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	$20,833		$116
2020	Greater than $60/bbl, less than $65/bbl	$9,000	Equal to or greater than $65/bbl	$20,833		$3,977
2021	Greater than $60/bbl, less than $65/bbl	$9,000	Equal to or greater than $65/bbl	$20,833	^(c)	$3,496


(a)	The price used to determine whether the specified thresholds have been met is the average of the final monthly settlements for each month during each annual period end for NYMEX Light Sweet Crude Oil Futures, as reported by the CME Group Inc.


(b)	Contingent consideration to be received will be classified as cash flows from financing activities up to the initial recognition fair value of $8,512; amounts in excess of the initial recognition fair value will be classified as cash flows from operating activities.


(c)	In the event that the 2019 and 2020 prices exceed the $65/bbl threshold, the aggregate amount of contingent consideration is limited to $60,000, resulting in the potential reduction in settlement for 2021 to $18,334.

Derivatives not designated as hedging instruments

The Company records its derivative contracts at fair value in the consolidated balance sheets and records changes in fair value as a gain or loss on derivative contracts in the consolidated statements of operations. Settlements are also recorded as a gain or loss on derivative contracts in the consolidated statements of operations.



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

The following table reflects the fair value of the Company’s derivative instruments for the periods presented:



As of September 30, 2019
Derivative Instrument	Balance Sheet Presentation	Asset		Liability			Net Asset (Liability)
Commodity - Oil	Fair value of derivatives - Current	$	23,487	$	(8,795	)	$	14,692
Commodity - Natural gas	Fair value of derivatives - Current	1,429		(146		)	1,283
Contingent consideration arrangement	Fair value of derivatives - Current	116		—			116
Commodity - Oil	Fair value of derivatives - Non-current	3,736		(2,233		)	1,503
Commodity - Natural gas	Fair value of derivatives - Non-current	—		(340		)	(340		)
Contingent consideration arrangement	Fair value of derivatives - Non-current	7,473		—			7,473
Totals		$	36,241	$	(11,514	)	$	24,727

As of December 31, 2018
Derivative Instrument	Balance Sheet Presentation	Asset		Liability			Net Asset (Liability)
Commodity - Oil	Fair value of derivatives - Current	$	60,097	$	(10,480	)	$	49,617
Commodity - Natural gas	Fair value of derivatives - Current	5,017		—			5,017
Commodity - Oil	Fair value of derivatives - Non-current	—		(5,672		)	(5,672		)
Commodity - Natural gas	Fair value of derivatives - Non-current	—		(1,768		)	(1,768		)
Totals		$	65,114	$	(17,920	)	$	47,194

As previously discussed, the Company’s commodity derivative contracts are subject to master netting arrangements. The Company’s policy is to present the fair value of commodity derivative contracts on a net basis in the consolidated balance sheet. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated:



	As of September 30, 2019
	Presented without						As Presented with
	Effects of Netting			Effects of Netting			Effects of Netting
Current assets: Fair value of commodity derivatives	$	35,936		$	(11,020	)	$	24,916
Long-term assets: Fair value of commodity derivatives	7,464			(3,728		)	3,736

Current liabilities: Fair value of commodity derivatives	$	(19,961	)	$	11,020		$	(8,941	)
Long-term liabilities: Fair value of commodity derivatives	(6,301		)	3,728			(2,573		)



	As of December 31, 2018
	Presented without						As Presented with
	Effects of Netting			Effects of Netting			Effects of Netting
Current assets: Fair value of commodity derivatives	$	78,091		$	(12,977	)	$	65,114

Current liabilities: Fair value of commodity derivatives	$	(23,457	)	$	12,977		$	(10,480	)
Long-term liabilities: Fair value of commodity derivatives	(7,440		)	—			(7,440		)

For the periods indicated, the Company recorded the following in the consolidated statements of operations as a gain or loss on derivative contracts:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Oil derivatives
Net gain (loss) on settlements	$	(1,045	)	$	(9,306	)	$	(7,048	)	$	(26,353	)
Net gain (loss) on fair value adjustments	25,767			(24,476		)	(27,750		)	(28,720		)
Total gain (loss) on oil derivatives	24,722			(33,782		)	(34,798		)	(55,073		)
Natural gas derivatives
Net gain (loss) on settlements	2,056			67			6,612			675
Net gain (loss) on fair value adjustments	(733		)	(624		)	(2,306		)	(976		)
Total gain (loss) on natural gas derivatives	1,323			(557		)	4,306			(301		)
Contingent consideration arrangement
Net gain (loss) on fair value adjustments	(4,236		)	—			(923		)	—
Total gain (loss) on derivatives	$	21,809		$	(34,339	)	$	(31,415	)	$	(55,374	)



