the LTIP.

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


	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2019	2018	2019	2018
Non-vested phantom stock and PAPS, beginning of period	3,906	3,949	5,125	3,589
Granted	-	2,474	7	3,652
Vested	(923)	(435)	(1,814)	(1,150)
Forfeited	(126)	(100)	(461)	(203)
Non-vested phantom stock and PAPS, end of period	2,857	5,888	2,857	5,888

Note 16. Income Taxes

The Company used a year-to-date effective tax rate method for recording income taxes for the six month periods ended June 30, 2019 and 2018. This method is based on our determination at June 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 June 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 six months ended June 30, 2019 and 2018 was (0.7%) and 0.0%, 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 June 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 June 30, 2019, the Company had no material uncertain tax positions.

Note 17. Commitments and Contingencies

Shareholder Derivative Litigation

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

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

Catarina Drilling Commitment

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

Palmetto Drilling Commitment

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 six gross (three 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. Marathon Oil EF LLC (“Marathon”) is the operator and other lessee of our Palmetto acreage position. We believe Marathon currently intends to drill at least the minimum number of wells required to satisfy the drilling commitments and to comply with applicable lease requirements necessary to maintain our Palmetto acreage position.

Volume Commitments

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

and natural gas processing agreements that obligate us to deliver a specified volume of production over a defined time horizon. If not fulfilled, the Company is subject to deficiency payments to our midstream counterparties. As of June 30, 2019, the Company had approximately $430.8 million in future commitments related to oil and natural gas gathering and transportation agreements ($165.7 million for 2019 through 2021, $128.5 million from 2022 through 2024, and $136.6 million under commitments expiring after December 31, 2024, in the aggregate) and approximately $43.8 million in future commitments related to natural gas processing agreements ($43.1 million for 2019 through 2021, 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 six months ended June 30, 2019, the Company incurred expenses related to deficiency fees of approximately $2.6 million and $3.9 million, respectively, and for the three and six months ended June 30, 2018, the Company incurred expenses related to deficiency fees of approximately $1.7 million and $2.3 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 have additional expenses in 2019 related to our volume commitments in connection with our reduced capital activity during the year.

Other Commitments and Contingencies

The commencement of the Chapter 11 Cases automatically stayed certain actions against the Company, including actions to collect pre-petition liabilities or to exercise control over the property of the Company’s bankruptcy estates, and the Company intends to seek authority to pay all general claims in the ordinary course of business notwithstanding the commencement of the Chapter 11 Cases. In addition, the commencement of the Chapter 11 Cases may allow the Company to assume, assign or reject certain commitments as executory contracts. See Note 1, “Organization and Business” 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 June 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 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.

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


	June 30, 2019
Assets	Parent Company		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Total current assets	$	339,343	$	192,806	$	116,483	$	(312,166)	$	336,466
Total oil and natural gas properties, net		121,441		1,410,747		728,668		—		2,260,856
Investment in subsidiaries		1,478,452		—		(7,278)		(1,471,174)		—
Other assets		61,615		273,470		39,921		—		375,006
Total Assets	$	2,000,851	$	1,877,023	$	877,794	$	(1,783,340)	$	2,972,328

Liabilities and Stockholders' Equity
Current liabilities	$	181,467	$	349,618	$	199,247	$	(312,166)	$	418,166
Long term liabilities		2,247,482		204,946		184,296		—		2,636,724
Mezzanine equity		—		—		479,719		—		479,719
Total stockholders' equity (deficit)		(428,098)		1,322,459		14,532		(1,471,174)		(562,281)
Total Liabilities and Stockholders' Equity (Deficit)	$	2,000,851	$	1,877,023	$	877,794	$	(1,783,340)	$	2,972,328


	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 six months ended June 30, 2019 and 2018 is presented below (in thousands):


	Three Months Ended June 30, 2019
	Parent Company		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Total revenues	$	—	$	133,196	$	61,887	$	—	$	195,083
Total operating costs and expenses		(38,952)		(120,680)		(56,835)		138		(216,329)
Other income		(36,592)		588		4,793		(138)		(31,349)
Income (loss) before income taxes		(75,544)		13,104		9,845		—		(52,595)

Income tax expense		374		—		—		—		374
Equity in income (loss) of subsidiaries		22,949		—		—		(22,949)		—
Net income (loss)	$	(52,969)	$	13,104	$	9,845	$	(22,949)	$	(52,969)


	Three Months Ended June 30, 2018
	Parent Company		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Total revenues	$	—	$	178,842	$	80,472	$	—	$	259,314
Total operating costs and expenses		(24,721)		(125,167)		(39,684)		134		(189,438)
Other income		(81,192)		(5,766)		(17,771)		(134)		(104,863)
Income (loss) before income taxes		(105,913)		47,909		23,017		—		(34,987)

Equity in income (loss) of subsidiaries		70,926		—		—		(70,926)		—
Net income (loss)	$	(34,987)	$	47,909	$	23,017	$	(70,926)	$	(34,987)


	Six Months Ended June 30, 2019
	Parent Company		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Total revenues	$	—	$	284,724	$	127,081	$	—	$	411,805
Total operating costs and expenses		(54,661)		(241,040)		(113,002)		271		(408,432)
Other income (expense)		(96,415)		656		(26,844)		(271)		(122,874)
Income (loss) before income taxes		(151,076)		44,340		(12,765)		—		(119,501)

Income tax expense		810		—		—		—		810
Equity in income (loss) of subsidiaries		31,575		—		—		(31,575)		—
Net income (loss)	$	(120,311)	$	44,340	$	(12,765)	$	(31,575)	$	(120,311)


	Six Months Ended June 30, 2018
	Parent Company		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Total revenues	$	—	$	346,328	$	164,212	$	—	$	510,540
Total operating costs and expenses		(40,252)		(207,833)		(113,862)		270		(361,677)
Other income (expense)		(147,959)		(5,263)		(35,175)		(270)		(188,667)
Income (loss) before income taxes		(188,211)		133,232		15,175		—		(39,804)

Equity in income (loss) of subsidiaries		148,407		—		—		(148,407)		—
Net income (loss)	$	(39,804)	$	133,232	$	15,175	$	(148,407)	$	(39,804)

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


	Six Months Ended June 30, 2019
	Parent Company		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Net cash provided by (used in) operating activities	$	(138,225)	$	243,224	$	5,884	$	—	$	110,883
Net cash provided by (used in) investing activities		83,450		(58,282)		(24,325)		(77,814)		(76,971)
Net cash provided by (used in) financing activities		(237)		(136,068)		30,435		77,814		(28,056)
Net increase (decrease) in cash and cash equivalents		(55,012)		48,874		11,994		—		5,856
Cash and cash equivalents, beginning of period		68,762		58,429		70,422		—		197,613
Cash and cash equivalents, end of period	$	13,750	$	107,303	$	82,416	$	—	$	203,469


	Six Months Ended June 30, 2018
	Parent Company		Combined Guarantor Subsidiaries		Combined Non-Guarantor Subsidiaries		Eliminations		Consolidated
Net cash provided by (used in) operating activities	$	(107,425)	$	206,878	$	55,841	$	—	$	155,294
Net cash provided by (used in) investing activities		(49,514)		(251,777)		(53,336)		47,669		(306,958)
Net cash provided by (used in) financing activities		423,387		15,853		13,348		(47,669)		404,919
Net increase (decrease) in cash and cash equivalents		266,448		(29,046)		15,853		—		253,255
Cash and cash equivalents, beginning of period		86,937		29,046		68,451		—		184,434
Cash and cash equivalents, end of period	$	353,385	$	—	$	84,304	$	—	$	437,689

Note 19. Variable Interest Entities

The Company’s investment in GRHL represents a VIE that could expose the Company to losses limited to the estimated fair value of the investment. The carrying amounts of the investment in GRHL, and the Company’s maximum exposure to loss as of June 30, 2019 and December 31, 2018, was approximately $7.3 million. The Company did not record any earnings from its ownership of the Class A Units for the period from January 1, 2018 through June 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 June 30, 2019 and December 31, 2018, was approximately $5.1 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 June 30, 2019 and December 31, 2018 (in thousands):


	June 30,		December 31,
	2019		2018
Beginning balance	$	11,189	$	32,507
Gain (loss) from change in fair value of investment in SNMP		1,205		(21,318)
Maximum exposure to loss	$	12,394	$	11,189

Note 20. Subsequent Events

Interest Payment Deferral

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.

