Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For The Quarterly Period Ended September 30, 2019

☐ 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 001-14039

Callon Petroleum Company



	(Exact Name of Registrant as Specified in Its Charter)



Delaware		64-0844345
State or Other Jurisdiction of Incorporation or Organization		I.R.S. Employer Identification No.

One Briarlake Plaza
2000 W. Sam Houston Parkway S., Suite 2000
Houston,	Texas	77042
Address of Principal Executive Offices		Zip Code



	(281)		589-5200
	Registrant’s Telephone Number, Including Area Code

	Former Name, Former Address and Former Fiscal Year, if Changed Since Last Report

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



Title of Each Class	Trading Symbol(s)	Name of Each Exchange on Which Registered
Common Stock, $0.01 par value	CPE	New York Stock Exchange

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

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



Large accelerated filer	☒	Accelerated filer	☐

Non-accelerated filer	☐	Smaller reporting company	☐

		Emerging growth company	☐

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

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

The Registrant had 228,386,100 shares of common stock outstanding as of November 1, 2019.

Table of Contents



Part I. Financial Information

Item 1. Financial Statements (Unaudited)

Consolidated Balance Sheets	4

Consolidated Statements of Operations	5

Consolidated Statements of Cash Flows	6

Consolidated Statements of Stockholders’ Equity	7

Notes to 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	34

Item 4. Controls and Procedures	35

Part II. Other Information

Item 1. Legal Proceedings	36

Item 1A. Risk Factors	36

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	36

Item 3. Defaults Upon Senior Securities	36

Item 4. Mine Safety Disclosures	36

Item 5. Other Information	36

Item 6. Exhibits	37

GLOSSARY OF CERTAIN TERMS

All defined terms under Rule 4-10(a) of Regulation S-X shall have their prescribed meanings when used in this report. As used in this document:


•	ARO: asset retirement obligation.


•	ASU: accounting standards update.


•	Bbl or Bbls: barrel or barrels of oil or natural gas liquids.

•

BOE: barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas. The ratio of one barrel of oil or NGL to six Mcf of natural gas is commonly used in the industry and represents the approximate energy equivalence of oil or NGLs to natural gas, and does not represent the economic equivalency of oil and NGLs to natural gas. The sales price of a barrel of oil or NGLs is considerably higher than the sales price of six Mcf of natural gas.


•	BOE/d: BOE per day.


•	Btu: a British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water 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.


•	Cushing: An oil delivery point that serves as the benchmark oil price for West Texas Intermediate.


•	FASB: Financial Accounting Standards Board.


•	GAAP: Generally Accepted Accounting Principles in the United States.


•	Henry Hub: A natural gas pipeline delivery point that serves as the benchmark natural gas price underlying NYMEX natural gas futures contracts.


•	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.


•	LIBOR: London Interbank Offered Rate.


•	LOE: lease operating expense.


•	MBbls: thousand barrels of oil.


•	MBOE: thousand BOE.


•	Mcf: thousand cubic feet of natural gas.


•	MEH: Magellan East Houston, a delivery point in Houston, Texas that serves as a benchmark for crude oil.


•	MMBtu: million Btu.


•	MMcf: million cubic feet of natural gas.


•	NGL or NGLs: natural gas liquids, such as ethane, propane, butanes and natural gasoline that are extracted from natural gas production streams.


•	NYMEX: New York Mercantile Exchange.


•	Oil: includes crude oil and condensate.


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


•	Royalty interest: An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development.


•	RSU: restricted stock units.


•	SEC: United States Securities and Exchange Commission.


•	Waha: A delivery point in West Texas that serves as the benchmark for natural gas.


•	Working interest: An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.


•	WTI: West Texas Intermediate grade crude oil, used as a pricing benchmark for sales contracts and NYMEX oil futures contracts.

With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross.