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

Derivative positions

Listed in the tables below are the outstanding oil and natural gas derivative contracts as of September 30, 2019:



	For the Remainder			For the Full Year			For the Full Year
Oil contracts (WTI)	of 2019			of 2020			of 2021
Puts
Total volume (Bbls)	230,000			—			—
Weighted average price per Bbl	$	65.00		$	—		$	—
Put spreads
Total volume (Bbls)	230,000			—			—
Weighted average price per Bbl
Floor (long put)	$	65.00		$	—		$	—
Floor (short put)	$	42.50		$	—		$	—
Collar contracts with short puts (three-way collars)
Total volume (Bbls)	1,196,000			5,124,000			—
Weighted average price per Bbl
Ceiling (short call)	$	67.46		$	65.46		$	—
Floor (long put)	$	56.54		$	55.45		$	—
Floor (short put)	$	43.65		$	44.66		$	—
Collar contracts (two-way collars)
Total volume (Bbls)	276,000			—			—
Weighted average price per Bbl
Ceiling (short call)	$	60.00		$	—		$	—
Floor (long put)	$	55.00		$	—		$	—
Short call
Total volume (Bbls)	—			—			1,825,000		^(a)
Weighted average price per Bbl	$	—		$	—		$	63.00
Swap contracts
Total volume (Bbls)	276,000			1,098,000			—
Weighted average price per Bbl	$	60.17		$	56.17		$	—

Oil contracts (Brent ICE)
Collar contracts with short puts (three-way collars)
Total volume (Bbls)	—			837,500			—
Weighted average price per Bbl
Ceiling (short call)	$	—		$	70.00		$	—
Floor (long put)	$	—		$	58.24		$	—
Floor (short put)	$	—		$	50.00		$	—

Oil contracts (Midland basis differential)
Swap contracts
Total volume (Bbls)	2,176,000			4,576,000			1,095,000
Weighted average price per Bbl	$	(2.50	)	$	(1.29	)	$	1.00

Oil contracts (Argus Houston MEH basis differential)
Swap contracts
Total volume (Bbls)	—			1,439,205			—
Weighted average price per Bbl	$	—		$	2.40		$	—

Natural gas contracts (Henry Hub)
Collar contracts (two-way collars)
Total volume (MMBtu)	598,000			—			—
Weighted average price per MMBtu
Ceiling (short call)	$	3.50		$	—		$	—
Floor (long put)	$	3.13		$	—		$	—
Swap contracts
Total volume (MMBtu)	155,000			—			—
Weighted average price per MMBtu	$	2.87		$	—		$	—

Natural gas contracts (Waha basis differential)
Swap contracts
Total volume (MMBtu)	2,116,000			4,758,000			—
Weighted average price per MMBtu	$	(1.18	)	$	(1.12	)	$	—

^(a)Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps.



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

Note 7 - Fair Value Measurements

The fair value hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable, and these valuations have the lowest priority.

Fair value of financial instruments

Cash, cash equivalents, and restricted investments. The carrying amounts for these instruments approximated fair value due to the short-term nature or maturity of the instruments.

Debt. The carrying amount of the Company’s floating-rate debt approximated fair value, because the interest rates were variable and reflective of market rates.



	September 30, 2019				December 31, 2018
	Carrying Value		Fair Value		Carrying Value		Fair Value
Credit Facility ^(a)	$	200,000	$	200,000	$	200,000	$	200,000
6.125% Senior Notes ^(b)	596,337		595,194		595,788		558,000
6.375% Senior Notes ^(b)	394,317		393,540		393,685		372,000
Total	$	1,190,654	$	1,188,734	$	1,189,473	$	1,130,000


(a)	Floating-rate debt.


(b)	The fair value was based upon Level 2 inputs. See Note 5 for additional information about the Company’s 6.125% and 6.375% Senior Notes.

Assets and liabilities measured at fair value on a recurring basis

Certain assets and liabilities are reported at fair value on a recurring basis in the consolidated balance sheet. The following methods and assumptions were used to estimate fair value:

Commodity derivative instruments. The fair value of commodity derivative instruments is derived using an income approach valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities. The Company believes that the majority of the inputs used to calculate the commodity derivative instruments fall within Level 2 of the fair value hierarchy based on the wide availability of quoted market prices for similar commodity derivative contracts. See Note 6 for additional information regarding the Company’s derivative instruments.

