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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-Q

 

x       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

 

o          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: 001-35512

 

MIDSTATES PETROLEUM COMPANY, INC.

(Exact name of registrant as specified in its charter)

 

Delaware		45-3691816
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

 

321 South Boston Avenue, Suite 1000
Tulsa, Oklahoma		74103
(Address of principal executive offices)		(Zip Code)

 

Registrant’s telephone number, including area code: (918) 947-8550

 

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  x   No  o

 

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  x   No  o

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a 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  o		Accelerated filer  x
Non-accelerated filer  o		Smaller reporting company  o
(Do not check if a smaller reporting company)		Emerging growth company  o

 

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. o

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes  o    No  x

 

The number of shares outstanding of our stock at May 7, 2018 is shown below:

 

Class		Number of shares outstanding
Common stock, $0.01 par value		25,256,957

 

DOCUMENTS INCORPORATED BY REFERENCE

 

None.

 

 

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MIDSTATES PETROLEUM COMPANY, INC.

QUARTERLY REPORT ON

FORM 10-Q

FOR THE THREE MONTHS ENDED MARCH 31, 2018

 

TABLE OF CONTENTS

 

	Page
Glossary of Oil and Natural Gas Terms	3
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements
Condensed Consolidated Balance Sheets at March 31, 2018 and December 31, 2017 (unaudited)	4
Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2018 and 2017 (unaudited)	5
Condensed Consolidated Statements of Changes in Stockholders’ Equity for the Three Months Ended March 31, 2018 and 2017 (unaudited)	6
Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2018 and 2017 (unaudited)	7
Notes to the Unaudited Condensed Consolidated Financial Statements	8
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3. Quantitative and Qualitative Disclosures About Market Risk	37
Item 4. Controls and Procedures	38
PART II — OTHER INFORMATION
Item 1. Legal Proceedings	39
Item 1A. Risk Factors	39
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	39
Item 3. Defaults upon Senior Securities	39
Item 4. Mine Safety Disclosures	39
Item 5. Other Information	39
Item 6. Exhibits	39
EXHIBIT INDEX	40
SIGNATURES	41

 

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GLOSSARY OF OIL AND NATURAL GAS TERMS

 

Bbl:   One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to oil, condensate or natural gas liquids.

 

Boe:   Barrels of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.

 

Boe/day:   Barrels of oil equivalent per day.

 

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

 

Dry hole:   A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production do not exceed production expenses and taxes.

 

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 natural gas or oil in another reservoir.

 

MMBoe:   One million barrels of oil equivalent.

 

MMBtu:   One million British thermal units.

 

Net acres:   The percentage of total acres an owner has out of a particular number of acres, or a specified tract.

 

NYMEX:   The New York Mercantile Exchange.

 

Proved reserves:   Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to drill or operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

 

Reasonable certainty:   A high degree of confidence.

 

Recompletion:   The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish, re-establishing, or increase existing production.

 

Reserves:   Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible as of a given date by application of development projects to known accumulations.

 

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.

 

Spud or Spudding:   The commencement of drilling operations of a new well.

 

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

 

Working interest:   The right granted to the lessee of a property to explore for and to produce and own oil, natural gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on a cash, penalty, or carried basis.

 

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PART I — FINANCIAL INFORMATION

MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In thousands, except share amounts)

 

