sn_Current folio_10Q

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10‑Q

(Mark One)

ma

 

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2018

OR

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from            to         

Commission file number: 1‑35372

Sanchez Energy Corporation

(Exact name of registrant as specified in its charter)

 

 

Delaware
(State or other jurisdiction of
incorporation or organization)

45‑3090102
(I.R.S. Employer
Identification No.)

1000 Main Street, Suite 3000
Houston, Texas
(Address of principal executive offices)

77002
(Zip Code)

(713) 783‑8000

(Registrant’s telephone number, including area code)

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

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

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

 

 

 

 

Emerging growth company ☐

Large accelerated filer ☐

Accelerated filer ☒

Non‑accelerated filer ☐
(Do not check if a
smaller reporting company)

Smaller reporting company ☐

Emerging growth company ☐

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

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

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

 

 


 

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Sanchez Energy Corporation

Form 10‑Q

For the Quarterly Period Ended March 31, 2018

 

Table of Contents

 

 

 

 

 

PART I

 

Item 1. 

Financial Statements

10

 

Condensed Consolidated Balance Sheets as of March 31, 2018 (Unaudited) and December 31, 2017 

10

 

Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2018 and 2017 (Unaudited)

11

 

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

12

 

Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2018 and 2017 (Unaudited)

13

 

Notes to the Condensed Consolidated Financial Statements (Unaudited)

14

Item 2. 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

56

Item 3. 

Quantitative and Qualitative Disclosures About Market Risk

68

Item 4. 

Controls and Procedures

70

 

PART II

 

Item 1. 

Legal Proceedings

71

Item 1A. 

Risk Factors

71

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

 

 

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CAUTIONARY NOTE REGARDING FORWARD‑LOOKING STATEMENTS

 

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

 

·

the timing and extent of changes in prices for, and demand for, crude oil and condensate, natural gas liquids, natural gas and related commodities;

 

·

our ability to successfully execute our business and financial strategies;

 

·

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

 

·

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

 

·

the realized benefits of the acreage acquired in our various acquisitions, including the Comanche Acquisition,  and other assets and liabilities assumed in connection therewith;

 

·

our ability to successfully integrate our various acquired assets, including  assets acquired in the Comanche Acquisition, into our operations, fully identify existing and potential problems with respect to such assets and accurately estimate reserves, production and costs with respect to such assets;

 

·

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

 

·

the realized benefits of our transactions with SNMP;

 

·

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

 

·

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

 

·

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

 

·

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

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·

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

 

·

competition in the oil and natural gas exploration and production industry in the marketing of crude oil, natural gas and NGLs and for the acquisition of leases and properties, employees and other personnel, equipment, materials and services and, related thereto, the availability and cost of employees and other personnel, equipment, materials and services;

 

·

our ability to compete with other companies in the oil and natural gas industry;

 

·

our ability to access the credit and capital markets to obtain financing on terms we deem acceptable, if at all, and to otherwise satisfy our capital expenditure and other funding  requirements;

 

·

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

 

·

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

 

·

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;

 

·

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

 

·

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

 

·

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

 

·

unexpected results of litigation filed against us;

 

·

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

 

·

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

 

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

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GLOSSARY OF SELECTED OIL AND NATURAL GAS TERMS

 

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

 

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

 

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

 

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

 

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

 

Bcf:  One billion cubic feet of natural gas.

 

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

 

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

 

Boe/d:  One Boe per day.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

LLS:  Louisiana light sweet crude.

 

MBbl:  One thousand Bbl.

 

MBoe:  One thousand Boe.

 

Mcf:  One thousand cubic feet of natural gas.

 

MMBbl:  One million Bbl.

 

MMBoe:  One million Boe.

 

MMbtu:  One million British thermal units.

 

MMcf:  One million cubic feet of natural gas.

 

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

 

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

 

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

 

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

 

NYMEX:  New York Mercantile Exchange.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

trend:  A geographic area with hydrocarbon potential.