Contingent consideration arrangement - embedded derivative financial instrument. The embedded option within the contingent consideration arrangement is considered a financial instrument under ASC 815. The Company engages a third-party valuation specialist using an option pricing model approach to measure the fair value of the embedded option on a recurring basis. The valuation includes significant inputs such as forward oil price curves, time to expiration, and implied volatility. The model provides for the probability that the specified pricing thresholds would be met for each settlement period, estimates an undiscounted payout, and risk adjusts for the discount rates inclusive of adjustments for the counterparty’s credit quality. As these inputs are substantially observable for the full term of the contingent consideration arrangement, the inputs are considered Level 2 inputs within the fair value hierarchy. See Note 6 for additional information regarding the Company’s contingent consideration arrangement.



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

The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis:



September 30, 2019	Classification	Level 1		Level 2			Level 3		Total
Assets
Derivative financial instruments	Fair value of derivatives	$	—	$	36,241		$	—	$	36,241
Liabilities
Derivative financial instruments	Fair value of derivatives	—		(11,514		)	—		(11,514		)
Total net assets (liabilities)		$	—	$	24,727		$	—	$	24,727

December 31, 2018	Classification	Level 1		Level 2			Level 3		Total
Assets
Derivative financial instruments	Fair value of derivatives	$	—	$	65,114		$	—	$	65,114
Liabilities
Derivative financial instruments	Fair value of derivatives	—		(17,920		)	—		(17,920		)
Total net assets		$	—	$	47,194		$	—	$	47,194

Assets and liabilities measured at fair value on a nonrecurring basis

Acquisitions. The Company determines the fair value of the assets acquired and liabilities assumed using the income approach based on expected discounted future cash flows from estimated reserve quantities, costs to produce and develop reserves, and oil and natural gas forward prices. The future net revenues are discounted using a weighted average cost of capital. The discounted future net revenues of proved undeveloped and probable reserves are reduced by an additional reserve adjustment factor to compensate for the inherent risk of estimating the value of unevaluated properties. The fair value measurements were based on Level 1, Level 2 and Level 3 inputs.

Note 8 - Income Taxes

The Company provides for income taxes at the statutory rate of 21% adjusted for permanent differences expected to be realized, which primarily relate to non-deductible executive compensation expenses, restricted stock windfalls, and state income taxes. The following table presents a reconciliation of the reported amount of income tax expense to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income from continuing operations:



	Three Months Ended September 30,				Nine Months Ended September 30,
Components of income tax rate reconciliation	2019		2018		2019		2018
Income tax expense computed at the statutory federal income tax rate	21	%	21	%	21	%	21	%
State taxes net of federal expense	1	%	3	%	1	%	2	%
Section 162(m)	—	%	2	%	—	%	1	%
Valuation allowance	—	%	(21	)%	—	%	(21	)%
Effective income tax rate, before discrete items	22	%	5	%	22	%	3	%
Discrete items ^(a)	2	%	(1	)%	2	%	(1	)%
Effective income tax rate, after discrete items	24	%	4	%	24	%	2	%


^(a)	Accounts for the potential impact of periodic volatility of stock-based compensation tax deductions on future effective tax rates.

Note 9 - Equity Transactions

10% Series A Cumulative Preferred Stock (“Preferred Stock”)

Holders of the Company’s 10.00% Series A Cumulative Preferred Stock were entitled to receive, when, as and if declared by the Company’s board of directors, out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of 10.0% per annum of the $50.00 liquidation preference per share (equivalent to $5.00 per annum per share). Dividends were payable quarterly in arrears on the last day of each March, June, September and December when, as and if declared by the Company’s Board of Directors. Preferred Stock dividends were $350 and $1,823 for the three months ended September 30, 2019 and 2018, respectively, and $3,997 and $5,471 for the nine months ended September 30, 2019 and 2018, respectively.