		March 31, 2018			December 31, 2017
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	8,428		$	68,498
Accounts receivable:
Oil and gas sales		30,467			32,455
Joint interest billing		3,691			3,297
Other		259			166
Commodity derivative contracts		—			762
Other current assets		3,124			1,510
Total current assets		45,969			106,688
PROPERTY AND EQUIPMENT:
Oil and gas properties, on the basis of full-cost accounting
Proved properties		798,593			765,308
Unproved properties not being amortized		7,142			7,065
Other property and equipment		6,502			6,508
Less accumulated depreciation, depletion, amortization and impairment		(219,590		)	(204,419		)
Net property and equipment		592,647			574,462
OTHER NONCURRENT ASSETS		7,006			6,978
TOTAL		$	645,622		$	688,128
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable		$	6,652		$	11,547
Accrued liabilities		45,533			42,842
Commodity derivative contracts		6,062			3,433
Total current liabilities		58,247			57,822
LONG-TERM LIABILITIES:
Asset retirement obligations		15,853			15,506
Commodity derivative contracts		950			562
Long-term debt		78,059			128,059
Other long-term liabilities		585			592
Total long-term liabilities		95,447			144,719
COMMITMENTS AND CONTINGENCIES (Note 14)
STOCKHOLDERS’ EQUITY:
Preferred stock, $0.01 par value, 50,000,000 shares authorized; no shares issued or outstanding at March 31, 2018 and December 31, 2017		—			—
Warrants, 6,625,554 warrants outstanding at March 31, 2018 and December 31, 2017		37,329			37,329
Common stock, $0.01 par value, 250,000,000 shares authorized; 25,383,854 shares issued and 25,255,485 shares outstanding at March 31, 2018; 25,272,969 shares issued and 25,173,346 shares outstanding at December 31, 2017		254			253
Treasury stock		(2,062		)	(1,603		)
Additional paid-in-capital		527,550			524,755
Retained deficit		(71,143		)	(75,147		)
Total stockholders’ equity		491,928			485,587
TOTAL		$	645,622		$	688,128

 

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

 

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MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per share amounts)

 

		For the Three Months Ended March 31,
		2018			2017
REVENUES:
Oil sales		$	32,414		$	31,036
Natural gas liquid sales		11,038			11,194
Natural gas sales		8,337			17,098
Other revenue		1,055			822
Total revenue from contracts with customers		52,844			60,150
Gains (losses) on commodity derivative contracts—net		(3,939		)	4,865
Total revenues		48,905			65,015
EXPENSES:
Lease operating and workover		14,808			15,852
Gathering and transportation (Note 3)		57			3,687
Severance and other taxes		2,861			2,121
Asset retirement accretion		297			276
Depreciation, depletion, and amortization		15,213			15,342
General and administrative		9,857			8,275
Total expenses		43,093			45,553
OPERATING INCOME		5,812			19,462
OTHER EXPENSE:
Interest income		19			—
Interest expense—net of amounts capitalized		(1,827		)	(977		)
Total other expense		(1,808		)	(977		)
INCOME BEFORE TAXES		4,004			18,485
Income tax expense		—			—
NET INCOME		$	4,004		$	18,485
Participating securities—non-vested restricted stock		(99		)	(546		)
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS		$	3,905		$	17,939
Basic and diluted net income per share attributable to common shareholders		$	0.15		$	0.72
Basic and diluted weighted average number of common shares outstanding (Note 12)		25,299			25,012

 

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

 

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MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(Unaudited)

(In thousands)

 

		Series A Preferred Stock			Common Stock			Warrants			Treasury Stock			Additional Paid-in-Capital			Retained Deficit			Total Stockholders’ Equity
Balance as of December 31, 2017		$	—		$	253		$	37,329		$	(1,603	)	$	524,755		$	(75,147	)	$	485,587
Share-based compensation		—			1			—			—			2,795			—			2,796
Acquisition of treasury stock		—			—			—			(459		)	—			—			(459		)
Net income		—			—			—			—			—			4,004			4,004
Balance as of March 31, 2018		$	—		$	254		$	37,329		$	(2,062	)	$	527,550		$	(71,143	)	$	491,928

 

		Series A Preferred Stock			Common Stock			Warrants			Treasury Stock			Additional Paid-in-Capital			Retained Earnings			Total Stockholders’ Equity
Balance as of December 31, 2016		$	—		$	250		$	37,329		$	—		$	514,305		$	9,930		$	561,814
Share-based compensation		—			—			—			—			3,790			—			3,790
Acquisition of treasury stock		—			—			—			—			—			—			—
Net income		—			—			—			—			—			18,485			18,485
Balance as of March 31, 2017		$	—		$	250		$	37,329		$	—		$	518,095		$	28,415		$	584,089

 

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

 

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MIDSTATES PETROLEUM COMPANY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

 