Credit Agreement

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 June 30, 2019, remains outstanding and is undrawn. On July 10, 2019, the Company borrowed the remaining $7.9 million available under the Credit Agreement. Subject to entry of the Final DIP Order, a portion of 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 an approximate $17.1 million letter of credit issued under our Credit Agreement.

Preferred Stock Conversions

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.

Voluntary Reorganization Under Chapter 11

See “—Note 1. Liquidity and Chapter 11 Cases—Voluntary Reorganization Under Chapter 11.”

Debtor-in-Possession Credit Agreement

See “—Note 1. Liquidity and Chapter 11 Cases—Debtor-in-Possession Credit Agreement.”

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 hold other producing properties and undeveloped acreage, including in the Tuscaloosa Marine Shale (“TMS”) in Mississippi and Louisiana which offers potential future development opportunities. As of June 30, 2019, we had assembled approximately 462,000 gross (260,000 net) leasehold acres in the Eagle Ford Shale, where we plan to invest the majority of our 2019 capital budget. We continually evaluate opportunities to manage our overall portfolio, which may include the acquisition of additional properties in the Eagle Ford Shale or other producing areas and, from time to time, the divestiture of non-core assets. Our successful acquisition of such properties will depend on the circumstances and the financing alternatives available to us at the time we consider such opportunities. However, at this time we are primarily focused on lowering cash costs across our business and reducing our financial leverage, with an objective of maximizing our liquidity position and improving our balance sheet. We are also continuing to pursue during the Chapter 11 Cases (as defined below) strategic alternatives to better align our capital structure with the current low commodity price environment. The market for acquisition and divestiture of oil and natural gas assets slowed significantly during the first two quarters of 2019, and this reduced transaction activity level, combined with continued challenging conditions in the credit and capital markets, among other reasons, made it difficult for us to complete divestitures of non-core assets or pursue other strategic alternatives. In anticipation of potential looming liquidity constraints, the Company commenced discussions with its bondholders, other stakeholders and potential third-party investors with respect to 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 in order to preserve liquidity and continue discussions with its stakeholders. Discussions with the stakeholders continued throughout the grace period. Although the Company has not 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.

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 have 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 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. 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.

permitted by the Bankruptcy Code. Absent an order of the Bankruptcy Court, substantially all of the Debtors’ pre-petition liabilities are subject to settlement under the Bankruptcy Code.

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. “Risk Factors.” As a result of these risks and uncertainties, the number 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.

In particular, 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 pre-petition 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 pre-petition 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 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 the 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. The Debtors have not yet made any formal determinations with respect to the assumption or rejection of any executory contracts or unexpired leases.

Ability to Continue as a Going Concern

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.

The Company believes the Chapter 11 Cases provide the most expeditious manner in which to effect a capital structure solution. There can be no assurances that the Company will be able to reorganize its capital structure on terms acceptable to the Company, its creditors or other stakeholders, or at all.

Covenant Violations

The Company’s filing of the Bankruptcy Petitions described above constitutes 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. In addition, the Company’s filing of the Bankruptcy Petitions constitutes a termination event with respect to the Company’s (other than SN UnSub’s) hedge agreements, which permits the counterparties to such hedge agreements to terminate the outstanding hedges, which termination events are not stayed under the Bankruptcy Cases.

Debtor-in-Possession Credit Agreement

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 the final approval of the Bankruptcy Court, refinancing all amounts existing under the Company’s existing Credit Agreement;

the Debtors’ Chapter 11 Cases are subject to certain milestones, including the following deadlines: (i) entry of the Interim DIP Order 5 days after the Petition Date; (ii) entry of the Bankruptcy Court’s final order approving the DIP Facility (the “Final DIP Order”) 40 days after the Petition Date; (iii) filing of a Chapter 11 plan of reorganization providing for payment in full in cash of the DIP Loans and the related disclosure statement 110 days after the Petition Date; (iv) entry of the Bankruptcy Court’s order approving the disclosure statement 155 days after the Petition Date; (v) entry of the Bankruptcy Court’s order confirming the Chapter 11 plan of reorganization 225 days after the Petition Date; and (vi) the effective date of the Chapter 11 plan of reorganization 255 days after the Petition Date;

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

Commodity Derivatives

Other than SN UnSub’s derivative contracts, the Company’s derivative contracts may be terminated unilaterally by the counterparty as a result of the Bankruptcy Petitions.

Basis of Presentation

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

Core Properties

Eagle Ford Shale

We and our predecessor entities have a long history in the Eagle Ford Shale where we had assembled approximately 462,000 gross (260,000 net) leasehold acres and have 4,366 gross (2,118 net) specifically identified potential future drilling locations. As of June 30, 2019, 948 of these drilling locations represented PUDs and were evaluated using existing geologic and engineering data. Although the approximately 3,418 gross additional non-proved locations identified by our management were determined using the same geologic and engineering methodology as those locations to which proved reserves are attributed, they fail to satisfy all criteria for proved reserves for reasons such as development timing, economic viability at Securities and Exchange Commission (“SEC”) pricing and production volume certainty. In evaluating and determining those locations, we also considered the availability of local infrastructure, drilling support assets, property restrictions and state and local regulations. The Company updates its estimate of identified potential future drilling locations from time to time based on various factors, including actual results from recently drilled and completed wells, changes in well-spacing strategies and other observed performance and operating trends. We may increase or decrease our estimated inventory of potential future drilling locations as appropriate based on additional information and performance data. Our estimate of potential future drilling locations was derived based on evaluations designed to optimize the value of our oil and natural gas properties and the efficiency of our multi-year development program and is not intended to represent an actual forecast or limitation in the number of locations that may be drilled. The locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results and other factors, and may differ from the locations currently identified. With our limited capital budget for 2019 (or if we do not

increase our capital expenditures budget in 2020), many of our identified drilling locations may be uneconomic at current or projected prices. For the year 2019, we plan to invest the majority of our capital budget in the Eagle Ford Shale.

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

In the Comanche area, we have a development commitment that, in addition to other requirements in the leases that must be met in order to maintain our acreage position, requires us to complete and equip 60 wells in each annual period commencing on September 1, 2017 and continuing thereafter until September 1, 2022 or pay a penalty for the failure to do so. Up to 30 wells completed and equipped in excess of the annual 60-well requirement can be carried over to satisfy part of the 60-well requirement in subsequent annual periods on a well-for-well basis. As of August 31, 2018, the Company had achieved a 30-well bank at Comanche that can be applied toward its current annual development commitment for the period that extends from September 1, 2018 to August 31, 2019. The Company completed and equipped an additional 45 wells at Comanche between September 1, 2018 and June 30, 2019, resulting in a total of 75 wells that can be applied toward the current annual development commitment of 60 wells. Accordingly, the Company has met its annual development commitment for the period September 1, 2018 to August 31, 2019. We currently intend to drill at least the minimum number of wells required to satisfy the development agreement and to comply with applicable lease requirements necessary to maintain our Comanche acreage position. SN Maverick is currently engaged in a disagreement with Gavilan, an entity controlled by Blackstone, regarding operations of the Comanche Assets under the joint development agreement with Gavilan (the “JDA”). Among other things, Gavilan has asserted that SN Maverick is in default of the JDA and Gavilan has the right to take over operations of the Comanche Assets. Although SN Maverick disputes Gavilan’s assertions and has asserted defenses to the allegations and its own counterclaims against Gavilan, if Gavilan prevails in the disagreement, SN Maverick would lose its rights to operate the Comanche Assets and certain rights of SN Maverick under the JDA, including the ability to vote or appoint representatives to the operating committee or to transfer the Comanche Assets, among others. Furthermore, Gavilan has attempted to initiate a division of operatorship under the JDA pursuant to which operatorship of the Comanche Assets would be divided between Gavilan (or a third-party operator) and SN Maverick in accordance with certain procedures specified in the JDA. Arbitration regarding this dispute was initiated by Gavilan with the American Arbitration Association on February 18, 2019, seeking, among other things, a declaration that SN Maverick is in default under the JDA, and the Company submitted its answer and counterclaims on February 26, 2019 seeking, among other things, a declaration that Gavilan is in default under the JDA. Loss of operatorship of some portion or all of the Comanche Assets, or a finding that SN Maverick is in default under the JDA, would have a material adverse effect on our business, financial condition or results of operations.