Part I. Financial Information

Item 1. Financial Statements

Callon Petroleum Company

Consolidated Balance Sheets

(in thousands, except par and share data)



	September 30, 2019			December 31, 2018
ASSETS	Unaudited
Current assets:
Cash and cash equivalents	$	11,309		$	16,051
Accounts receivable	114,120			131,720
Fair value of derivatives	25,032			65,114
Other current assets	14,912			9,740
Total current assets	165,373			222,625
Oil and natural gas properties, full cost accounting method:
Evaluated properties	4,830,499			4,585,020
Less accumulated depreciation, depletion, amortization and impairment	(2,458,026		)	(2,270,675		)
Evaluated oil and natural gas properties, net	2,372,473			2,314,345
Unevaluated properties	1,405,993			1,404,513
Total oil and natural gas properties, net	3,778,466			3,718,858
Operating lease right-of-use assets	24,447			—
Other property and equipment, net	24,770			21,901
Restricted investments	3,490			3,424
Deferred financing costs	5,081			6,087
Fair value of derivatives	11,209			—
Other assets, net	4,087			6,278
Total assets	$	4,016,923		$	3,979,173
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	243,481		$	261,184
Operating lease liabilities	19,196			—
Accrued interest	25,660			24,665
Cash-settleable restricted stock unit awards	535			1,390
Asset retirement obligations	1,250			3,887
Fair value of derivatives	8,941			10,480
Other current liabilities	1,948			13,310
Total current liabilities	301,011			314,916
Senior secured revolving credit facility	200,000			200,000
6.125% senior unsecured notes due 2024	596,337			595,788
6.375% senior unsecured notes due 2026	394,317			393,685
Operating lease liabilities	4,995			—
Asset retirement obligations	8,294			10,405
Cash-settleable restricted stock unit awards	1,737			2,067
Deferred tax liability	39,007			9,564
Fair value of derivatives	2,573			7,440
Other long-term liabilities	—			100
Total liabilities	1,548,271			1,533,965
Commitments and contingencies
Stockholders’ equity:
Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized; 0 and 1,458,948 shares outstanding, respectively	—			15
Common stock, $0.01 par value, 300,000,000 shares authorized; 228,372,081 and 227,582,575 shares outstanding, respectively	2,284			2,276
Capital in excess of par value	2,421,559			2,477,278
Retained earnings (accumulated deficit)	44,809			(34,361		)
Total stockholders’ equity	2,468,652			2,445,208
Total liabilities and stockholders’ equity	$	4,016,923		$	3,979,173

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

Callon Petroleum Company

Consolidated Statements of Operations

(Unaudited; in thousands, except per share data)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Operating revenues:
Oil sales	$	148,210		$	142,601		$	450,036		$	380,500
Natural gas sales	7,168			18,613			25,441			45,229
Total operating revenues	155,378			161,214			475,477			425,729
Operating expenses:
Lease operating expenses	19,668			18,525			66,511			44,705
Production taxes	11,866			10,263			33,810			26,265
Depreciation, depletion and amortization	56,002			48,257			178,690			122,407
General and administrative	9,388			9,721			31,705			26,779
Merger and integration expense	5,943			—			5,943			—
Settled share-based awards	—			—			3,024			—
Accretion expense	128			202			585			626
Other operating expense	(161		)	1,435			931			3,750
Total operating expenses	102,834			88,403			321,199			224,532
Income from operations	52,544			72,811			154,278			201,197
Other (income) expenses:
Interest expense, net of capitalized amounts	739			711			2,218			1,765
(Gain) loss on derivative contracts	(21,809		)	34,339			31,415			55,374
Other income	(122		)	(1,657		)	(270		)	(2,571		)
Total other (income) expense	(21,192		)	33,393			33,363			54,568
Income before income taxes	73,736			39,418			120,915			146,629
Income tax expense	17,902			1,487			29,444			2,463
Net income	55,834			37,931			91,471			144,166
Preferred stock dividends	(350		)	(1,823		)	(3,997		)	(5,471		)
Loss on redemption of preferred stock	(8,304		)	—			(8,304		)	—
Income available to common stockholders	$	47,180		$	36,108		$	79,170		$	138,695
Income per common share:
Basic	$	0.21		$	0.16		$	0.35		$	0.65
Diluted	$	0.21		$	0.16		$	0.35		$	0.65
Weighted average common shares outstanding:
Basic	228,322			227,564			228,054			213,409
Diluted	228,469			228,140			228,557			214,079

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

Callon Petroleum Company

Consolidated Statements of Cash Flows

(Unaudited; in thousands)