		For the Three Months Ended March 31,
		2018			2017
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	4,004		$	18,485
Adjustments to reconcile net income to net cash provided by operating activities: (Gains) losses on commodity derivative contracts—net		3,939			(4,865		)
Net cash received (paid) for commodity derivative contracts not designated as hedging instruments		(160		)	811
Asset retirement accretion		297			276
Depreciation, depletion, and amortization		15,213			15,342
Share-based compensation, net of amounts capitalized to oil and gas properties		2,210			3,337
Amortization of deferred financing costs		108			80
Change in operating assets and liabilities:
Accounts receivable—oil and gas sales		1,293			2,812
Accounts receivable—JIB and other		(663		)	(842		)
Other current and noncurrent assets		(1,750		)	(656		)
Accounts payable		(1,467		)	1,279
Accrued liabilities		(869		)	(3,649		)
Other		(8		)	(37		)
Net cash provided by operating activities		$	22,147		$	32,373
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in property and equipment		$	(31,758	)	$	(26,108	)
Proceeds from the sale of oil and gas equipment		—			1,350
Net cash used in investing activities		$	(31,758	)	$	(24,758	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayment of revolving credit facility		$	(50,000	)	$	—
Repurchase of restricted stock for tax withholdings		(459		)	—
Net cash used in financing activities		$	(50,459	)	$	—
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		$	(60,070	)	$	7,615
Cash and cash equivalents, beginning of period		$	68,498		$	76,838
Cash and cash equivalents, end of period		$	8,428		$	84,453
SUPPLEMENTAL INFORMATION:
Non-cash transactions — investments in property and equipment accrued — not paid		$	18,508		$	17,440
Cash paid for interest, net of capitalized interest of $0.1 million and $0.9 million, respectively		$	1,785		$	937

 

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

 

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MIDSTATES PETROLEUM COMPANY, INC.

Notes to Unaudited Condensed Consolidated Financial Statements

 

1. Organization and Business

 

Midstates Petroleum Company, Inc. engages in the business of exploring and drilling for, and the production of, oil, natural gas liquids (“NGLs”) and natural gas in Oklahoma and Texas. Midstates Petroleum Company, Inc. was incorporated pursuant to the laws of the State of Delaware on October 25, 2011 to become a holding company for Midstates Petroleum Company LLC (“Midstates Sub”). The terms “Company,” “we,” “us,” “our,” and similar terms refer to Midstates Petroleum Company, Inc. and its subsidiary.

 

The Company conducts oil and gas operations and owns and operates oil and natural gas properties in Oklahoma and Texas. The Company operates a significant portion of its oil and natural gas properties. The Company’s management evaluates performance based on one reportable segment as all of its operations are located in the United States and, therefore, it maintains one cost center.

 

2. Summary of Significant Accounting Policies

 

Basis of Presentation

 

These interim financial statements are unaudited and have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) regarding interim financial reporting. Certain disclosures have been condensed or omitted from these financial statements. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America (“US GAAP”) for complete consolidated financial statements, and should be read in conjunction with the audited consolidated financial statements and notes thereto for the year ended December 31, 2017 included in the Company’s Annual Report on Form 10-K as filed with the SEC on March 14, 2018.

 

All intercompany transactions have been eliminated in consolidation. In the opinion of the Company’s management, the accompanying unaudited condensed consolidated financial statements include all adjustments, consisting of normal recurring adjustments, necessary to fairly present the financial position as of, and the results of operations for, all periods presented. In preparing the accompanying unaudited condensed consolidated financial statements, management has made certain estimates and assumptions that affect reported amounts in the unaudited condensed consolidated financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.

 

As a result of the adoption of Accounting Standards Update 2014-09,  “Revenue from Contracts with Customers (Topic 606) ” (“ASU 2014-09”), certain balances included in the unaudited condensed consolidated statements of operations for prior periods have been reclassified to conform to the 2018 presentation. These reclassifications had no impact on net income, cash flows or stockholders’ equity for any period presented.