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

In the Catarina area, we have a drilling commitment that requires us to drill (i) 50 wells in each 12-month period commencing on July 1, 2014 and (ii) at least one well in any consecutive 120‑day period, in order to maintain rights to any future undeveloped acreage. Up to 30 wells drilled in excess of the minimum 50 wells in a given annual period can be carried over to satisfy part of the 50-well requirement in the subsequent 12-month period on a well-for-well basis. As of June 30, 2018, the Company achieved a 26-well drilling bank at Catarina that can be applied toward its annual drilling commitment for the period that extends from July 1, 2018 to June 30, 2019. The Company drilled an additional 37 wells between July 1, 2018 and June 30, 2019 at Catarina, resulting in a total of 63 wells toward the annual drilling commitment of 50 wells. Accordingly, the Company has met all of its 50-well annual drilling commitment for the period July 1, 2018 to June 30, 2019 and initiated a bank of 13 wells that will be counted toward the next annual drilling commitment period, which began on July 1, 2019. The Company’s 2019 capital budget and plans include the additional activity needed to fulfill the commitment to drill at least one well in any 120-day period 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.

We have approximately 85,000 net acres in Dimmit, Frio, La Salle, and Zavala counties, Texas, which we refer to as the Maverick area, which we believe lies in the black oil window. We have identified approximately 790 gross (760 net) locations for potential future drilling in our Maverick area.

We have approximately 7,600 net acres in Gonzales County, Texas, which we refer to as the Palmetto area, which we believe lies in the volatile oil window. We have identified approximately 219 gross (107 net) locations for potential future drilling in our Palmetto area.

In the Palmetto area, as of June 30, 2019, we had 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 six gross (three 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. Marathon Oil EF LLC (“Marathon”) is the operator and other lessee of our Palmetto acreage position. We believe Marathon currently intends to drill at least the minimum number of wells required to satisfy the drilling commitments and to comply with applicable lease requirements necessary to maintain our Palmetto acreage position.

Tuscaloosa Marine Shale

As of June 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 has 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,” “—Covenant Violations” and “—Debtor-in-Possession Credit Agreement” 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 the Sanchez Energy Corporation, SN UR Holdings, SN EF UnSub Holdings, LLC (“SN UnSub Holdings”), SN Maverick and, 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 will be tolled during the Tolling Period.

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 has set its 2019 capital budget at a range of $100 million to $150 million for development and optimization activities in our core areas, which represents a substantial reduction from capital expenditures of approximately $593 million in 2018. We 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. 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. During the first and second quarters of 2019, the market for acquisition and divestiture of oil and natural gas assets slowed significantly, and this reduced transaction activity level, combined with continued challenging conditions in the credit and capital markets, among other reasons, made it difficult for us to complete divestitures of non-core assets or pursue other strategic alternatives. In anticipation of potential looming liquidity constraints, the Company commenced discussions with its bondholders, other stakeholders and potential third-party investors with respect to 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 in order to preserve liquidity and continue discussions with its stakeholders. Discussions with the stakeholders continued throughout the grace period. Although the Company has not reached an agreement with its stakeholders on the terms of a comprehensive restructuring transaction, the Company obtained additional financing pursuant to the DIP Facility on an interim basis. On August 11, 2019, the Company and other Debtors filed Bankruptcy Petitions with the Bankruptcy Court and were approved 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. Following the Petition Date, the Company and the other Debtors have continued to engage with their 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. However, there can be no assurances that the Company will be able to reorganize its capital structure on terms acceptable to the Company, its creditors or other stakeholders, or at all.

Results of Operations

Three Months Ended June 30, 2019 Compared to Three Months Ended June 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				Increase (Decrease)
	June 30,				2019 vs. 2018
	2019		2018		$		%
Net Production:
Oil (MBbls)		2,113		2,377		(264)	(11)	%
Natural gas liquids (MBbls)		2,174		2,484		(310)	(12)	%
Natural gas (MMcf)		12,095		14,249		(2,154)	(15)	%
Total oil equivalent (MBoe)		6,303		7,236		(933)	(13)	%

Average Sales Price Excluding Derivatives(1):
Oil ($ per Bbl)	$	60.75	$	65.86	$	(5.11)	(8)	%
Natural gas liquids ($ per Bbl)		13.67		22.76		(9.09)	(40)	%
Natural gas ($ per Mcf)		2.59		2.89		(0.30)	(10)	%
Oil equivalent ($ per Boe)	$	30.05	$	35.13	$	(5.08)	(14)	%

Average Sales Price Including Derivatives(2):
Oil ($ per Bbl)	$	57.79	$	52.80	$	4.99	9	%
Natural gas liquids ($ per Bbl)		13.67		22.76		(9.09)	(40)	%
Natural gas ($ per Mcf)		2.69		3.21		(0.52)	(16)	%
Oil equivalent ($ per Boe)	$	29.24	$	31.48	$	(2.24)	(7)	%

Revenues from Production(1)(3):
Oil sales	$	128,380	$	156,544	$	(28,164)	(18)	%
Natural gas liquids sales		29,716		56,533		(26,817)	(47)	%
Natural gas sales		31,311		41,141		(9,830)	(24)	%
Total revenues from production	$	189,407	$	254,218	$	(64,811)	(25)	%

(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.

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
	June 30,
	2019		2018
Net Production:
Oil (MBbls)
Comanche		973		1,134
Catarina		788		828
Maverick		237		368
Palmetto		98		26
TMS / Other		17		21
Total		2,113		2,377
Natural gas liquids (MBbls)
Comanche		854		1,024
Catarina		1,292		1,445
Maverick		8		8
Palmetto		20		7
Total		2,174		2,484
Natural gas (MMcf)
Comanche		4,640		5,796
Catarina		7,300		8,374
Maverick		41		37
Palmetto		114		42
Total		12,095		14,249
Net production volumes:
Total oil equivalent (MBoe)		6,303		7,236
Average daily production (Boe/d)		69,264		79,516
Average sales price (1):
Oil ($ per Bbl)	$	60.75	$	65.86
Natural gas liquids ($ per Bbl)	$	13.67	$	22.76
Natural gas ($ per Mcf)	$	2.59	$	2.89
Oil equivalent ($ per Boe)	$	30.05	$	35.13
Average unit costs per Boe:
Oil and natural gas production expenses	$	12.02	$	10.73
Production and ad valorem taxes	$	1.87	$	1.96
General and administrative expenses	$	7.69	$	4.07
Depreciation, depletion, amortization and accretion	$	9.93	$	8.61
Impairment of oil and natural gas properties	$	1.46	$	0.03

(1)

Excludes the realized impact of derivative instrument settlements.

Net Production. Production decreased from 7,236 MBoe for the three months ended June 30, 2018 to 6,303 MBoe for the three months ended June 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 June 30,
	2019		2018
	# Wells	MBoe	# Wells	MBoe
Comanche	1,760	2,600	1,657	3,124
Catarina	460	3,297	425	3,669
Palmetto	82	137	86	40
Maverick	68	252	63	382
TMS / Other	50	17	47	21
Total	2,420	6,303	2,278	7,236

For the three months ended June 30, 2019, 34% of our production was oil, 34% was NGLs and 32% was natural gas compared to the three months ended June 30, 2018 production that was 33% oil, 34% NGLs and 33% natural gas. The production mix is relatively consistent between the periods.

Revenues from Production. Sales revenue for oil, NGLs and natural gas from production totaled $189.4 million and $254.2 million for the three months ended June 30, 2019 and 2018, respectively. Sales revenue for oil, NGLs and gas for the three months ended June 30, 2019 decreased $28.2 million, $26.8 million and $9.9 million, respectively, as compared to the three months ended June 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 $5.7 million and $5.1 million during the three months ended June 30, 2019 and 2018, respectively. The commodity purchase and sale transactions associated with this revenue stream commenced during the first quarter 2018. We believe an opportunity exists, from time to time, to participate in additional economic benefits and operational efficiencies in support of our upstream activities by purchasing and reselling production from others, to a limited extent, in order to utilize existing firm transportation arrangements. The volumes associated with these activities are variable and, accordingly, the related revenues from these activities are expected to fluctuate from period to period.