 

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

 

unproved properties:  Properties with no proved reserves.

 

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

 

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

 

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

 

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

 

WTI:  West Texas Intermediate crude.

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PART I—FINANCIAL INFORMATION

 

Item 1.  Financial Statements

 

Sanchez Energy Corporation

 

Condensed Consolidated Balance Sheets (Unaudited)

 

(in thousands, except par value and share amounts)

 

 

 

 

 

 

 

 

 

 

March 31, 

 

December 31, 

 

    

2018

    

2017

ASSETS

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

Cash and cash equivalents

 

$

550,044

 

$

184,434

Oil and natural gas receivables

 

 

86,018

 

 

101,396

Joint interest billings receivables

 

 

20,715

 

 

22,569

Accounts receivable - related entities

 

 

4,823

 

 

4,491

Fair value of derivative instruments

 

 

12,019

 

 

16,430

Other current assets

 

 

12,852

 

 

21,478

Total current assets

 

 

686,471

 

 

350,798

Oil and natural gas properties, on the basis of successful efforts accounting:

 

 

 

 

 

 

Proved oil and natural gas properties

 

 

3,278,731

 

 

3,130,407

Unproved oil and natural gas properties

 

 

399,144

 

 

398,605

Total oil and natural gas properties

 

 

3,677,875

 

 

3,529,012

Less: Accumulated depreciation, depletion, amortization and impairment

 

 

(1,558,802)

 

 

(1,501,553)

Total oil and natural gas properties, net

 

 

2,119,073

 

 

2,027,459

 

 

 

 

 

 

 

Other assets:

 

 

 

 

 

 

Fair value of derivative instruments

 

 

8,778

 

 

1,428

Investments (Investment in SNMP measured at fair value of $23.5 million and $25.2 as of March 31, 2018 and December 31, 2017, respectively)

 

 

37,312

 

 

38,462

Other assets

 

 

52,208

 

 

52,488

Total assets

 

$

2,903,842

 

$

2,470,635

LIABILITIES AND STOCKHOLDERS' EQUITY

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

Accounts payable

 

$

10,688

 

$

14,994

Other payables

 

 

84,688

 

 

81,970

Accrued liabilities:

 

 

 

 

 

 

Capital expenditures

 

 

98,819

 

 

85,340

Other

 

 

76,131

 

 

84,794

Fair value of derivative instruments

 

 

73,997

 

 

56,190

Short term debt

 

 

23,996

 

 

23,996

Other current liabilities

 

 

105,938

 

 

115,244

Total current liabilities

 

 

474,257

 

 

462,528

Long term debt, net of premium, discount and debt issuance costs

 

 

2,366,495

 

 

1,930,683

Asset retirement obligations

 

 

37,030

 

 

36,098

Fair value of derivative instruments

 

 

20,272

 

 

17,474

Other liabilities

 

 

39,209

 

 

65,480

Total liabilities

 

 

2,937,263

 

 

2,512,263

Commitments and contingencies (Note 17)

 

 

 

 

 

 

Mezzanine equity:

 

 

 

 

 

 

Preferred units ($1,000 liquidation preference, 500,000 units authorized, issued and outstanding as of March 31, 2018 and December 31, 2017)

 

 

433,442

 

 

427,512

Stockholders' equity:

 

 

 

 

 

 

Preferred stock ($0.01 par value, 15,000,000 shares authorized; 1,838,985 shares issued and outstanding as of March 31, 2018 and December 31, 2017 of 4.875% Convertible Perpetual Preferred Stock, Series A; 3,527,830 shares issued and outstanding as of March 31, 2018 and December 31, 2017 of 6.500% Convertible Perpetual Preferred Stock, Series B)

 

 

53

 

 

53

Common stock ($0.01 par value, 150,000,000 shares authorized; 85,172,408 and 83,984,827 shares issued and outstanding as of March 31, 2018 and December 31, 2017, respectively)