 

Recent Accounting Pronouncements Adopted During the Period

 

In March 2018, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2018-05, “Income Taxes (Topic 740), Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118” (“ASU 2018-05”). ASU 2018-05 amends certain SEC paragraphs pursuant to the issuance of the December 2017 SEC Staff Accounting Bulletin No. 118,  Income Tax Accounting Implications of the Tax Cuts and Jobs Act (“SAB 118”), which provides guidance on accounting for the tax effects of the Tax Cuts and Jobs Act (“the Tax Act”). SAB 118 provides a measurement period that should not extend beyond one year from the Tax Act’s enactment date for companies to complete its accounting under FASB Accounting Standards Codification (“ASC”) 740. In accordance with SAB 118, to the extent a company has not completed its analysis of the Tax Act but can provide a reasonable estimate, it must record a provisional estimate in its financial statements. The Company has accounted for certain tax effects of the Tax Act under the guidance of SAB 118, on a provisional basis. The Company’s accounting for certain income tax effects is incomplete due to forthcoming guidance and the ongoing analysis of final year-end data and tax positions. The Company expects to complete its analysis within the measurement period in accordance with SAB 118.

 

In August 2016, the FASB issued Accounting Standards Update 2016-15, “ Statement of Cash Flows — Classification of Certain Cash Receipts and Cash Payments”  (“ASU 2016-15”). ASU 2016-15 addresses eight specific cash flow issues with the objective of reducing existing diversity of practice. The eight specific cash flow issues contained within ASU 2016-15 are debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions and separately identifiable cash flows and application of the predominance principle. ASU 2016-15 is effective for the Company for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The adoption of ASU 2016-15 did not have a material impact on our statements of cash flows.

 

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In May 2014, the FASB issued ASU 2014-09. ASU 2014-09 provides guidance concerning the recognition and measurement of revenue from contracts with customers. The objective of ASU 2014-09 is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. The Company adopted ASU 2014-09 using the modified retrospective approach. The adoption of this guidance did not have a material impact on the Company’s financial statements. See Note 3 below for further details.

 

Recent Accounting Pronouncements Issued But Not Yet Adopted

 

In July 2017, the FASB issued Accounting Standards Update 2017-11, “ Earnings Per Share (Topic 260), Distinguishing Liabilities from Equity (Topic 480), and Derivatives and Hedging (Topic 815) ” (“ASU 2017-11”). ASU 2017-11 changes the classification analysis of certain equity-linked financial instruments (or embedded features) with down round features. The amendments require entities that present earnings per share (“EPS”) in accordance with Topic 260 to recognize the effect of the down round feature when triggered with the effect treated as a dividend and as a reduction of income available to common shareholders in basic EPS. The new standard is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company does not believe the adoption of ASU 2017-11 will have a material impact on its financial position, results of operations or cash flows.

 

In February 2016, the FASB issued Accounting Standards Update 2016-02,  “Leases (Topic 842)”  (“ASU 2016-02”). ASU 2016-02 establishes a right-of-use (“ROU”) model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. All leases create an asset and a liability for the lessee and therefore recognition of those lease assets and lease liabilities is required by ASU 2016-02. When measuring lease assets and liabilities, payments to be made in optional extension periods should be included if the lessee is reasonably certain to exercise the option. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement.

 

For finance leases, the Company will recognize a ROU asset and liability, initially measured at the present value of the lease payments. Interest expense will be recognized on the lease liability separately from the amortization of the ROU asset. The Company will recognize payments of principal on the lease liability within financing activities in the consolidated statement of cash flows and payments of interest within operating activities in the consolidated statement of cash flows. For operating leases, the Company will recognize a ROU asset and liability, initially measured at the present value of the lease payments. The Company will recognize a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a generally straight-line basis and all cash payments will be recognized in operating activities within the consolidated statement of cash flows.

 

In January 2018, the FASB issued Accounting Standards Update 2018-01, “ Leases (Topic 842)-Land Easement Practical Expedient for Transition to Topic 842 ” (“ASU 2018-01”). ASU 2018-01 permits an entity to elect an optional transition practical expedient to not evaluate land easements that exist or expired prior to a company’s adoption of ASU 2016-02 and that were not accounted for as leases under previous lease guidance. The new standard is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. A modified retrospective transition approach is required for lessees for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available.