On June 18, 2019, the Company announced it had given notice for the redemption (the “Redemption”) of all outstanding shares of the Preferred Stock. The redemption date of the Preferred Stock was July 18, 2019 (the “Redemption Date”). The Preferred Stock were redeemed at the redemption price equal to $50.00 per share, plus an amount equal to all accrued and unpaid dividends in an amount equal to $0.24 per share, for a total redemption price of $50.24 per share (the “Redemption Price”). After the Redemption Date, the Preferred



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

Stock were no longer deemed outstanding, dividends on the Preferred Stock ceased to accrue, and all rights of the holders with respect to such Preferred Stock were terminated, except the right of the holders to receive the Redemption Price, without interest.

Common stock

On May 30, 2018, the Company completed an underwritten public offering of 25.3 million shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering costs) of approximately $287,988. The Company used proceeds from the offering to partially fund the Delaware Asset Acquisition completed in the third quarter of 2018, described in Note 3.

Note 10 - Leases

Leases

We determine if an arrangement is a lease at inception of the arrangement. To the extent that we determine an arrangement represents a lease, we classify that lease as an operating lease or a finance lease. Based on our evaluation of leases for the three and nine months ended September 30, 2019, we have no leases that meet the criteria for classification as a finance lease. We capitalize operating leases on our consolidated balance sheets through a right-of-use (“ROU”) asset and a corresponding lease liability. ROU assets represent our right to use an underlying asset for the lease term, and lease liabilities represent our obligation to make lease payments arising from the lease.

Operating leases are included in operating lease ROU assets, current operating lease liabilities, and long-term operating lease liabilities in our consolidated balance sheets. Operating lease ROU assets and liabilities are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term. The operating lease ROU asset also includes any lease payments made to the lessor prior to lease commencement, less any lease incentives, and initial direct costs incurred. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term.

Nature of leases

In support of our operations, we lease certain drilling rigs, office space, office equipment, production facilities, compressors, vehicles and other ancillary drilling equipment under cancelable and non-cancelable contracts. A more detailed description of our material lease types is included below.

Drilling rigs

The Company enters into daywork and long-term contracts for drilling rigs with third party service contractors to support the development of undeveloped reserves. Our daywork drilling rig arrangements are typically structured with a term that is in effect until drilling operations are completed on a contractually specified well or well pad. Upon mutual agreement with the contractor, we typically have the option to extend the contract term for additional wells, well pads or contractually stated extension terms by providing 30 days’ notice prior to the end of the original contract term.

The Company’s long-term drilling contracts are generally structured with an initial non-cancelable term of one to two years. We have concluded that our long-term drilling rig arrangements represent operating leases with a lease term greater than twelve months. Additionally, we have concluded that our daywork drilling rig arrangements represent short-term operating leases with a lease term that equals the period of time required to complete drilling operations on the contractually specified well or well pad (that is, generally one to a few months from commencement of drilling).

We do not include the option to extend the drilling rig contract in the lease term due to the continuously evolving nature of our drilling schedules, which requires significant flexibility in the structure of the term of these arrangements, and the potential volatility in commodity prices in an annual period. We have further elected to apply the practical expedient for short-term leases to our daywork drilling rig leases. Accordingly, we do not apply the lease recognition requirements to our daywork drilling rig contracts, and we recognize lease payments related to these arrangements in profit or loss on a straight-line basis over the lease term.

Corporate and field offices

We enter into long-term contracts to lease corporate and field office space in support of company operations. These contracts are generally structured with an initial non-cancelable term of two to five years. To the extent that our corporate and field office contracts include renewal options, we evaluate whether we are reasonably certain to exercise those options on a contract by contract basis based on expected future office space needs, market rental rates, drilling plans and other factors. We have further determined that our current corporate and field office leases represent operating leases.



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

Transportation, gathering and processing arrangements

We engage in various types of transactions in which midstream entities transport, gather and/or process our product leveraging integrated systems and facilities wholly-owned and operated by the midstream counterparty. Under most of these arrangements, we do not utilize substantially all of the underlying pipeline, gathering system or processing facilities, and thus, we have concluded that those underlying assets do not meet the definition of an identified asset.

The following tables reflect the current period impact of our adoption of the new leases standard. As we have no leases that meet the criteria for classification as a finance lease, all information contained herein represents our operating leases.

The components of our total lease cost were as follows:



	Three Months Ended		Nine Months Ended
	September 30, 2019		September 30, 2019
Operating lease cost	$	7,964	$	27,122
Short-term lease cost ^(a)	293		3,640

^(a)Short-term lease cost excludes expenses related to leases with a contract term of one month or less.

As of September 30, 2019, our weighted average remaining lease term and our weighted average discount rate for our operating leases were 1.36 years and 4.03%, respectively.