	Nine Months Ended September 30,
Cash flows from operating activities:	2019			2018
Net income	$	91,471		$	144,166
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization	182,153			124,430
Accretion expense	585			626
Amortization of non-cash debt related items	2,218			1,749
Deferred income tax expense	29,444			2,463
Loss on derivatives, net of settlements	30,979			29,696
(Gain) loss on sale of other property and equipment	36			(80		)
Non-cash expense related to equity share-based awards	7,868			4,466
Change in the fair value of liability share-based awards	106			1,428
Payments to settle asset retirement obligations	(1,425		)	(1,080		)
Payments for cash-settled restricted stock unit awards	(1,425		)	(4,990		)
Changes in current assets and liabilities:
Accounts receivable	17,600			(54,384		)
Other current assets	(5,172		)	(1,665		)
Current liabilities	(13,038		)	64,801
Other	(2,662		)	4,389
Net cash provided by operating activities	338,738			316,015
Cash flows from investing activities:
Capital expenditures	(503,425		)	(455,352		)
Acquisitions	(40,788		)	(595,984		)
Proceeds from sale of assets	279,952			8,326
Net cash used in investing activities	(264,261		)	(1,043,010		)
Cash flows from financing activities:
Borrowings on senior secured revolving credit facility	581,000			270,000
Payments on senior secured revolving credit facility	(581,000		)	(230,000		)
Issuance of 6.375% senior unsecured notes due 2026	—			400,000
Issuance of common stock	—			288,364
Payment of preferred stock dividends	(3,997		)	(5,471		)
Payment of deferred financing costs	(31		)	(9,960		)
Tax withholdings related to restricted stock units	(2,174		)	(1,804		)
Redemption of preferred stock	(73,017		)	—
Net cash provided by (used in) financing activities	(79,219		)	711,129
Net change in cash and cash equivalents	(4,742		)	(15,866		)
Balance, beginning of period	16,051			27,995
Balance, end of period	$	11,309		$	12,129

Supplemental cash flow information:
Interest paid, net of capitalized amounts	$	—		$	—
Income taxes paid	—			—
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	1,667			—
Investing cash flows from operating leases	25,455			—
Non-cash investing and financing activities:
Change in accrued capital expenditures	$	(15,032	)	$	42,062
Change in asset retirement costs	(393		)	4,847
Right-of-use assets obtained in exchange for operating lease liabilities	2,588			—
Contingent consideration arrangement	8,512			—

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

Callon Petroleum Company

Consolidated Statements of Stockholders’ Equity

(Unaudited; in thousands)



												Retained
	Preferred					Common			Capital in			Earnings			Total
	Stock					Stock			Excess			(Accumulated			Stockholders'
	Shares		$			Shares	$		of Par			Deficit)			Equity
Balance at 12/31/2018	1,459		$	15		227,583	$	2,276	$	2,477,278		$	(34,361	)	$	2,445,208
Net loss	—		—			—	—		—			(19,543		)	(19,543		)
Shares issued pursuant to employee benefit plans	—		—			24	—		154			—			154
Restricted stock	—		—			277	3		4,447			—			4,450
Preferred stock dividend ($1.25 per share)	—		—			—	—		—			(1,824		)	(1,824		)
Balance at 03/31/2019	1,459		$	15		227,884	$	2,279	$	2,481,879		$	(55,728	)	$	2,428,445
Net income	—		—			—	—		—			55,180			55,180
Restricted stock	—		—			380	4		2,071			—			2,075
Preferred stock dividend ($1.25 per share)	—		—			—	—		—			(1,823		)	(1,823		)
Preferred stock redemption costs	—		—			—	—		(5		)	—			(5		)
Balance at 06/30/2019	1,459		$	15		228,264	$	2,283	$	2,483,945		$	(2,371	)	$	2,483,872
Net income	—		—			—	—		—			55,834			55,834
Restricted stock	—		—			108	1		2,307			—			2,308
Preferred stock dividend ($0.24 per share)	—		—			—	—		—			(350		)	(350		)
Preferred stock redemption	(1,459	)	(15		)	—	—		(64,693		)	—			(64,708		)
Loss on redemption of preferred stock	—		—			—	—		—			(8,304		)	(8,304		)
Balance at 09/30/2019	—		$	—		228,372	$	2,284	$	2,421,559		$	44,809		$	2,468,652