 

The Company is in the initial evaluation stage for ASU 2016-02 and related interpretations and guidance. The Company cannot reasonably quantify the impact of adoption at this time and expects to complete the assessment of ASU 2016-02 during the fourth quarter of 2018.

 

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3. Impact of ASC 606 Adoption

 

On January 1, 2018, the Company adopted ASC 606, Revenue from Contracts with Customers (“ASC 606”) using the modified retrospective method of transition. ASC 606 supersedes previous revenue recognition requirements in ASC 605, Revenue Recognition (“ASC 605”) and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services.

 

The impact of adoption on the Company’s current period results is as follows (in thousands):

 

		Three Months Ended March 31, 2018
		Under ASC 606			Under ASC 605			Increase/(Decrease)
Revenues :
Oil sales		$	32,414		$	32,424		$	(10	)
Natural gas liquid sales		11,038			11,065			(27		)
Natural gas sales		8,337			11,400			(3,063		)
Gathering and transportation		57			3,070			(3,013		)
Lease operating and workover expense		14,808			14,895			(87		)
Net income		$	4,004		$	4,004		$	—
Retained deficit		$	(71,143	)	$	(71,143	)	$	—

 

The primary impact to the Company’s revenues as a result of the adoption of ASC 606 is the netting of certain deductions and costs against revenue instead of its historical practice of presenting such expenses gross in gathering and transportation. These changes are due to analysis of the control model in ASC 606. Further discussion of the Company’s revenue recognition under ASC 606 is included below.

 

Revenue Recognition

 

Oil, NGLs and natural gas revenues are recognized at the point in time that control of the product is transferred to the customer and collectability is reasonably assured. Other revenue consists of iodine royalty income, which are point in time sales, and salt water disposal income, which is recognized over time. A more detailed summary of the underlying contracts that give rise to revenue and the method of recognition is included below.

 

Natural Gas and NGLs Sales

 

Under the Company’s gas processing contracts, it delivers natural gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity processes the natural gas, sells the resulting NGLs and residue gas to third-parties and pays the Company for the NGLs and residue gas. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. For those contracts that the Company concluded that it was the principal, the ultimate third party is the customer, and it recognizes revenue on a gross basis, with gathering, compression, processing, and transportation fees presented as an expense. Alternatively, for those contracts that the Company has concluded that it is the agent, the purchaser is its customer, and it recognizes revenue based on the net amount of the proceeds received from the purchaser.

 

Oil Sales

 

Under the Company’s oil sales contracts, it delivers all or a specified percentage of the crude oil production from specified leases to the purchaser at the wellhead. The Company sells oil production at the wellhead and collect an agreed-upon index price, net of applicable transport costs. The Company recognizes revenue when control transfers to the purchaser at the wellhead at the net price received.

 

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Other Revenue

 

Other revenue consists of fees charged to outside working interest owners for salt water disposal as well as royalties received from a third-party for iodine extracted from the Company’s salt water. Salt water disposal revenue is recognized over time because the customer simultaneously receives and consumes the benefit of the salt water disposal service as the service is provided. For salt water disposal income the Company utilized the practical expedient in ASC 606-10-55-18 that states that if an entity has a right to consideration from a customer in an amount that corresponds directly with the value to the customer of the entity’s performance completed to date, the entity may recognize revenue in the amount to which the entity has a right to invoice. Iodine royalty revenue is recognized point-in-time when control transfers to the customer.

 

Imbalances

 

The Company recognizes revenue for all oil, NGLs and natural gas sold to purchasers regardless of whether the sales are proportionate to the Company’s ownership interest in the property. Production imbalances are recognized as a liability to the extent an imbalance on a specific property exceeds the Company’s share of remaining proved oil and gas reserves. The Company had no significant imbalances at March 31, 2018 or December 31, 2017.