 

 

858

 

 

845

Additional paid-in capital

 

 

1,366,283

 

 

1,362,118

Accumulated deficit

 

 

(1,834,057)

 

 

(1,832,156)

Total stockholders' deficit

 

 

(466,863)

 

 

(469,140)

Total liabilities and stockholders' deficit

 

$

2,903,842

 

$

2,470,635

 

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

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Sanchez Energy Corporation

 

Condensed Consolidated Statements of Operations (Unaudited)

 

(in thousands, except per share amounts)

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

March 31, 

 

    

2018

    

2017*

REVENUES:

 

 

 

 

 

 

Oil sales

 

$

155,392

 

$

73,276

Natural gas liquid sales

 

 

49,305

 

 

27,100

Natural gas sales

 

 

41,729

 

 

33,467

Sales and marketing revenues

 

 

4,802

 

 

 —

Total revenues

 

 

251,228

 

 

133,843

OPERATING COSTS AND EXPENSES:

 

 

 

 

 

 

Oil and natural gas production expenses

 

 

71,948

 

 

37,998

Exploration expenses

 

 

33

 

 

352

Sales and marketing expenses

 

 

4,173

 

 

 —

Production and ad valorem taxes

 

 

13,469

 

 

6,524

Depreciation, depletion, amortization and accretion

 

 

59,248

 

 

26,404

Impairment of oil and natural gas properties

 

 

948

 

 

1,845

General and administrative expenses

 

 

22,420

 

 

67,465

Total operating costs and expenses

 

 

172,239

 

 

140,588

Operating income (loss)

 

 

78,989

 

 

(6,745)

Other income (expense):

 

 

 

 

 

 

Interest income

 

 

742

 

 

357

Other income

 

 

3,428

 

 

10,535

Gain on sale of oil and natural gas properties

 

 

 —

 

 

4,344

Interest expense

 

 

(43,920)

 

 

(33,025)

Earnings from equity investments

 

 

 —

 

 

435

Net gains (losses) on commodity derivatives

 

 

(44,054)

 

 

38,881

Total other income (expense)

 

 

(83,804)

 

 

21,527

Income (loss) before income taxes

 

 

(4,815)

 

 

14,782

Income tax benefit

 

 

 —

 

 

953

Net income (loss)

 

 

(4,815)

 

 

15,735

Less:

 

 

 

 

 

 

Preferred stock dividends

 

 

(3,987)

 

 

(3,987)

Preferred unit dividends and distributions

 

 

(9,908)

 

 

(16,466)

Preferred unit amortization

 

 

(5,930)

 

 

(1,710)

Net loss attributable to common stockholders

 

$

(24,640)

 

$

(6,428)

 

 

 

 

 

 

 

Net loss per common share - basic and diluted

 

$

(0.30)

 

$

(0.09)

Weighted average number of shares used to calculate net loss attributable to common stockholders - basic and diluted

 

 

80,919

 

 

69,659

 

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

 

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

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Sanchez Energy Corporation

 

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

 

(in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Series A

 

Series B

 

 

 

 

 

 

Additional

 

 

 

 

Total

 

 

 

Preferred Stock

 

Preferred Stock

 

Common Stock

 

Paid-in

 

Accumulated

 

Stockholders'

 

 

    

Shares

    

Amount

    

Shares

    

Amount

    

Shares

    

Amount

    

Capital

    

Deficit

    

Deficit

 

BALANCE, December 31, 2017

 

1,839

 

$

18

 

3,528

 

$

35

 

83,985

 

$

845

 

$

1,362,118

 

$

(1,832,156)

 

$

(469,140)

 

Adoption of accounting standards

 

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 

 —

 

 

22,739

 

 

22,739

 

Issuance of common stock

 

 —

 

 

 —

 

 —

 

 

 —

 

100

 

 

 1

 

 

565

 

 

 —

 

 

566

 

Dividends on Series A and Series B Preferred stock

 