	Preferred			Common			Capital in					Total
	Stock			Stock			Excess		Accumulated			Stockholders'
	Shares	$		Shares	$		of Par		Deficit			Equity
Balance at 12/31/2017	1,459	$	15	201,836	$	2,018	$	2,181,359	$	(327,426	)	$	1,855,966
Net income	—	—		—	—		—		55,761			55,761
Shares issued pursuant to employee benefit plans	—	—		7	—		88		—			88
Restricted stock	—	—		105	1		1,152		—			1,153
Preferred stock dividend ($1.25 per share)	—	—		—	—		—		(1,824		)	(1,824		)
Balance at 03/31/2018	1,459	$	15	201,948	$	2,019	$	2,182,599	$	(273,489	)	$	1,911,144
Net income	—	—		—	—		—		50,474			50,474
Shares issued pursuant to employee benefit plans	—	—		11	—		141		—			141
Restricted stock	—	—		248	3		1,312		—			1,315
Common stock issued	—	—		25,300	253		288,103		—			288,356
Preferred stock dividend ($1.25 per share)	—	—		—	—		—		(1,824		)	(1,824		)
Balance at 06/30/2018	1,459	$	15	227,507	$	2,275	$	2,472,155	$	(224,837	)	$	2,249,608
Net income	—	—		—	—		—		37,931			37,931
Shares issued pursuant to employee benefit plans	—	—		12	—		131		—			131
Restricted stock	—	—		49	1		2,454		—			2,455
Common stock issued	—	—		—	—		8		—			8
Preferred stock dividend ($1.25 per share)	—	—		—	—		—		(1,823		)	(1,823		)
Balance at 09/30/2018	1,459	$	15	227,568	$	2,276	$	2,474,748	$	(188,731	)	$	2,288,308

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



	Notes to the Consolidated Financial Statements (Unaudited) (All dollar amounts in thousands, except per share and per unit data)

Index to the Notes to the Consolidated Financial Statements



1.	Description of Business and Basis of Presentation	8.	Income Taxes
2.	Revenue Recognition	9.	Equity Transactions
3.	Acquisitions and Dispositions	10.	Leases
4.	Earnings Per Share	11.	Asset Retirement Obligations
5.	Borrowings	12.	Other
6.	Derivative Instruments and Hedging Activities	13.	Carrizo Acquisition
7.	Fair Value Measurements

Note 1 - Description of Business and Basis of Presentation

Description of business

Callon Petroleum Company has been engaged in the development, acquisition and production of oil and natural gas properties since 1950. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise. We were incorporated in the state of Delaware in 1994.

Callon is focused on the acquisition and development of unconventional onshore oil and natural gas reserves in the Permian Basin. The Permian Basin is located in West Texas and southeastern New Mexico and is comprised of three primary sub-basins: the Midland Basin, the Delaware Basin, and the Central Basin Platform. Since our entry into the Permian Basin in late 2009, we have been focused on the Midland Basin and entered the Delaware Basin through an acquisition completed in February 2017. The Company further expanded its presence in the Delaware Basin through acquisitions in 2018.

Basis of presentation

Unless otherwise indicated, all dollar amounts included within the Footnotes to the Financial Statements are presented in thousands, except for per share and per unit data.

The interim consolidated financial statements of the Company have been prepared in accordance with (1) GAAP, (2) the SEC’s instructions to Quarterly Report on Form 10-Q and (3) Rule 10-01 of Regulation S-X, and include the accounts of Callon Petroleum Company, and its subsidiary, Callon Petroleum Operating Company (“CPOC”). CPOC also has a subsidiary, namely Mississippi Marketing, Inc. Effective February 28, 2019, Callon Offshore Production, Inc. was merged with and into CPOC.

These interim consolidated financial statements should be read in conjunction with the Company’s Annual Report on Form 10-K for the year ended December 31, 2018. The balance sheet at December 31, 2018 has been derived from the audited financial statements at that date. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the year ended December 31, 2019.

In the opinion of management, the accompanying unaudited consolidated financial statements reflect all adjustments, including normal recurring adjustments and all intercompany account and transaction eliminations, necessary to present fairly the Company’s financial position, results of operations and cash flows for the periods indicated. Certain prior year amounts have been reclassified to conform to current year presentation.

Accounting Standards Updates (“ASUs”)

Recently adopted ASUs - Leases

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842): Amendments to the FASB Accounting Standards Codification (“ASU 2016-02”). In January 2018, the FASB issued ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842 (“ASU 2018-01”). In July 2018, the FASB issued ASU No. 2018-11, Leases (Topic 842): Targeted Improvements (“ASU 2018-11”). In March 2019, the FASB issued ASU No. 2019-01, Leases (Topic 842): Codification Improvements (“ASU 2019-01”). Together these related amendments to GAAP represent ASC Topic 842, Leases (“ASC Topic 842”).