The following tables provide an analysis of the impacts of changes in average realized prices and production volumes between the periods on our revenues from production from the three months ended June 30, 2018 to the three months ended June 30, 2019 (in thousands, except average sales price).



	Production Volume						Three Months Ended		Revenue
	Three Months Ended June 30,						June 30, 2018		Decrease
	2019		2018		Difference		Average Sales Price		from Production
Oil (MBbls)		2,113		2,377		(264)	$	65.86	$	(17,386)
NGLs (MBbls)		2,174		2,484		(310)	$	22.76	$	(7,055)
Natural gas (MMcf)		12,095		14,249		(2,154)	$	2.89	$	(6,220)
Total oil equivalent (MBoe)		6,303		7,236		(933)	$	35.13	$	(30,661)


	Average Sales Price per Unit						Three Months Ended		Revenue
	Three Months Ended June 30,						June 30, 2019		Decrease
	2019		2018		Difference		Production Volume		from Price
Oil (MBbls)	$	60.75	$	65.86	$	(5.11)		2,113	$	(10,778)
NGLs (MBbls)	$	13.67	$	22.76	$	(9.09)		2,174	$	(19,762)
Natural gas (MMcf)	$	2.59	$	2.89	$	(0.30)		12,095	$	(3,610)
Total oil equivalent (MBoe)	$	30.05	$	35.13	$	(5.08)		6,303	$	(34,150)

Additionally, a 10% increase or decrease in our average realized sales prices for the three months ended June 30, 2019, excluding the impact of derivatives, would have increased or decreased our revenues by approximately $18.9 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)
	June 30,				2019 vs. 2018
	2019		2018		$		%
Oil and natural gas production expenses	$	75,747	$	77,644	$	(1,897)	(2)	%
Exploration expenses		3,548		516		3,032	*
Sales and marketing expenses		4,988		5,086		(98)	(2)	%
Production and ad valorem taxes		11,765		14,208		(2,443)	(17)	%
Depreciation, depletion, amortization and accretion		62,575		62,323		252	0	%
Impairment of oil and natural gas properties		9,214		194		9,020	*
General and administrative expenses(1)		48,492		29,467		19,025	65	%
Total operating costs and expenses		216,329		189,438		26,891	14	%

Interest income		603		1,528		(925)	(61)	%
Other income (expense)		(1,787)		6,715		(8,502)	*
Interest expense		(44,561)		(44,590)		29	0	%
Net gains (losses) on commodity derivatives		14,396		(70,044)		84,440	*
Income tax expense		374		—		374	*

*Variances deemed to be not meaningful

(1)

Includes non-cash stock-based compensation expense of $0.2 million and $4.7 million for the three months ended June 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 $75.7 million ($12.02 per Boe) for the three months ended June 30, 2019, as compared to $77.6 million ($10.73 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 June 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 $83.5 million ($11.55 per Boe). The decrease in oil and natural gas production expenses from the three months ended June 30, 2018, excluding the amortization of the Western Catarina Midstream deferred gain, compared to the three months ended June 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 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. The increase in oil and natural gas production expenses per Boe for the three months ended June 30, 2019 compared to the three months ended June 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 $3.5 million and $0.5 million during the three months ended June 30, 2019 and 2018, respectively. The increase in our exploration expenses for the six months ended June 30, 2019 as compared to the same period in 2018 was primarily due to an increase in our exploratory geological and geophysical seismic costs.

Sales and Marketing Expenses. The Company incurred sales and marketing expenses of approximately $5.0 million and $5.1 million for the three months ended June 30, 2019 and 2018, respectively. The commodity purchase and

sale transactions associated with the related revenue stream commenced during the first quarter 2018. We believe an opportunity exists, from time to time, to participate in additional economic benefits and operational efficiencies in support of our upstream activities by purchasing and reselling production from others, to a limited extent, in order to utilize existing firm transportation arrangements. The volumes associated with these activities are variable and, accordingly, the related expenses from these activities are expected to fluctuate from period to period.

Production and Ad Valorem Taxes. Production taxes are paid on produced oil and natural gas based upon a percentage of gross revenues or at fixed rates established by state or local taxing authorities. Ad valorem taxes are paid based upon the appraised fair market value of producing properties using an estimated discounted cash flow approach and a fixed rate established by state or local taxing authorities. Our production and ad valorem taxes totaled $11.8 million ($1.87 per Boe) and $14.2 million ($1.96 per Boe) for the three months ended June 30, 2019 and 2018, respectively. The decrease in production and ad valorem taxes in the second 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 increased $0.3 million from $62.3 million ($8.61 per Boe) for the three months ended June 30, 2018 to $62.6 million ($9.93 per Boe) for the three months ended June 30, 2019. The increase in expense represented an approximate $8.3 million increase due to a higher depletion rate which was offset by a $8.0 million decrease from lower production.

Impairment of Oil and Natural Gas Properties. We recorded a proved property impairment of $4.3 million for the three months ended June 30, 2019. We did not record a proved property impairment for the three months ended June 30, 2018. We recorded impairment of $4.9 million and $0.2 million to our unproved oil and natural gas properties for the three months and ended June 30, 2019 and 2018, respectively, due to acreage expiration from changes in development plan. Changes in production rates, levels of reserves, future development costs and other factors will impact our actual impairment analyses in future periods.

General and Administrative Expenses. Our G&A expenses totaled $48.5 million ($7.69 per Boe) for the three months ended June 30, 2019 compared to $29.5 million ($4.07 per Boe) for the same period in 2018. This increase was primarily due to increases in professional fees due to costs incurred in connection with our evaluation of strategic alternatives and preparation for the Chapter 11 Cases as well as increases in salaries and wages resulting from employee retention and executive compensation programs. Offsetting these increases was a decrease in stock-based compensation expense for the three months ended June 30, 2018 to the comparable period of 2019 resulting from a decrease in the Company’s stock price.

Other Income (Expense). For the three months ended June 30, 2019, other expense totaled $1.8 million compared to other income of $6.7 million for the three months ended June 30, 2018. The other expense during the three months ended June 30, 2019 relates primarily to a loss of $2.6 million associated with the decrease in fair value of the investment in Lonestar, partially offset by gains of $0.2 million associated with the increase in fair value of the investment in SNMP. This is compared to gains of $6.1 million and $3.3 million associated with the increases in fair value of the investment in Lonestar and SNMP, respectively, for the three month period ended June 30, 2018. Additionally, we received $0.6 million of income on Company owned equipment during the three months ended June 30, 2019 as compared to $1.1 million for the comparable period of 2018.

Interest Expense. For the three months ended June 30, 2019, interest expense totaled $44.6 million and included $3.2 million in amortization of debt issuance costs, which is consistent with the three months ended June 30, 2018, for which interest expense totaled $44.6 million and included $3.1 million in amortization of debt issuance costs.

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 June 30, 2019, we recognized a net gain of $14.4 million on our commodity derivative contracts, which included mark-to-market gains on unsettled oil and natural gas derivatives of $14.6 million and $4.8 million, respectively, offset by a net loss of $5.0 million associated with the settlements of commodity derivative contracts. The mark-to-market gains were a result of the decrease in estimated future commodity prices as compared to the derivative settlement prices. The settlement losses during the period were primarily a result of increases in commodity prices from the time the positions were entered into until the time of settlement. During the three months ended June 30, 2018, we recognized a net loss of $70.0 million on our commodity derivative contracts, which

included mark-to-market losses on oil and natural gas derivatives of $35.3 million and $8.4 million, respectively, and net losses of $26.4 million associated with the settlements of commodity derivative contracts.

Income Tax Expense. For the three months ended June 30, 2019, the Company recorded an income tax expense of $0.4 million, and our effective tax rate was approximately (0.7%). The Company did not record an income tax expense for the three months ended June 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.