 

Significant Judgments

 

Principal versus agent

 

The Company engages in various types of transactions in which midstream entities process its wet gas and, in some scenarios, subsequently market resulting NGLs and residue gas to third-party customers on its behalf, such as its percentage-of-proceeds and gas purchase contracts. These types of transactions require judgment to determine whether the Company is the principal or the agent in the contract and, as a result, whether revenues are recorded gross or net. The Company analyzed control under ASC 606 and determined for those contracts where control passes at the wellhead, the Company acts as agent and revenue should be recognized net of amounts paid after such control passed for costs such as gathering, compression, processing and transportation, among others. The determination of control and the presentation of revenues was completed for ASC 606 purposes only. Amounts paid by the Company for royalties are calculated under a different methodology and may differ from the amount of revenues recognized under ASC 606.

 

Transaction price allocated to remaining performance obligations

 

A significant number of the Company’s product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient in ASC 606-10-50-14 that exempts it from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

 

For the Company’s product sales that have a contract term greater than one year,  it has utilized the practical expedient in ASC 606-10-50-14A that states it is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

 

For salt water disposal income, the Company has utilized the practical expedient in ASC 606-10-50-14 that states that if it recognizes revenue from the satisfaction of the performance obligation in accordance with the right to invoice practical expedient then it is exempted from disclosure of the transaction price allocated to remaining performance obligations.

 

Prior-period performance obligations

 

The Company records revenue in the month production is delivered and control passes to the customer. However settlement statements and payment may not be received for 30 to 90 days after the date production occurs, and as a result, the Company is required to estimate the amount of production that was delivered and the price that will be received for the sale of the product. The Company utilizes its knowledge of the properties, its historical performance, the anticipated effect of weather conditions during the month of production, NYMEX and local spot market prices and other pertinent factors as the basis for these estimates. The Company records the variances between its estimates and the actual amounts received in the month payment is received and such variances have historically not been significant. For the three months ended March 31, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

 

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4. Fair Value Measurements of Financial Instruments

 

Assets and Liabilities Measured at Fair Value on a Recurring Basis

 

Derivative Instruments

 

Commodity derivative contracts reflected in the unaudited condensed consolidated balance sheets are recorded at estimated fair value. At March 31, 2018, all of the Company’s commodity derivative contracts were with four bank counterparties and were classified as Level 2 in the fair value input hierarchy. The fair value of the Company’s commodity derivatives are determined using industry-standard models that consider various assumptions including current market and contractual prices for the underlying instruments, implied volatility, time value, nonperformance risk, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data.

 

Derivative instruments listed below are presented gross and include swaps and collars that are carried at fair value. The Company records the net change in the fair value of these positions in gains (losses) on commodity derivative contracts — net in the Company’s unaudited condensed consolidated statements of operations.

 

		Fair Value Measurements at March 31, 2018
					Significant Other			Significant
		Quoted Prices in Active Markets (Level 1)			Observable Inputs (Level 2)			Unobservable Inputs (Level 3)			Total
		(in thousands)
Derivative Assets:
Commodity derivative oil swaps		$	—		$	2		$	—		$	2
Commodity derivative gas swaps		$	—		$	74		$	—		$	74
Commodity derivative oil collars		$	—		$	4,764		$	—		$	4,764
Commodity derivative gas collars		$	—		$	1,415		$	—		$	1,415
Total assets		$	—		$	6,255		$	—		$	6,255
Derivative Liabilities:
Commodity derivative oil swaps		$	—		$	(4,293	)	$	—		$	(4,293	)
Commodity derivative gas swaps		$	—		$	(205	)	$	—		$	(205	)
Commodity derivative oil collars		$	—		$	(8,208	)	$	—		$	(8,208	)
Commodity derivative gas collars		$	—		$	(561	)	$	—		$	(561	)
Total liabilities		$	—		$	(13,267	)	$	—		$	(13,267	)

 