 —

 

 

 —

 

 —

 

 

 —

 

805

 

 

 8

 

 

3,979

 

 

(3,987)

 

 

 —

 

Dividends on SN UnSub preferred units

 

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 

 —

 

 

(12,500)

 

 

(12,500)

 

Distributions - SN UnSub preferred units

 

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 

 —

 

 

2,592

 

 

2,592

 

Accretion of discount on SN UnSub preferred units

 

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 

 —

 

 

(5,930)

 

 

(5,930)

 

Restricted stock awards, net of forfeitures

 

 —

 

 

 —

 

 —

 

 

 —

 

283

 

 

 4

 

 

(4)

 

 

 —

 

 

 —

 

Stock-based compensation

 

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 

(375)

 

 

 —

 

 

(375)

 

Net loss

 

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 

 —

 

 

(4,815)

 

 

(4,815)

 

BALANCE, March 31, 2018

 

1,839

 

$

18

 

3,528

 

$

35

 

85,173

 

$

858

 

$

1,366,283

 

$

(1,834,057)

 

$

(466,863)

 

 

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

 

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Sanchez Energy Corporation

Condensed Consolidated Statements of Cash Flows (Unaudited)

 (in thousands)

 

 

 

 

 

 

 

 

 

Three Months Ended

 

 

March 31, 

 

    

2018

    

2017*

CASH FLOWS FROM OPERATING ACTIVITIES:

 

 

 

 

 

 

Net income (loss)

 

$

(4,815)

 

$

15,735

Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:

 

 

 

 

 

 

Depreciation, depletion, amortization and accretion

 

 

59,248

 

 

26,404

Impairment of oil and natural gas properties

 

 

948

 

 

1,845

Gain on sale of oil and natural gas properties

 

 

 —

 

 

(4,344)

Stock-based compensation expense (benefit)

 

 

(1,273)

 

 

23,032

Net (gains) losses on commodity derivative contracts

 

 

44,054

 

 

(38,881)

Net cash settlement received (paid) on commodity derivative contracts

 

 

(19,651)

 

 

1,267

Gain on other derivatives

 

 

(336)

 

 

(685)

(Gain) loss on investments

 

 

1,150

 

 

(8,864)

Amortization of deferred gain on Western Catarina Midstream Divestiture

 

 

(5,929)

 

 

(5,929)

Amortization of debt issuance costs

 

 

6,714

 

 

2,497

Accretion of debt discount, net

 

 

281

 

 

159

Deferred taxes

 

 

 —

 

 

(953)

Earnings from equity investments

 

 

 —

 

 

(435)

Distributions from equity investments

 

 

 —

 

 

412

Changes in operating assets and liabilities:

 

 

 

 

 

 

Accounts receivable

 

 

12,984

 

 

(9,634)

Other current assets

 

 

8,626

 

 

(2,025)

Accounts payable

 

 

(4,306)

 

 

7,373

Accounts receivable - related entities

 

 

(332)

 

 

(69)

Other assets

 

 

374

 

 

 —

Other payables

 

 

2,718

 

 

929

Accrued liabilities

 

 

(3,525)

 

 

(8,529)

Other current liabilities

 

 

(12,411)

 

 

(12,993)

Net cash provided by (used in) operating activities

 

 

84,519

 

 

(13,688)

 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES:

 

 

 

 

 

 

Payments for oil and natural gas properties

 

 

(135,907)

 

 

(87,722)

Payments for other property and equipment

 

 

(173)

 

 

(7,491)

Proceeds from sale of oil and natural gas properties

 

 

 —

 

 

7,032

Acquisition of oil and natural gas properties

 

 

2,834

 

 

(1,039,127)

Payments for investments

 

 

 —

 

 

(101)

Net cash used in investing activities

 

 

(133,246)

 

 

(1,127,409)

 

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES:

 

 

 

 

 

 

Proceeds from borrowings

 

 

539,865

 