Six Months Ended June 30, 2019 Compared to Six Months Ended June 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):


	Six Months Ended				Increase (Decrease)
	June 30,				2019 vs. 2018
	2019		2018		$		%
Net Production:
Oil (MBbls)		4,449		4,898		(449)	(9)	%
Natural gas liquids (MBbls)		4,510		4,890		(380)	(8)	%
Natural gas (MMcf)		25,253		28,199		(2,946)	(10)	%
Total oil equivalent (MBoe)		13,168		14,488		(1,320)	(9)	%

Average Sales Price Excluding Derivatives(1):
Oil ($ per Bbl)	$	57.63	$	63.68	$	(6.05)	(10)	%
Natural gas liquids ($ per Bbl)		15.57		21.64		(6.07)	(28)	%
Natural gas ($ per Mcf)		2.94		2.94		—	—	%
Oil equivalent ($ per Boe)	$	30.45	$	34.56	$	(4.11)	(12)	%

Average Sales Price Including Derivatives(2):
Oil ($ per Bbl)	$	55.70	$	53.07	$	2.63	5	%
Natural gas liquids ($ per Bbl)		15.57		21.64		(6.07)	(28)	%
Natural gas ($ per Mcf)		2.95		3.14		(0.19)	(6)	%
Oil equivalent ($ per Boe)	$	29.80	$	31.35	$	(1.55)	(5)	%

Revenues from Production(1)(3):
Oil sales	$	256,408	$	311,935	$	(55,527)	(18)	%
Natural gas liquids sales		70,217		105,838		(35,621)	(34)	%
Natural gas sales		74,360		82,870		(8,510)	(10)	%
Total revenues from production	$	400,985	$	500,643	$	(99,658)	(20)	%

(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.

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:


	Six Months Ended
	June 30,
	2019		2018
Net Production:
Oil (MBbls)
Comanche		2,045		2,340
Catarina		1,764		1,600
Maverick		492		854
Palmetto		108		57
TMS / Other		40		47
Total		4,449		4,898
Natural gas liquids (MBbls)
Comanche		1,737		2,061
Catarina		2,740		2,794
Maverick		10		17
Palmetto		23		18
Total		4,510		4,890
Natural gas (MMcf)
Comanche		9,532		11,534
Catarina		15,534		16,481
Maverick		53		84
Palmetto		134		100
Total		25,253		28,199
Net production volumes:
Total oil equivalent (MBoe)		13,168		14,488
Average daily production (Boe/d)		72,751		80,044
Average sales price (1):
Oil ($ per Bbl)	$	57.63	$	63.68
Natural gas liquids ($ per Bbl)	$	15.57	$	21.64
Natural gas ($ per Mcf)	$	2.94	$	2.94
Oil equivalent ($ per Boe)	$	30.45	$	34.56
Average unit costs per Boe:
Oil and natural gas production expenses	$	11.90	$	10.33
Production and ad valorem taxes	$	1.88	$	1.91
General and administrative expenses	$	5.24	$	3.58
Depreciation, depletion, amortization and accretion	$	9.88	$	8.39
Impairment of oil and natural gas properties	$	1.00	$	0.08

(1)

Excludes the realized impact of derivative instrument settlements.

Net Production. Production decreased from 14,488 MBoe for the six months ended June 30, 2018 to 13,168 MBoe for the six months ended June 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:


	Six Months Ended June 30,
	2019		2018
	# Wells	MBoe	# Wells	MBoe
Comanche	1,760	5,371	1,657	6,323
Catarina	460	7,093	425	7,141
Palmetto	82	511	86	92
Maverick	68	153	63	885
TMS / Other	50	40	47	47
Total	2,420	13,168	2,278	14,488

For the six months ended June 30, 2019, 34% of our production was oil, 34% was NGLs and 32% was natural gas compared to the six months ended June 30, 2018 production that was 34% oil, 34% NGLs and 32% natural gas. The production mix is consistent between the periods.

Revenues from Production. Sales revenue for oil, NGLs and natural gas from production totaled $401.0 million and $500.6 million for the six months ended June 30, 2019 and 2018, respectively. Sales revenue for oil, NGLs and natural gas decreased $55.5 million, $35.6 million and $8.5 million, respectively, as compared to the six months ended June 30, 2018. The decreases in sales revenue for were due to decreases in production for all three commodities, as discussed above, as well as decreases in average realized prices for oil and NGLs for the three months ended June 30, 2019 as compared to the comparable period of 2018. Average realized prices remained constant for natural gas.

Sales and Marketing Revenues. The Company recorded sales and marketing revenues of $10.8 million and $9.9 million during the six months ended June 30, 2019 and 2018, respectively. The commodity purchase and sale transactions associated with this revenue stream commenced during the first quarter 2018. We believe an opportunity exists, from time to time, to participate in additional economic benefits and operational efficiencies in support of our upstream activities by purchasing and reselling production from others, to a limited extent, in order to utilize existing firm transportation arrangements. The volumes associated with these activities are variable and, accordingly, the related revenues from these activities are expected to fluctuate from period to period.

The following tables provide an analysis of the impacts of changes in average realized prices and production volumes between the periods on our revenues from production from the six months ended June 30, 2018 to the six months ended June 30, 2019 (in thousands, except average sales price).



	Production Volume						Six Months Ended		Revenue
	Six Months Ended June 30,						June 30, 2018		Decrease
	2019		2018		Difference		Average Sales Price		from Production
Oil (MBbls)		4,449		4,898		(449)	$	63.68	$	(28,595)
NGLs (MBbls)		4,510		4,890		(380)	$	21.64	$	(8,225)
Natural gas (MMcf)		25,253		28,199		(2,946)	$	2.94	$	(8,658)
Total oil equivalent (MBoe)		13,168		14,488		(1,320)	$	34.56	$	(45,478)



	Average Sales Price per Unit						Six Months Ended		Revenue
	Six Months Ended June 30,						June 30, 2019		Increase/(Decrease)
	2019		2018		Difference		Production Volume		from Price
Oil (MBbls)	$	57.63	$	63.68	$	(6.05)		4,449	$	(26,932)
NGLs (MBbls)	$	15.57	$	21.64	$	(6.07)		4,510	$	(27,396)
Natural gas (MMcf)	$	2.94	$	2.94	$	—		25,253	$	148
Total oil equivalent (MBoe)	$	30.45	$	34.56	$	(4.11)		13,168	$	(54,180)

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 $40.1 million.

Operating Costs and Expenses

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


	Six Months Ended				Increase (Decrease)
	June 30,				2019 vs. 2018
	2019		2018			$	%
Oil and natural gas production expenses	$	156,702	$	149,592	$	7,110	5	%
Exploration expenses		4,818		549		4,269	*
Sales and marketing expenses		9,919		9,259		660	7	%
Production and ad valorem taxes		24,815		27,677		(2,862)	(10)	%
Depreciation, depletion, amortization and accretion		130,056		121,571		8,485	7	%
Impairment of oil and natural gas properties		13,147		1,142		12,005	*
General and administrative expenses(1)		68,975		51,887		17,088	33	%
Total operating costs and expenses		408,432		361,677		46,755	13	%

Interest income		1,226		2,270		(1,044)	(46)	%
Other income (expense)		(959)		10,143		(11,102)	*
Gain (loss) on sale of oil and natural gas properties		—		1,528		(1,528)	(100)	%
Interest expense		(89,115)		(88,510)		(605)	1	%
Net losses on commodity derivatives		(34,026)		(114,098)		80,072	(70)	%
Income tax expense		810		—		810	*

*Variances deemed to be not meaningful

(1)

Includes non-cash stock-based compensation expense of $0.3 million and $4.3 million for the six months ended June 30, 2019 and 2018, respectively.

on January 1, 2019, the Western Catarina Midstream deferred gain was derecognized. During the six months ended June 30, 2018, the Company recognized a benefit of approximately $11.9 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 $161.5 million ($11.14 per Boe). The decrease in oil and natural gas production expenses from the six months ended June 30, 2018, excluding the amortization of the Western Catarina Midstream deferred gain, compared to the six months ended June 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 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. The increase in oil and natural gas production expenses per Boe for the six months ended June 30, 2019 compared to the six months ended June 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 $4.8 million and $0.5 million during the six months ended June 30, 2019 and 2018, respectively. The increase in our exploration expenses for the six months ended June 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.

Sales and Marketing Expenses. The Company incurred sales and marketing expenses of approximately $9.9 million and $9.3 million for the six months ended June 30, 2019 and 2018, respectively. The commodity purchase and sale transactions associated with the related revenue stream commenced during the first quarter 2018. We believe an opportunity exists, from time to time, to participate in additional economic benefits and operational efficiencies in support of our upstream activities by purchasing and reselling production from others, to a limited extent, in order to utilize existing firm transportation arrangements. The volumes associated with these activities are variable and, accordingly, the related expenses from these activities are expected to fluctuate from period to period.