Our operating lease liabilities with enforceable contract terms that are greater than one year mature as follows:



	As of September 30, 2019
Remainder of 2019	$	7,932
2020	13,933
2021	1,576
2022	534
2023	517
Thereafter	431
Total lease payments	24,923
Less imputed interest	732
Total	$	24,191

Note 11 - Asset Retirement Obligations

The table below summarizes the activity for the Company’s ARO:



	Nine Months Ended
	September 30, 2019
Asset retirement obligations at January 1, 2019	$	14,292
Accretion expense	585
Liabilities incurred	325
Liabilities settled	(3,187		)
Dispositions	(1,753		)
Revisions to estimate	(718		)
Asset retirement obligations at end of period	9,544
Less: Current asset retirement obligations	(1,250		)
Long-term asset retirement obligations at September 30, 2019	$	8,294


•	Liabilities incurred include additions from acquisitions, asset swaps, and new wells drilled during the year.


•	Liabilities settled include the retirement of 28 wells during the year and settlement of abandonment obligations attributable to historical activity within the Gulf of Mexico.


•	Dispositions are primarily attributable to the Ranger Asset Divestiture in the second quarter of 2019. See Note 3 for details about the Ranger Asset Divestiture.


•	Revisions to estimates were due to changes in plugging cost estimates, timing of abandonment activities, and changes in working interest of producing wells.



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

Certain of the Company’s operating agreements require that assets be restricted for abandonment obligations. Amounts recorded in the consolidated balance sheet at September 30, 2019 as long-term restricted investments were $3,490. These assets, which primarily include short-term U.S. Government securities, are held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s oil and natural gas properties.

Note 12 - Other

Other commitments

In August 2018, the Company executed a firm transportation agreement for dedicated capacity on a new pipeline system that will connect with a regional gathering system which currently transports oil volumes under long-term agreements from our properties in Howard and Ward counties to multiple marketing points in the Permian Basin. Subject to completion of the new pipeline system, which will have delivery points in several locations along the Gulf Coast, we will have a long-term commitment that will apply applicable tariff rates to our 15,000 Bbls per day commitment for the term of the agreement. Barrels may be transported to multiple delivery points along the Gulf Coast and may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf.

In January 2019, the Company executed a crude oil sales contract that provides further dedicated capacity on several pipeline systems that will connect with a regional gathering system which currently transports oil volumes under long-term agreements from our properties in Howard and Ward counties and will have delivery points in several locations along the Gulf Coast, providing the Company with the potential benefit of access to an international weighted average sales price. We will have a long-term 10,000 Bbls per day commitment for the term of the agreement, and may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf.

In June 2019, the Company executed a firm transportation agreement for dedicated capacity on a new pipeline system that originates in Midland, Texas and terminates in Houston, Texas. Subject to completion of the new pipeline system, which will have delivery points in several locations along the Gulf Coast, we will have a long-term commitment that will apply applicable tariff rates to our quantities committed that average 10,000 Bbls per day for the term of the agreement. Barrels may be transported to multiple delivery points along the Gulf Coast and may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf.

In July 2019, the Company executed a crude oil sales contact that provides dedicated capacity on a new pipeline system that originates in Midland County and will have delivery points in several locations along the Gulf Coast. We will have a long-term 5,000 Bbls per day commitment for the term of the agreement and will apply applicable tariff rates to those quantities. Barrels may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf.

Note 13 - Carrizo Acquisition

On July 14, 2019, Callon and Carrizo Oil & Gas, Inc. (“Carrizo”) entered into an Agreement and Plan of Merger (the “Merger Agreement”), pursuant to which, upon the terms and subject to the conditions set forth therein, Carrizo will merge with and into Callon, with Callon as the surviving corporation (the “Merger” or the “Carrizo Acquisition”). The combination will result in a portfolio of core oil-weighted assets in both the Permian Basin and Eagle Ford Shale.

Subject to the terms and conditions of the Merger Agreement, at the effective time of the Merger (the “Effective Time”), each outstanding share of Carrizo common stock, will be converted into the right to receive 2.05 shares of Callon common stock. Following the closing of the Merger, Callon’s existing shareholders and Carrizo’s existing shareholders will own approximately 54% and 46%, respectively, of the outstanding shares of the combined company.