ASU 2016-02 requires lessees to recognize lease assets and liabilities (with terms in excess of 12 months) on the balance sheet and disclose key quantitative and qualitative information about leasing arrangements. The Company engaged a third-party consultant to assist with assessing its existing contracts, as well as future potential contracts, and to determine the impact of its application on its consolidated financial statements and related disclosures. The contract evaluation process includes review of drilling rig contracts, office facility leases,



	Notes to the Consolidated Financial Statements (Unaudited) (All dollar amounts in thousands, except per share and per unit data)

compressors, field vehicles and equipment, general corporate leased equipment, and other existing arrangements to support its operations that may contain a lease component.

The new standard was effective for us in the first quarter of 2019, and we adopted the new standard using a modified retrospective approach, with the date of initial application on January 1, 2019. Consequently, upon transition, we recognized the cumulative effect of adoption in retained earnings as of January 1, 2019. We further utilized the package of practical expedients at transition to not reassess the following:


•	Whether any expired or existing contracts were or contained leases;


•	The lease classification for any expired or existing leases; and


•	Initial direct costs for any existing leases.

Additionally, we elected the practical expedient under ASU 2018-01, which did not require us to evaluate existing or expired land easements not previously accounted for as leases prior to the effective date. We also chose not to separate lease and non-lease components for the various classes of underlying assets. In addition, for all of our asset classes, we have made an accounting policy election not to apply the lease recognition requirements to our short-term leases. Accordingly, we recognize lease payments related to our short-term leases in profit or loss on a straight-line basis over the lease term.

Through our implementation process, we evaluated each of our lease arrangements and enhanced our systems to track and calculate additional information required upon adoption of this standard. The standard had an impact on our consolidated balance sheet at September 30, 2019, resulting from the recognition during the current period of right-of-use assets and lease liabilities for operating leases. We have no leases that meet the criteria for classification as a finance lease. We lease certain office space, office equipment, production facilities, compressors, drilling rigs, vehicles and other ancillary drilling equipment under cancelable and non-cancelable leases to support our operations. See Note 10 for additional information regarding the impact of adoption of the new leases standard on our current period results.

Adoption of the new leases standard did not impact our consolidated statement of operations or cash provided from or used in operating, investing or financing in our consolidated statement of cash flows.

We note that the standard does not apply to leases to explore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained.

Recently adopted ASUs - Other

In June 2018, the FASB issued ASU No. 2018-07, Compensation - Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting (“ASU 2018-07”). The standard is intended to simplify several aspects of the accounting for nonemployee share-based payment transactions for acquiring goods and services from nonemployees, including the timing and measurement of nonemployee awards. The Company adopted this update on January 1, 2019 and it did not have a material impact on its consolidated financial statements upon adoption of this guidance.

Note 2 - Revenue Recognition

Revenue from contracts with customers

Oil sales

Under the Company’s oil sales contracts it sells oil production at the point of delivery and collects an agreed upon index price, net of pricing differentials. The Company recognizes revenue when control transfers to the purchaser at the point of delivery at the net price received.

Natural gas sales

Under the Company’s natural gas sales processing contracts, it delivers natural gas to a midstream processing entity. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sale of natural gas. The Company’s share of revenue received from the sale of NGLs is included in the natural gas sales. Under these processing agreements, when control of the natural gas changes at the point of delivery, the treatment of gathering and treating fees are recorded net of revenues. Gathering and treating fees have historically been recorded as an expense in lease operating expense in the statement of operations. The Company has modified the presentation of revenues and expenses to include these fees net of operating revenues. For the three and nine months ended September 30, 2019, $2,566 and $7,779 of gathering and treating fees were recognized and recorded as a reduction to natural gas sales in the consolidated statement of operations, respectively. For the three and nine months ended September 30, 2018,



	Notes to the Consolidated Financial Statements (Unaudited) (All dollar amounts in thousands, except per share and per unit data)

$2,209 and $5,413 of gathering and treating fees were recognized and recorded as a reduction to natural gas sales in the consolidated statement of operations, respectively.