Production and Ad Valorem Taxes. Production taxes are paid on produced oil and natural gas based upon a percentage of gross revenues or at fixed rates established by state or local taxing authorities. Ad valorem taxes are paid based upon the appraised fair market value of producing properties using an estimated discounted cash flow approach and a fixed rate established by state or local taxing authorities. Our production and ad valorem taxes totaled $24.8 million ($1.88 per Boe) and $27.7 million ($1.91 per Boe) for the six months ended June 30, 2019 and 2018, respectively. The decrease in production and ad valorem taxes in the first six 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 increased $8.5 million from $121.6 million ($8.39 per Boe) for the six months ended June 30, 2018 to $130.1 million ($9.88 per Boe) for the six months ended June 30, 2019. The increase in expense represented an approximate $19.6 million increase due to a higher depletion rate which was offset by a $11.1 million decrease from lower production.

Impairment of Oil and Natural Gas Properties. We recorded a proved property impairment of $4.3 million for the six months ended June 30, 2019. We did not record a proved property impairment for the six months ended June 30, 2018. We recorded impairment of $8.8 million and $1.1 million to our unproved oil and natural gas properties for the six months ended June 30, 2019 and 2018, respectively, due to acreage expiration for changes in development plan. Changes in production rates, levels of reserves, future development costs and other factors will impact our actual impairment analyses in future periods.

General and Administrative Expenses. Our G&A expenses totaled $69.0 million ($5.24 per Boe) for the six months ended June 30, 2019 compared to $51.9 million ($3.58 per Boe) for the same period in 2018. This increase was primarily due to increases in professional fees due to costs incurred in connection with our evaluation of strategic alternatives and preparation for the Chapter 11 Cases as well as increases in salaries and wages resulting from employee retention and executive compensation programs. Offsetting these increases was a decrease in stock-based compensation expense for the three months ended June 30, 2018 to the comparable period of 2019 resulting from a decrease in the Company’s stock price.

Other Income (Expense). For the six months ended June 30, 2019, other expense totaled $1.0 million compared to other income of $10.1 million for the six months ended June 30, 2018. The other expense during the six months ended June 30, 2019 relates primarily to $1.2 million in shortfall and idle rig costs as compared to no costs for the comparable period of 2018. Additionally, we experienced a loss of $2.0 million associated with the decrease in fair value of the investment in Lonestar for the six months ended June 30, 2019, partially offset by a gain of $1.2 million associated with the increase in fair value of the investment in SNMP. This is compared to gains of $6.7 million and $1.6 million associated with the increases in fair value of the investments in Lonestar and SNMP, respectively, for the comparable period of 2018. Further, we received $0.3 million in income on Company owned equipment during the six months ended June 30, 2019 as compared to $4.3 million for the comparable period of 2018, we experienced a gain on our embedded derivative contracts of $0.3 million for the six months ended June 30, 2019 as compared to a loss of $6.1 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 $2.0 million for the comparable period of 2018.

Interest Expense. For the six months ended June 30, 2019, interest expense totaled $89.1 million and included $6.3 million in amortization of debt issuance costs. Interest expense, excluding amortization of debt issuance costs, for the six months ended June 30, 2019 was greater than the six months ended June 30, 2018 primarily due to the additional interest incurred during 2019 on the 7.25% Senior Secured Notes, as they were issued in February 2018. The amortization of debt issuance costs for the six months ended June 30, 2019 was lower than the six months ended June 30, 2018 due to a write-off of amortization costs related to the amendment to the Credit Agreement in February 2018.

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 six months ended June 30, 2019, we recognized a net loss of $34.0 million on our commodity derivative contracts, which included net losses of $8.6 million associated with the settlements of commodity derivative contracts and mark-to-market losses of $25.4 million on unsettled commodity derivative contracts. The mark-to-market losses were a result of the increase in estimated future commodity prices as compared to the derivative settlement prices. The settlement losses during the period were primarily a result of increases in commodity prices from the time the positions were entered into until the time of settlement. During the six months ended June 30, 2018, we recognized a net loss of $114.1 million on our commodity derivative contracts, which included mark-to-market losses on oil and natural gas derivatives of $56.0 million and $12.0 million, respectively, and net losses of $46.1 million associated with the settlements of commodity derivative contracts.

Income Tax Expense. For the six months ended June 30, 2019, the Company recorded an income tax expense of $0.8 million and our effective tax rate was approximately (0.7%). The Company did not record an income tax expense for the six months ended June 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 June 30, 2019, our critical accounting policies were consistent with those discussed in our 2018 Annual Report.

Use of Estimates

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

of unproved properties for impairment, the fair value of commodity derivative contracts, embedded derivatives and asset retirement obligations, accrued oil and natural gas revenues and expenses and the allocation of 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. As discussed in “Part I, Item 1. Notes to the Condensed Consolidated Financial Statements—Note 1—Liquidity and Chapter 11 Cases—Voluntary Reorganization Under Chapter 11” and earlier in “Item 2.—Management’s Discussion and Analysis of Financial Condition and Results of Operations” the Debtors filed petitions for reorganization under Chapter 11 of the Bankruptcy Code.

As of June 30, 2019, we had approximately $203.5 million in cash and cash equivalents, $7.9 million in available borrowing capacity under the Credit Agreement, and $87.0 million in available borrowing capacity under the SN UnSub Credit Agreement, resulting in aggregate liquidity of approximately $298.4 million.

The Company’s filing of the Bankruptcy Petitions described above constitutes 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 June 30, 2019, there were approximately $153.0 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 our borrowing base under the SN UnSub Credit Agreement may be decreased at the time of the next redetermination or at the time of a future redetermination, and 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 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.

On August 13, 2019, the Bankruptcy Court approved our DIP Facility on an interim basis subject to submitting an appropriate form of order, which includes the authority for us to borrow $50 million, and which subject to final approval by the Bankruptcy Court, would provide the Company with an incremental $125 million of borrowing capacity. See above under “Business Overview” for a description of the DIP Facility. We anticipate closing the DIP Facility and borrowing the initial New Money DIP Loans thereunder promptly following the Bankruptcy Court’s entry of the Interim DIP Order. With the significant reduction of our capital budget, we currently expect 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 fund our anticipated 2019

operating needs. However, there are no assurances 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 other alternative restructuring transaction is approved by the Bankruptcy Court and consummated. 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.

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 six months ended June 30, 2019 and 2018 (in thousands) are as follows:


	Six Months Ended
	June 30,
	2019		2018
Cash Flow Data:
Net cash provided by operating activities	$	110,883	$	155,294
Net cash used in investing activities	$	(76,971)	$	(306,958)
Net cash provided by (used in) financing activities	$	(28,056)	$	404,919

Net Cash Provided by Operating Activities. Net cash provided by operating activities was $110.9 million for the six months ended June 30, 2019 compared to cash provided by operating activities of $155.3 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 $77.0 million for the six months ended June 30, 2019 compared to $307.0 million for the same period in 2018. Capital expenditures incurred for drilling and leasehold activities for the six months ended June 30, 2019 totaled $40.5 million, and cash paid for capital expenditures was $81.6 million. The capital expenditures incurred are primarily associated with bringing 24 gross wells on-line during the first half 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 six months ended June 30, 2018, capital expenditures incurred for drilling and leasehold activities totaled $324.0 million and cash paid for capital expenditures was $307.7 million. The capital expenditures incurred are primarily associated with bringing 117 gross wells on-line. In addition, we received $2.8 million related to the post-closing adjustments for the Comanche Acquisition during the six months ended June 30, 2018.

Net Cash Used in or Provided by Financing Activities. Net cash flows used in financing activities totaled $28.1 million for the six months ended June 30, 2019 compared net cash flows provided by financing activities of $404.9 million for the same period in 2018. During the six months ended June 30, 2019, we made payments of $15.2 million on the SN UnSub Credit Agreement and our other debt agreements. We also made payments of $12.5 million for distributions to holders of the SN UnSub Preferred Units. During the six months ended June 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 the prior credit facility of $95 million and payments on the SN UnSub Credit Agreement of $8.0 million. We also made payments of $9.9 million for distributions to holders of the SN UnSub Preferred Units and paid dividends on our Series A and B Preferred Stock of $8.0 million.