 

190,000

Repayment of borrowings

 

 

(99,087)

 

 

 —

Issuance of common stock

 

 

 —

 

 

135,942

Issuance of preferred units

 

 

 —

 

 

500,000

Issuance costs related to preferred units

 

 

 —

 

 

(21,043)

Financing costs

 

 

(11,940)

 

 

(23,873)

Preferred dividends paid

 

 

(3,987)

 

 

 —

Cash paid to tax authority for employee stock-based compensation awards

 

 

(606)

 

 

(795)

Preferred unit distribution

 

 

(9,908)

 

 

(16,466)

Net cash provided by financing activities

 

 

414,337

 

 

763,765

 

 

 

 

 

 

 

Increase (decrease) in cash and cash equivalents

 

 

365,610

 

 

(377,332)

Cash and cash equivalents, beginning of period

 

 

184,434

 

 

501,917

Cash and cash equivalents, end of period

 

$

550,044

 

$

124,585

 

 

 

 

 

 

 

NON-CASH INVESTING AND FINANCING ACTIVITIES:

 

 

 

 

 

 

Change in asset retirement obligations

 

$

174

 

$

8,349

Change in accrued capital expenditures

 

$

13,479

 

$

17,993

SUPPLEMENTAL DISCLOSURE:

 

 

 

 

 

 

Cash paid for taxes

 

$

 —

 

$

 —

Cash paid for interest

 

$

37,869

 

$

35,598

 

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

 

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

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Sanchez Energy Corporation

 

Notes to the Condensed Consolidated Financial Statements

 

(Unaudited)

Note 1. Organization and Business

 

Sanchez Energy Corporation (together with our consolidated subsidiaries, “Sanchez Energy,” the “Company,” “SN,” “we,” “our,” “us” or similar terms), a Delaware corporation formed in August 2011, is an independent exploration and production company focused on the acquisition and development of U.S. onshore unconventional oil and natural gas resources, with a current focus on the horizontal development of significant resource potential from the Eagle Ford Shale in South Texas. We also hold an undeveloped acreage position in the Tuscaloosa Marine Shale (“TMS”) in Mississippi and Louisiana, which offers potential future development opportunities. As of March 31, 2018, we have assembled approximately 487,000 gross leasehold acres (285,000 net acres) in the Eagle Ford Shale. In addition, we continually evaluate opportunities to grow our acreage and our producing assets through acquisitions. Our successful acquisition of such assets will depend on the opportunities and the financing alternatives available to us at the time we consider such opportunities. We have included definitions of some of the oil and natural gas terms used in this Quarterly Report on Form 10‑Q in the “Glossary of Selected Oil and Natural Gas Terms.” 

 

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

 

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

 

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

 

Principles of Consolidation

 

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

 

Use of Estimates

 

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

 

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Recent Accounting Pronouncements

 

In August 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-12 “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities,” which changes the recognition and presentation requirements of hedge accounting, including eliminating the requirement to separately measure and report hedge ineffectiveness, and presenting all items that affect earnings in the same income statement line item as the hedged item.  The ASU also provides new alternatives for applying hedge accounting.  This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2018. The Company is currently in the process of evaluating the impact of adoption of this guidance on its consolidated financial statements.

 

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

 

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

 

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

 

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

 

In February 2016, the FASB issued ASU 2016-02 “Leases (Topic 842),” effective for annual and interim periods for public companies beginning after December 15, 2018, with a modified retrospective approach to be used for implementation. The standard updates the previous lease guidance by requiring the recognition of a right-to-use 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 corresponding right-of-use asset on the balance sheet for most leases. Recognition, measurement and presentation of expenses and cash flows arising from a lease will depend on classification as a finance or operating lease. The Company has several operating leases as further discussed in Note 17, “Commitments and Contingencies,” which will be impacted by the new rules under this standard. The Company will not early adopt this standard, and will apply the revised lease rules for our interim and annual reporting periods starting January 1, 2019. The Company is currently evaluating the impact of these rules on its financial statements and has started the assessment process by evaluating the population of leases under the revised definition. The Company is also in the process of implementing a lease accounting software to properly account for lease data upon adoption. The adoption of this standard will result in an increase in the assets and liabilities on the Company’s condensed consolidated balance sheets. The quantitative impacts of the new standard are dependent on the active leases at the time of adoption. As a result, the evaluation of the effect of the new standards will extend over future periods.