		Fair Value Measurements at December 31, 2017
					Significant Other			Significant
		Quoted Prices in Active Markets (Level 1)			Observable Inputs (Level 2)			Unobservable Inputs (Level 3)			Total
		(in thousands)
Derivative Assets:
Commodity derivative oil swaps		$	—		$	—		$	—		$	—
Commodity derivative gas swaps		$	—		$	821		$	—		$	821
Commodity derivative oil collars		$	—		$	952		$	—		$	952
Commodity derivative gas collars		$	—		$	2,611		$	—		$	2,611
Total assets		$	—		$	4,384		$	—		$	4,384
Derivative Liabilities:
Commodity derivative oil swaps		$	—		$	(3,679	)	$	—		$	(3,679	)
Commodity derivative gas swaps		$	—		$	—		$	—		$	—
Commodity derivative oil collars		$	—		$	(2,605	)	$	—		$	(2,605	)
Commodity derivative gas collars		$	—		$	(1,333	)	$	—		$	(1,333	)
Total liabilities		$	—		$	(7,617	)	$	—		$	(7,617	)

 

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5. Risk Management and Derivative Instruments

 

The Company’s production is exposed to fluctuations in crude oil, NGLs and natural gas prices. The Company believes it is prudent to manage the variability in cash flows by, at times, entering into derivative financial instruments to economically hedge a portion of its crude and natural gas production. The Company utilizes various types of derivative financial instruments, including swaps and collars, to manage fluctuations in cash flows resulting from changes in commodity prices.

 

·                   Swaps: The Company receives or pays a fixed price for the commodity and pays or receives a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

 

·                   Three-way collars: A three-way collar contains a fixed floor price (long put), fixed sub-floor price (short put), and a fixed ceiling price (short call). If the market price exceeds the ceiling strike price, the Company receives the ceiling strike price and pays the market price. If the market price is between the ceiling and the floor strike price, no payments are due from either party. If the market price is below the floor price but above the sub-floor price, the Company receives the floor strike price and pays the market price. If the market price is below the sub-floor price, the Company receives the market price plus the difference between the floor and the sub-floor strike prices and pays the market price.

 

These derivative contracts are placed with major financial institutions that the Company believes are minimal credit risks. The crude oil and natural gas reference prices upon which the commodity derivative contracts are based reflect various market indices that management believes correlates with actual prices received by the Company for its crude and natural gas production.

 

Inherent in the Company’s portfolio of commodity derivative contracts are certain business risks, including market risk and credit risk. Market risk is the risk that the price of the commodity will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the Company’s counterparty to a contract. The Company does not require collateral from its counterparties but does attempt to minimize its credit risk associated with derivative instruments by entering into derivative instruments only with counterparties that are large financial institutions, which management believes present minimal credit risk. In addition, to mitigate its risk of loss due to default, the Company has entered into agreements with its counterparties on its derivative instruments that allow the Company to offset its asset position with its liability position in the event of default by the counterparty. Due to the netting arrangements, had the Company’s counterparties failed to perform under existing commodity derivative contracts at March 31, 2018, the Company would not have experienced a loss.

 

Commodity Derivative Contracts

 

The Company entered into various oil and natural gas derivative contracts that extend through December 31, 2020, summarized as follows:

 

		NYMEX WTI
		Fixed Swaps					Three-Way Collars
		Hedge Position (Bbls)		Weighted Avg Strike Price			Hedge Position (Bbls)		Weighted Avg Ceiling Price			Weighted Avg Floor Price			Weighted Avg Sub-Floor Price
Quarter Ended:
March 31, 2018(1)		99,000		$	50.61		225,000		$	62.14		$	50.00		$	40.00
June 30, 2018(1)		154,750		$	51.97		182,000		$	60.65		$	50.00		$	40.00
September 30, 2018(1)		151,800		$	55.23		184,000		$	59.93		$	50.00		$	40.00
December 31, 2018(1)		289,800		$	57.79		46,000		$	56.70		$	50.00		$	40.00
March 31, 2019(1)		—		$	—		180,000		$	63.14		$	53.75		$	43.75
June 30, 2019(1)		—		$	—		182,000		$	63.14		$	53.75		$	43.75
September 30, 2019(1)		—		$	—		184,000		$	63.14		$	53.75		$	43.75
December 31, 2019(1)		—		$	—		184,000		$	63.14		$	53.75		$	43.75
March 31, 2020(1)		—		$	—		91,000		$	65.75		$	50.00		$	40.00
June 30, 2020(1)		—		$	—		91,000		$	65.75		$	50.00		$	40.00
September 30, 2020(1)		—		$	—		92,000		$	65.75		$	50.00		$	40.00
December 31, 2020(1)		—		$	—		92,000		$	65.75		$	50.00		$	40.00