Off‑Balance Sheet Arrangements

As of June 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 six months ended June 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.

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 entered 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 have included 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 entered 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 June 30, 2019, are regulated by, as applicable, the terms of the Credit Agreement, the SN UnSub Credit Agreement and SN UnSub’s organizational documents, are intended to support oil and natural gas prices at targeted levels and manage exposure to oil and natural gas price fluctuations. It is our policy to

enter into derivative contracts only with counterparties that are creditworthy and competitive market participants. As of June 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 Credit Agreement are, in each case, collateralized by the assets securing the applicable facility, and, therefore, did not as of June 30, 2019 require the posting of cash collateral. As of June 30, 2019, any derivatives that are with (x) non-lenders (or non-lender affiliates) under the SN UnSub Credit Agreement or (y) counterparties that are not designated as secured under the Credit Agreement are, in each case, unsecured and do not require the posting of cash or other collateral. It is never the Company’s intention to enter into derivative contracts for speculative trading purposes. Please refer to Note 8, “Derivative Instruments” for a description of all of our derivatives covering anticipated future production as of June 30, 2019. Other than SN UnSub’s derivative contracts, the Company’s derivative contracts may be terminated unilaterally by the counterparty as a result of the Bankruptcy Petitions.

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 June 30, 2019, the fair value of our commodity derivative contracts was a net liability of approximately $4.2 million. A 10% increase or decrease in the oil and natural gas index prices above the June 30, 2019 prices would result in a decrease or increase, respectively, in the fair value of our commodity derivative contracts of $21.1 million. On a consolidated basis as of June 30, 2019, the Company has hedged approximately 1,546,000 Bbls of its remaining 2019 oil production and 8,654,000 MMBtu of its remaining 2019 natural gas production. As of June 30, 2019, SN UnSub’s production represents approximately 48% of the hedged oil volumes and approximately 43% of the hedged gas volumes. As noted above, other than SN UnSub’s derivative contracts, the Company’s derivative contracts may be terminated unilaterally by the counterparty as a result of the Bankruptcy Petitions.

Following the Chapter 11 Cases, 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.”

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

Interest Rate Risk

As of June 30, 2019, we had no borrowings outstanding under the Credit Agreement, $153.0 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. On July 10, 2019, the Company borrowed the remaining $7.9 million available under the Credit Agreement, which we anticipate paying off in full subject to final approval of the Bankruptcy Court. 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 June 30, 2019, a one percent change in the interest rates on the outstanding borrowings under the SN UnSub Credit Agreement and the SR Credit Agreement would result in an approximately $1.6 million change in annual interest expense. We believe our exposure to interest-related losses at June 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 June 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 June 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 commencement of the Chapter 11 Cases automatically stayed certain actions against the Company, including actions to collect pre-petition liabilities or to exercise control over the property of the Company’s bankruptcy estates, and the Company intends to seek authority to pay all general claims in the ordinary course of business notwithstanding the commencement of the Chapter 11 Cases. If a Chapter 11 plan of reorganization is confirmed, it will provide for the treatment of claims against the Company’s bankruptcy estates, including pre-petition liabilities that have not otherwise been satisfied or addressed during the Chapter 11 Cases.

Item 1A. Risk Factors

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

We are subject to the risks and uncertainties associated with Chapter 11 Cases.

For the duration of our Chapter 11 Cases, our operations and our ability to develop and execute our business plan, as well as our continuation as a going concern, are subject to the risks and uncertainties associated with bankruptcy. These risks include the following:

our ability to develop, negotiate, confirm and consummate a Chapter 11 plan or alternative restructuring transaction;

our ability to obtain court approval with respect to motions filed in Chapter 11 Cases from time to time;

our ability to maintain our relationships with our suppliers, service providers, customers, employees and other third parties;

our ability to maintain contracts that are critical to our operations;

our ability to execute our business plan;

the ability of third parties to seek and obtain court approval to terminate contracts and other agreements with us;

our ability to obtain Bankruptcy Court approval of the various motions and form of motions described herein, including with respect to our DIP Facility and the ability of third parties to seek and obtain court approval to terminate or shorten the exclusivity period for us to propose and confirm a Chapter 11 plan, to appoint a Chapter 11 trustee, or to convert the Chapter 11 Cases to a Chapter 7 proceeding; and

the actions and decisions of our creditors and other third parties who have interests in our Chapter 11 Cases that may be inconsistent with our plans.

These risks and uncertainties could affect our business and operations in various ways. For example, negative events associated with our Chapter 11 Cases could adversely affect our relationships with our suppliers, service providers, customers, employees, and other third parties, which in turn could adversely affect our operations and financial condition. Also, we need the prior approval of the Bankruptcy Court for transactions outside the ordinary course of business, which may limit our ability to respond timely to certain events or take advantage of certain opportunities. Because of the risks and uncertainties associated with our Chapter 11 Cases, we cannot accurately predict or quantify the ultimate impact of events that will occur during our Chapter 11 Cases that may be inconsistent with our plans.

Operating under Bankruptcy Court protection for a long period of time may harm our business.

Our future results are dependent upon the successful confirmation and implementation of a plan of reorganization. A long period of operations under Bankruptcy Court protection could have a material adverse effect on our business, financial condition, results of operations and liquidity. So long as the Chapter 11 Cases continue, our senior management will be required to spend a significant amount of time and effort dealing with the reorganization instead of focusing exclusively on our business operations. A prolonged period of operating under Bankruptcy Court protection also may make it more difficult to retain management and other key personnel necessary to the success and growth of our business. In addition, the longer the Chapter 11 Cases continue, the more likely it is that our customers and suppliers will lose confidence in our ability to reorganize our business successfully and will seek to establish alternative commercial relationships.

Furthermore, we cannot predict the ultimate amount of all settlement terms for the liabilities that will be subject to a plan of reorganization. Even once a plan of reorganization is approved and implemented, our operating results may be adversely affected by the possible reluctance of prospective lenders and other counterparties to do business with a company that recently emerged from Chapter 11 Cases.

We may not be able to obtain confirmation of a Chapter 11 plan of reorganization.

To emerge successfully from Bankruptcy Court protection as a viable entity, we must meet certain statutory requirements with respect to adequacy of disclosure with respect to a Chapter 11 plan of reorganization, solicit and obtain the requisite acceptances of such a plan and fulfill other statutory conditions for confirmation of such a plan, which have not occurred to date. The confirmation process is subject to numerous, unanticipated potential delays, including a delay in the Bankruptcy Court’s commencement of the confirmation hearing regarding our plan.

If a Chapter 11 plan of reorganization is not confirmed by the Bankruptcy Court, it is unclear whether we would be able to reorganize our business and what, if anything, holders of claims against us would ultimately receive with respect to their claims.

We may have insufficient liquidity for our business operations during the Chapter 11 Cases.

Although our transformation efforts to date have resulted in lowering our cost structure and creating efficiencies, our business remains capital intensive. In addition to the cash requirements necessary to fund ongoing operations, we have incurred significant professional fees and other costs in connection with our Chapter 11 Cases and expect that we will continue to incur significant professional fees and costs throughout the Chapter 11 Cases. Although we believe that we will have sufficient liquidity to operate our business during the pendency of the Chapter 11 Cases, there can be no assurance that the cash made available to us under the DIP Facility or otherwise in our restructuring process and revenue generated by our business operations will be sufficient to fund our operations. In the event that revenue flows and other available cash are not sufficient to meet our liquidity requirements, we may be required to seek additional financing. There can be no assurance that such additional financing would be available or, if available, offered on terms that are acceptable.

Our liquidity, including our ability to meet our ongoing operational obligations, is dependent upon, among other things: (i) our ability to comply with the terms and conditions of any order governing the use of our cash collateral that may be entered by the Bankruptcy Court in connection with the Chapter 11 Cases, (ii) our ability to maintain adequate cash on hand, (iii) our ability to generate cash flow from operations, (iv) our ability to develop, confirm and consummate a Chapter 11 plan or other alternative restructuring transaction, and (v) the cost, duration and outcome of the Chapter 11 Cases.

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 and, if the borrowing base under the SN UnSub Credit Facility is decreased, SN UnSub may also have no or limited borrowing capacity or be required to pay a deficiency, in which case we may not be able to satisfy the liquidity requirements of SN UnSub.