 

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606).” In March, April, May and December of 2016, the FASB issued rules clarifying several aspects of the new revenue

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recognition standard. The new guidance is effective for fiscal years and interim periods beginning after December 15, 2017. This guidance outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods and services. The new standard also requires more detailed disclosures related to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. See Note 18. “Revenue Recognition” for discussion of the Company’s adoption of the new standard.  

 

Note 3. Change in Accounting Principle

 

During the fourth quarter of 2017, the Company voluntarily changed its method of accounting for oil and natural gas exploration and development activities from the full cost method to the successful efforts method. Accordingly, financial information for prior periods has been recast to reflect retrospective application of the successful efforts method. In general, under successful efforts, exploration expenditures such as exploratory dry holes, exploratory geological and geophysical costs, delay rentals, unproved impairments, and exploration overhead are charged against earnings as incurred, versus being capitalized under the full cost method of accounting. The successful efforts method also provides for the assessment of potential property impairments under FASB Accounting Standards Codification 360 “Property, Plant and Equipment” by comparing the net carrying value of oil and natural gas properties with associated projected undiscounted pre-tax future net cash flows. If the expected undiscounted pre-tax future net cash flows are lower than the unamortized capitalized costs, the capitalized cost is reduced to fair value. Under the full cost method of accounting, a write-down would be required if the net carrying value of oil and natural gas properties exceeds a full cost “ceiling,” using an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months. In addition, gains or losses, if applicable, are generally recognized on the dispositions of oil and natural gas property and equipment under the successful efforts method, as opposed to an adjustment to the net carrying value of the remaining assets under the full cost method. Our consolidated financial statements have been recast to reflect these differences for all periods presented, including the Condensed Consolidated Balance Sheets, Condensed Consolidated Statements of Operations, Condensed Consolidated Statements of Stockholders’ Equity, Condensed Consolidated Statements of Cash Flows and related information in Notes 3, 4, 6, 12, 13, 14, 16 and 19.

 

The following table presents the effects of the change to the successful efforts method in the condensed consolidated balance sheet (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

Changes to Condensed Consolidated Balance Sheet

March 31, 2017

 

 

Under Full Cost

 

 

Changes

 

 

As Reported Under Successful Efforts

Oil and natural gas properties:

 

 

 

 

 

 

 

 

 

Proved oil and natural gas properties

 

$

4,077,686

 

$

(1,324,878)

 

$

2,752,808

Unproved oil and natural gas properties

 

 

466,868

 

 

(6,705)

 

 

460,163

Total oil and natural gas properties

 

 

4,544,554

 

 

(1,331,583)

 

 

3,212,971

Less: Accumulated depreciation, depletion, amortization and impairment

 

 

(2,769,126)

 

 

1,381,319

 

 

(1,387,807)

Total oil and natural gas properties, net

 

 

1,775,428

 

 

49,736

 

 

1,825,164

Total assets

 

$

2,078,560

 

$

49,736

 

$

2,128,296

 

 

 

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

 

 

 

Other current liabilities

 

$

17,273

 

$

8,907

 

$

26,180

Total current liabilities

 

 

172,557

 

 

8,907

 

 

181,464

Other liabilities

 

 

63,506

 

 

22,639

 

 

86,145

Total liabilities

 

 

2,156,133

 

 

31,546

 

 

2,187,679

Accumulated deficit

 

 

(1,822,912)

 

 

18,190

 

 

(1,804,722)