 

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		NYMEX HENRY HUB
		Fixed Swaps					Three-Way Collars
		Hedge Position (MMBtu)		Weighted Avg Strike Price			Hedge Position (MMBtu)		Weighted Avg Ceiling Price			Weighted Avg Floor Price			Weighted Avg Sub-Floor Price
Quarter Ended:
March 31, 2018(1)(2)		1,350,000		$	3.47		1,530,000		$	4.38		$	3.25		$	2.50
June 30, 2018(1)		915,000		$	2.79		1,365,000		$	3.40		$	3.00		$	2.50
September 30, 2018(1)		1,380,000		$	2.79		1,380,000		$	3.40		$	3.00		$	2.50
December 31, 2018(1)		1,380,000		$	2.91		1,380,000		$	3.40		$	3.00		$	2.50
March 31, 2019(1)		1,350,000		$	2.98		1,350,000		$	3.40		$	3.00		$	2.50

 

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(1)           Positions shown represent open commodity derivative contract positions as of March 31, 2018.

(2)           During the second quarter of 2017, the Company entered into natural gas three-way collars with long call ceilings in order to offset its Q1 2018 natural gas fixed swaps.

 

Balance Sheet Presentation

 

The following table summarizes the net fair values of commodity derivative instruments by the appropriate balance sheet classification in the Company’s unaudited condensed consolidated balance sheets for the periods presented (in thousands):

 

Type		Balance Sheet Location (1)		March 31, 2018			December 31, 2017
Gas swaps		Derivative financial instruments — current assets		$	—		$	821
Oil collars		Derivative financial instruments — current assets		—			(760		)
Gas collars		Derivative financial instruments — current assets		—			701
Total derivative financial instruments — current assets				$	—		$	762
Oil swaps		Derivative financial instruments — current liabilities		$	(4,291	)	$	(3,679	)
Gas swaps		Derivative financial instruments — current liabilities		(131		)	—
Oil collars		Derivative financial instruments — current liabilities		(2,494		)	(370		)
Gas collars		Derivative financial instruments — current liabilities		854			616
Total derivative financial instruments — current liabilities				$	(6,062	)	$	(3,433	)
Oil collars		Derivative financial instruments — noncurrent liabilities		$	(950	)	$	(523	)
Gas collars		Derivative financial instruments — noncurrent liabilities		—			(39		)
Total derivative financial instruments — noncurrent liabilities				$	(950	)	$	(562	)
Total derivative fair value at period end				$	(7,012	)	$	(3,233	)

 

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(1)           The fair values of commodity derivative instruments reported in the Company’s unaudited condensed consolidated balance sheets are subject to netting arrangements and qualify for net presentation.

 

The following table summarizes the location and fair value amounts of all commodity derivative instruments in the unaudited condensed consolidated balance sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the unaudited condensed consolidated balance sheets for the periods presented (in thousands):

 

				March 31, 2018
Not Designated as				Gross Recognized			Gross Amounts			Net Recognized Fair Value
ASC 815 Hedges		Balance Sheet Location Classification		Assets/Liabilities			Offset			Assets/Liabilities
Derivative Assets:
Commodity contracts		Derivative financial instruments — current		$	2,134		$	(2,134	)	$	—
Commodity contracts		Derivative financial instruments — noncurrent		4,121			(4,121		)	—
				$	6,255		$	(6,255	)	$	—
Derivative Liabilities:
Commodity contracts		Derivative financial instruments — current		$	(8,196	)	$	2,134		$	(6,062	)
Commodity contracts		Derivative financial instruments — noncurrent		(5,071		)	4,121			(950		)
				$	(13,267	)	$	6,255		$	(7,012	)

 

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