Our long-term liquidity requirements and the adequacy of our capital resources are difficult to predict at this time.

We face uncertainty regarding the adequacy of our liquidity and capital resources and have extremely limited, if any, access to additional financing beyond the DIP Facility. In addition to the cash requirements necessary to fund ongoing 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. We cannot assure you that cash on hand, cash flow from operations and any financing we are able to obtain in connection with our emergence from our Chapter 11 Cases will be sufficient to continue to fund our operations and allow us to satisfy our obligations related to the Chapter 11 Cases until we emerge from our Chapter 11 Cases.

As a result of the Chapter 11 Cases, our financial results may be volatile and may not reflect historical trends.

During the Chapter 11 Cases, we expect our financial results to continue to be volatile as restructuring activities and expenses, contract terminations and rejections, and claims assessments significantly impact our consolidated financial statements. As a result, our historical financial performance is likely not indicative of our financial performance after the date of the bankruptcy filing. In addition, if we emerge from Chapter 11, the amounts reported in subsequent consolidated financial statements may materially change relative to historical consolidated financial statements, including as a result of revisions to our operating plans pursuant to a plan of reorganization. We also may be required to adopt fresh start accounting, in which case our assets and liabilities will be recorded at fair value as of the fresh start reporting date, which may differ materially from the recorded values of assets and liabilities on our consolidated balance sheets. Our financial results after the application of fresh start accounting also may be different from historical trends.

We may be subject to claims that will not be discharged in the Chapter 11 Cases, which could have a material adverse effect on our financial condition and results of operations.

The Bankruptcy Code provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation. With few exceptions, all claims that arose prior to August 11, 2019, or before confirmation of the plan of reorganization (i) would be subject to compromise and/or treatment under the plan of reorganization and/or (ii) would be discharged in accordance with the terms of the plan of reorganization. Any claims not ultimately discharged through the plan of reorganization could be asserted against the reorganized entities and may have an adverse effect on our financial condition and results of operations on a post-reorganization basis.

SOG may experience increased levels of employee attrition as a result of the Chapter 11 Cases.

As a result of the Chapter 11 Cases, SOG may experience increased levels of employee attrition, and its employees likely will face considerable distraction and uncertainty. We have no employees and rely on SOG to provide services, including for the operation of our properties. A loss of key personnel or material erosion of SOG’s employee morale could adversely affect our business and results of operations. The loss of services of members of our senior management team could impair our ability to execute our strategy and implement operational initiatives, which would be likely to have a material adverse effect on our business, financial condition and results of operations.

In certain instances, a Chapter 11 case may be converted to a case under Chapter 7 of the Bankruptcy Code.

There can be no assurance as to whether we will successfully reorganize and emerge from the Chapter 11 Cases or, if we do successfully reorganize, as to when we would emerge from the Chapter 11 Cases.

If the Bankruptcy Court finds that it would be in the interest of creditors and/or the Debtors, the Bankruptcy Court may convert our anticipated Chapter 11 bankruptcy case to a case under chapter 7 of the Bankruptcy Code. In such event, a chapter 7 trustee would be appointed or elected to liquidate the Debtors’ assets for distribution in accordance with the priorities established by the Bankruptcy Code.

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.

During the Chapter 11 Cases, other than with respect to SN UnSub, our ability to enter into new commodity derivatives covering estimated future production will be limited. As a result, we may not be able to enter into additional commodity derivatives covering our production in future periods on favorable terms or at all. If we cannot or choose not to enter into commodity derivatives in the future, we could be more affected by changes in commodity prices than our competitors who engage in hedging arrangements. Our inability to hedge the risk of low commodity prices in the future, on favorable terms or at all, could have a material adverse impact on our business, financial condition and results of operations.

GSO consent is required for SN UnSub or SN UnSub’s general partner to take certain actions, even if we believe the actions to be in the interests of our stockholders, and GSO has claimed that we and/or SOG are in violation of one or more agreements related to GSO’s investment in SN UnSub.

Under the amended and restated limited partnership agreement of SN UnSub and limited liability company agreement of SN UnSub’s general partner, we are not able to cause SN UnSub or its general partner to take or not to take certain actions without GSO consent. GSO made a substantial investment (including contributions and other commitments) in SN UnSub at the closing of the Comanche Acquisition and, accordingly, required that the relevant organizational documents of SN UnSub and its general partner contain certain features designed to provide it with the opportunity to participate in the management of SN UnSub and its general partner and to protect its investment in SN UnSub, as well as any other assets which may be substantially dependent on or otherwise affected by the activities of SN UnSub. These participation and protective features include a governance structure that consists of a board of directors of SN UnSub’s general partner, only some of whom we appointed. Thus, unless GSO concurs, we will not be able to cause SN UnSub and its general partner to take or not to take certain actions, even though those actions may be in the interest of SN UnSub, its general partner, or us, including filing a voluntary petition for reorganization under Chapter 11. Although the Bankruptcy Code automatically stays the Company’s creditors from taking certain actions with respect to other debt agreements of the Company, no such automatic stay exists with respect to actions taken by SN UnSub’s creditors under the UnSub Credit Agreement. Furthermore, we and GSO may have different or conflicting goals or interests which could make it more difficult or time-consuming to obtain any necessary approvals or consents to pursue activities that we believe to be in the interests of our stockholders. In case of certain events of default under our debt instruments, our loss of operatorship under the JDA of the Comanche Assets in certain circumstances (including, potentially, as a result of the disagreement with Blackstone disclosed in our prior public filings), or causing SN UnSub or its general partner to take certain actions before obtaining GSO’s consent if required and other specified events (an “Investor Redemption Event”), GSO could gain control of the board of directors of SN UnSub’s general partner and as a result have the right to sell SN UnSub, the equity of SN UnSub or all or substantially all of SN UnSub’s assets. Following an Investor Redemption Event, SN UnSub may not be consolidated into our financial statements. As a result, the value of our interest in SN UnSub may be affected by economic and market conditions that are beyond our control, our ability to liquidate or otherwise monetize our interest in SN UnSub without adversely affecting its value may also be further limited, and changes in the value of our investment in SN UnSub may affect our financial results. GSO has recently alleged the existence of events that, if not cured, would be Investor Redemption Events and that we and/or SOG are also in violation of one or more agreements related to GSO’s investment in SN UnSub. Although we are disputing these allegations, if either the Company or SOG is determined to be in default under these agreements or we are otherwise unable to resolve GSO’s allegations and concerns, such alleged events may mature into one or more Investor Redemption Events as described above, if applicable, or such violations may otherwise have a material adverse effect on our financial condition or results of operations. On August 10, 2019, the Company entered into the Tolling Agreement, pursuant to which the GSO Parties agreed to not exercise any rights or remedies with respect to any Investor Redemption Event during the Tolling Period. See “Part I, Item 2. Business Overview—Recent Developments—UnSub Tolling Agreement.”

See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources in our 2018 Annual Report.

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
April 1, 2019 - April 30, 2019	417,493	$ 0.23	—	—
May 1, 2019 - May 31, 2019	2,269	$ 0.12	—	—
June 1, 2019 - June 30, 2019	45,141	$ 0.13	—	—
Total	464,903	$ 0.22	—	—

(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 1. Liquidity and 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. The Company may, at its option, pay dividends in cash and, subject to certain conditions, common stock or any combination thereof. Dividends are cumulative, and beginning during the three month period ending March 31, 2019, the Board determined to suspend the dividend on our Series A Preferred Stock. Dividends accumulated through 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 $0.9 million.

The annual dividend on each share of our Series B Preferred Stock is 6.500% on the liquidation preference of $50.00 per share and is payable quarterly, in arrears, on each January 1, April 1, July 1 and October 1, when, as and if declared by the Board. The Company may, at its option, pay dividends in cash and, subject to certain conditions, common stock or any combination thereof. Dividends are cumulative, and beginning during the three month period ending March 31, 2019, the Board determined to suspend the dividend on our Series B Preferred Stock. Dividends accumulated through 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 $4.8 million.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

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)*	Form of Executive Service Agreement.

10.2	(a)*	Sanchez Energy Corporation 2019 Executive Incentive Plan, effective May 6, 2019.

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.

*Management contract or compensatory plan or arrangement.

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 August 14, 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)