Accounts receivable from revenues from contracts with customers

Net accounts receivable include amounts billed and currently due from revenue contracts with customers related to our oil and natural gas production, which had a balance at September 30, 2019 and December 31, 2018 of $83,442 and $87,061, respectively, and does not currently include an allowance for doubtful accounts. Accounts receivable, net, from the sale of oil and natural gas are included in accounts receivable on the consolidated balance sheets.

Transaction price allocated to remaining performance obligations

For the Company’s product sales that have a contract term greater than one year, it has utilized the practical expedient in Accounting Standards Codification 606-10-50-14, which states the Company 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.

Prior period performance obligations

The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant.

Note 3 - Acquisitions and Dispositions

2019 Acquisitions and Dispositions

In the second quarter of 2019, the Company completed its divestiture of certain non-core assets in the southern Midland Basin (the “Ranger Asset Divestiture”) for net cash proceeds received at closing of $244,935, including customary purchase price adjustments. The transaction also provides for potential contingent consideration in payments of up to $60,000 based on West Texas Intermediate average annual pricing over a three-year period (see Notes 6 and 7 for additional information regarding the contingent consideration payments). The divestiture encompasses the Ranger operating area in the southern Midland Basin which includes approximately 9,850 net Wolfcamp acres with an average 66% working interest. The divestiture did not significantly alter the relationship between capitalized costs and proved reserves, and as such, net cash proceeds and contingent consideration were recorded as adjustments to our full cost pool with no gain or loss recognized.

In the first quarter of 2019, the Company completed various acquisitions and dispositions of additional working interests and acreage located in our existing core operating areas within the Permian Basin. The Company purchased mineral rights for $21,407 in the Spur operating area and received proceeds of $14,084, including customary purchase price adjustments, for certain leasehold interests in our WildHorse acreage. In the second quarter of 2019, the Company completed various acreage swaps in the Permian Basin and received proceeds of $19,108, including customary purchase price adjustments, for certain working interests in our Spur acreage.



	Notes to the Consolidated Financial Statements (Unaudited) (All dollar amounts in thousands, except per share and per unit data)

2018 Acquisitions

On August 31, 2018, the Company completed the acquisition of approximately 28,000 net surface acres in the Spur operating area, located in the Delaware Basin, from Cimarex Energy Company, for $539,519, including customary purchase price adjustments (the “Delaware Asset Acquisition”). The Company issued debt and equity to fund, in part, the Delaware Asset Acquisition. See Notes 5 and 9 for additional information regarding the Company’s debt obligations and equity offerings. The following table summarizes the estimated acquisition date fair values of the acquisition:



Evaluated oil and natural gas properties	$	253,089
Unevaluated oil and natural gas properties	287,000
Asset retirement obligations	(570		)
Net assets acquired	$	539,519

In addition, the Company completed various acquisitions of additional working interests and mineral rights, and associated production volumes, in the Company’s existing core operating areas within the Permian Basin. In the first quarter of 2018, the Company completed acquisitions within Monarch and WildHorse operating areas for $37,770, including customary purchase price adjustments. In the fourth quarter of 2018, the Company completed acquisitions of leasehold interests and mineral rights within its WildHorse and Spur operating areas for $87,865, including customary purchase price adjustments.

Note 4 - Earnings Per Share

Basic earnings per share is computed by dividing income available to common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings per share includes the potential dilutive impact of non-vested restricted shares outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is anti-dilutive. The following table sets forth the computation of basic and diluted earnings per share:



(amounts in thousands)	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Net income	$	55,834		$	37,931		$	91,471		$	144,166
Preferred stock dividends	(350		)	(1,823		)	(3,997		)	(5,471		)
Loss on redemption of preferred stock	(8,304		)	—			(8,304		)	—
Income available to common stockholders	$	47,180		$	36,108		$	79,170		$	138,695

Weighted average common shares outstanding	228,322			227,564			228,054			213,409
Dilutive impact of restricted stock	147			576			503			670
Weighted average common shares outstanding for diluted income per share	228,469			228,140			228,557			214,079

Basic income per share	$	0.21		$	0.16		$	0.35		$	0.65
Diluted income per share	$	0.21		$	0.16		$	0.35		$	0.65

Restricted stock ^(a)	1,488			154			829			154


(a)	Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive.