Total stockholders' equity (deficit)

 

 

(481,502)

 

 

18,190

 

 

(463,312)

 

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The following table presents the effects of the change to the successful efforts method in the statement of consolidated operations (in thousands, except per share amounts):

 

 

 

 

 

 

 

 

 

 

 

 

 

Changes to the Condensed Consolidated Statement of Operations

For the three months ended March 31, 2017

 

 

Under Full Cost

 

 

Changes

 

 

As Reported Under Successful Efforts

Oil and natural gas production expenses

 

$

40,225

 

$

(2,227)

 

$

37,998

Exploration expenses

 

 

 —

 

 

352

 

 

352

Depreciation, depletion, amortization and accretion

 

 

33,206

 

 

(6,802)

 

 

26,404

Impairment of oil and natural gas properties

 

 

 —

 

 

1,845

 

 

1,845

Gain on sale of oil and natural gas properties

 

 

5,143

 

 

(799)

 

 

4,344

Net income

 

 

9,702

 

 

6,033

 

 

15,735

Net income allocable to participating securities

 

 

 —

 

 

 —

 

 

 —

Net loss attributable to common stockholders

 

$

(12,461)

 

$

6,033

 

$

(6,428)

 

 

 

 

 

 

 

 

 

 

Net loss per common share - basic and diluted

 

$

(0.18)

 

$

0.09

 

$

(0.09)

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Changes to the Condensed Consolidated Statement of Cash Flows

For the three months ended March 31, 2017

    

    

Under Full Cost

    

Change

    

As reported Under Successful Efforts

Net income

 

 

$

9,702

 

$

6,033

 

$

15,735

Adjustments to reconcile net income to net cash provided by operating activities:

 

 

 

 

 

 

 

 

 

 

Depreciation, depletion, amortization and accretion

 

 

 

33,206

 

 

(6,802)

 

 

26,404

Impairment of oil and natural gas properties

 

 

 

 —

 

 

1,845

 

 

1,845

Gain on sale of oil and natural gas properties

 

 

 

(5,143)

 

 

799

 

 

(4,344)

Amortization of deferred gain on Catarina Midstream Sale

 

 

 

(3,702)

 

 

(2,227)

 

 

(5,929)

Net cash used in operating activities

 

 

 

(13,336)

 

 

(352)

 

 

(13,688)

Payments for oil and natural gas properties

 

 

 

(88,074)

 

 

352

 

 

(87,722)

Net cash used in investing activities

 

 

 

(1,127,761)

 

 

352

 

 

(1,127,409)

Net cash provided by financing activities

 

 

 

763,765

 

 

 —

 

 

763,765

Decrease in cash and cash equivalents

 

 

 

(377,332)

 

 

 —

 

 

(377,332)

Cash and cash equivalents, beginning of period

 

 

 

501,917

 

 

 —

 

 

501,917

Cash and cash equivalents, end of period

 

 

$

124,585

 

$

 —

 

$

124,585

 

 

 

 

 

 

 

 

 

 

 

 

 

Note 4. Acquisitions and Divestitures

 

Our acquisitions are accounted for under the acquisition method of accounting in accordance with ASC Topic 805, “Business Combinations” (“ASC Topic 805”). A business combination may result in the recognition of a gain or goodwill based on the measurement of the fair value of the assets acquired at the acquisition date as compared to the fair value of consideration transferred, adjusted for purchase price adjustments. The initial accounting for acquisitions may not be complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates. The results of operations of the properties acquired in our acquisitions have been included in the condensed consolidated financial statements since the closing dates of the acquisitions.

 

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Javelina Disposition

 

On September 19, 2017, the Company, through its wholly owned subsidiary, SN Cotulla Assets, LLC (“SN Cotulla”), sold approximately 68,000 undeveloped net acres located in the Eagle Ford Shale in LaSalle and Webb Counties, Texas to Vitruvian Exploration IV, LLC for approximately $105 million in cash, after preliminary closing adjustments (the “Javelina Disposition”).  Consideration received from the Javelina Disposition was based on an August 1, 2017 effective date and is subject to normal and customary post-closing adjustments. The Company recorded a gain of approximately $73.7 million on the Javelina Disposition.