	Notes to the Consolidated Financial Statements (Unaudited) (All dollar amounts in thousands, except per share and per unit data)

Note 5 - Borrowings

The Company’s borrowings consisted of the following:



	As of
Principal components:	September 30, 2019			December 31, 2018
Senior secured revolving credit facility	$	200,000		$	200,000
6.125% senior unsecured notes due 2024	600,000			600,000
6.375% senior unsecured notes due 2026	400,000			400,000
Total principal outstanding	1,200,000			1,200,000
Premium on 6.125% senior unsecured notes due 2024, net of accumulated amortization	5,625			6,469
Unamortized deferred financing costs	(14,971		)	(16,996		)
Total carrying value of borrowings ^(a)	$	1,190,654		$	1,189,473


^(a)	Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $5,081 and $6,087 as of September 30, 2019 and December 31, 2018, respectively.

Senior secured revolving credit facility (the “Credit Facility”)

On May 25, 2017, the Company entered into the Sixth Amended and Restated Credit Agreement to the Credit Facility. JPMorgan Chase Bank, N.A. is Administrative Agent, and participants include 17 institutional lenders. The total notional amount available under the Credit Facility is $2,000,000. Amounts borrowed under the Credit Facility may not exceed the borrowing base, which is generally reviewed on a semi-annual basis. The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties. The maturity date of the Credit Facility is May 25, 2023.

Effective May 1, 2019, the Company entered into the third amendment to the Sixth Amended and Restated Credit Agreement to the Credit Facility to, among other things: (i) reaffirm the borrowing base at $1,100,000, excluding the Ranger assets sold; and (ii) amend various covenants and terms to reflect current market trends. As of September 30, 2019, the Credit Facility’s borrowing base remained at $1,100,000 with an elected commitment amount of $850,000.

As of September 30, 2019, there was $200,000 principal and $17,675 in letters of credit outstanding under the Credit Facility. For the period ended September 30, 2019, the Credit Facility had a weighted-average interest rate of 3.55%, calculated as the LIBOR plus a tiered rate ranging from 1.25% to 2.25%, which is determined based on utilization of the facility. In addition, the Credit Facility carries a current commitment fee of 0.375% per annum, payable quarterly, on the unused portion of the borrowing base.

Restrictive covenants

The Company’s Credit Facility and the indentures governing its senior notes contain various covenants including restrictions on additional indebtedness, payment of cash dividends and maintenance of certain financial ratios. The Company was in compliance with these covenants at September 30, 2019.

Note 6 - Derivative Instruments and Hedging Activities

Objectives and strategies for using commodity derivative instruments

The Company is exposed to fluctuations in oil and natural gas prices received for its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its oil and natural gas production. The Company utilizes a mix of collars, swaps and put and call options to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for speculative or trading purposes.

Counterparty risk and offsetting

The use of derivative instruments exposes the Company to the risk that a counterparty will be unable to meet its commitments. While the Company monitors counterparty creditworthiness on an ongoing basis, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices while continuing to be obligated under higher commodity price contracts subject to any right of offset under the agreements. Counterparty credit risk is considered when determining the fair value of a derivative instrument; see Note 7 for additional information regarding fair value.



	Notes to the Consolidated Financial Statements (Unaudited) (All dollar amounts in thousands, except per share and per unit data)

The Company executes commodity derivative contracts under master agreements with netting provisions that provide for offsetting assets against liabilities. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a cash payment transfer or terminate the arrangement.

Financial statement presentation and settlements

Settlements of the Company’s commodity derivative instruments are based on the difference between the contract price or prices specified in the derivative instrument and a benchmark price, such as the NYMEX price. To determine the fair value of the Company’s derivative instruments, the Company utilizes present value methods that include assumptions about commodity prices based on those observed in underlying markets. See Note 7 for additional information regarding fair value.

Contingent consideration arrangement

Our Ranger Asset Divestiture in June of 2019 provides for potential contingent consideration to be received by the Company if commodity prices exceed specific thresholds in each of the next several years. On the disposition date, we recognized a derivative asset of $8,512 based on the initial fair value measurement. See Note 7 for additional information regarding fair value measurement. These contingent payments are summarized in the tables below (in thousands):

Year of Potential Settlement

Threshold ^(a)

Contingent Payment Amount

Threshold ^(a)

Contingent Payment Amount

Fair Value as of September 30, 2019 ^(b)

Aggregate Settlements Limit^(c)

60,000

2019

Greater than $60/bbl, less than $65/bbl

$9,000

Equal to or greater than $65/bbl