 

Marquis Disposition

 

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

 

Comanche Acquisition

 

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

 

 

 

 

 

 

Proved oil and natural gas properties

    

$

781,789

  

Unproved properties

 

 

263,471

 

Other assets acquired

 

 

6,702

 

Fair value of assets acquired

 

 

1,051,962

 

Asset retirement obligations

 

 

(8,289)

 

Fair value of net assets acquired

 

$

1,043,673

 

 

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

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the contracts.  We are currently meeting our minimum volume commitments under these contracts and expect to continue to fulfill these obligations based on our anticipated development plan for the Comanche Assets.

 

Cotulla Disposition

 

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

 

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

 

Note 5. Cash and Cash Equivalents

 

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

 

 

 

 

 

 

 

 

 

 

March 31, 

 

December 31, 

 

    

2018

    

2017

Cash at banks

 

$

125,647

 

$

135,363

Cash equivalents

 

 

424,397

 

 

49,071

Total cash and cash equivalents

 

$

550,044

 

$

184,434

 

 

Note 6. Oil and Natural Gas Properties

 

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

 

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

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

 

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

 

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

 

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

 

Note 7. Debt

 

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

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Amount Outstanding

 

 

 

 

 

 

(in thousands) as of

 

 

 

 

 

 

March 31, 

 

December 31, 

 

    

Interest Rate

    

Original Maturity Date

    

2018

    

2017

Short-Term Debt

 

 

 

 

 

 

 

 

 

 

SR Credit Agreement(1)(2)

 

Variable

 

August 8, 2018

 

$

23,996

 

$

23,996

Total short-term debt

 

 

 

 

 

$

23,996

 

$

23,996

 

 

 

 

 

 

 

 

 

 

 

Long-Term Debt

 

 

 

 

 

 

 

 

 

 

Credit Agreement

 

Variable

 

February 14, 2023

 

$

 —

 

$

50,000

SN UnSub Credit Agreement(1)

 

Variable

 

March 1, 2022

 

 

171,500

 

 

175,500

7.75% Notes

 

7.75%

 

June 15, 2021

 

 

600,000

 

 

600,000

4.59% Non-Recourse Subsidiary Term Loan(1)

 

4.59%

 

August 31, 2022

 

 

4,077

 

 

4,164

6.125% Notes

 

6.125%

 

January 15, 2023

 

 

1,150,000

 

 

1,150,000

7.25% Senior Secured Notes

 

7.25%

 

February 15, 2023

 

 

500,000

 

 

 —

 

 

 

 

 

 

 

2,425,577

 

 

1,979,664

Unamortized discount on Additional 7.75% Notes

 

 

 

 

 

 

(2,900)

 

 

(3,126)

Unamortized premium on Additional 6.125% Notes

 

 

 

 

 

 

1,292

 

 

1,360

Unamortized discount on 7.25% Senior Secured Notes

 

 

 

 

 

 

(5,012)

 

 

 —

Unamortized debt issuance costs

 

 

 

 

 

 

(52,462)

 

 

(47,215)

Total long-term debt

 

 

 

 

 

$

2,366,495

 

$

1,930,683

 

(1)

These debt instruments are Non-Recourse to the Company.

(2)

Bears a weighted-average interest rate of 5.359% and 5.122% for the three months ended March 31, 2018 and the one month ended December 31, 2017, respectively.

 

The components of interest expense are (in thousands):

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

    

March 31, 

 

 

2018

    

2017

Interest on SR Credit Agreement

 

$

(348)

 

$

 —

Interest and commitment fees on Credit Agreement

 

 

(665)

 

 

(379)

Interest on SN UnSub Credit Agreement