The Merger Agreement provides that, upon consummation of the Merger, the board of directors of Callon will consist of the eight members of the board of directors of Callon immediately prior to the Effective Time and three members of the board of directors of Carrizo. Callon and Carrizo have agreed that the Director Designees will be appointed to the Callon board immediately after the effective time, with the Callon designee being appointed as a Class III director, with a term ending at the 2021 annual meeting of the shareholders of Callon, and the Carrizo designees being appointed as Class I directors, each with a term ending at the 2022 annual meeting of the shareholders of Callon. Callon and Carrizo expect that the Callon designee will be Frances Aldrich Sevilla-Sacasa and the Carrizo designees will be S.P. Johnson IV and Steven A. Webster.

Additionally, the Merger Agreement provides that, upon consummation of the Merger, the officers of Callon immediately prior to the Effective Time shall be the officers of the combined company. Callon will continue to be headquartered in Houston, Texas, where both



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

companies are currently based. Callon expects that the acquisition will close during the fourth quarter of 2019, subject to the approval of both shareholder bases, the satisfaction of certain regulatory approvals and other closing conditions.

Special Note Regarding Forward Looking Statements

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”), as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In some cases, you can identify forward-looking statements in this Form 10-Q by words such as “anticipate,” “project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target” or similar expressions.

All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect or anticipate will or may occur in the future are forward-looking statements, including such things as:


•	matters relating to the Carrizo Acquisition;


•	our oil and natural gas reserve quantities, and the discounted present value of these reserves;


•	the amount and nature of our capital expenditures;


•	our future drilling and development plans and our potential drilling locations;


•	the timing and amount of future capital and operating costs;


•	production decline rates from our wells being greater than expected;


•	commodity price risk management activities and the impact on our average realized prices;


•	business strategies and plans of management;


•	our ability to consummate and efficiently integrate recent acquisitions; and


•	prospect development and property acquisitions.

Some of the risks, which could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements, include:


•	general economic conditions including the availability of credit and access to existing lines of credit;


•	the volatility of oil and natural gas prices;


•	the uncertainty of estimates of oil and natural gas reserves;


•	impairments;


•	the impact of competition;


•	the availability and cost of seismic, drilling and other equipment, waste and water disposal infrastructure, and personnel;


•	operating hazards inherent in the exploration for and production of oil and natural gas;


•	difficulties encountered during the exploration for and production of oil and natural gas;


•	the potential impact of future drilling on production from existing wells;


•	difficulties encountered in delivering oil and natural gas to commercial markets;


•	changes in customer demand and producers’ supply;


•	the uncertainty of our ability to attract capital and obtain financing on favorable terms;


•	compliance with, or the effect of changes in, the extensive governmental regulations regarding the oil and natural gas business including those related to climate change and greenhouse gases;


•	the impact of government regulation, including regulation of hydraulic fracturing and water disposal wells;


•	any increase in severance or similar taxes;


•	the financial impact of accounting regulations and critical accounting policies;


•	the comparative cost of alternative fuels;


•	credit risk relating to the risk of loss as a result of non-performance by our counterparties;


•	cyberattacks on the Company or on systems and infrastructure used by the oil and gas industry;


•	weather conditions;


•	risks associated with acquisitions, including the Carrizo Acquisition;


•	failure to consummate the Carrizo Acquisition in a timely manner, or at all, and failure to realize the expected benefits thereof;


•	any litigation relating to the Carrizo Acquisition; and


•	any other factors listed in the reports we have filed and may file with the SEC.

We caution you that the forward-looking statements contained in this Form 10-Q are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of oil and natural gas. These risks include, but are not limited to, the risks described in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2018 (the “2018 Annual Report on Form 10-K”), and all quarterly reports on Form 10-Q filed subsequently thereto.

Should one or more of the risks or uncertainties described above or in our 2018 Annual Report on Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. Any forward-looking statement speaks only as of the date of which such statement is made and the Company undertakes no obligation

to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except required by applicable law.

Except as required by applicable law, all forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.



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

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

General

The following management’s discussion and analysis describes the principal factors affecting the Company’s results of operations, liquidity, capital resources and contractual cash obligations. This discussion should be read in conjunction with the accompanying unaudited consolidated financial statements and our 2018 Annual Report on Form 10-K, which include additional information about our business practices, significant accounting policies, risk factors, and the transactions that underlie our financial results. Our website address is www.callon.com. All of our filings with the SEC are available free of charge through our website as soon as reasonably practicable after we file them with, or furnish them to, the SEC. Information on our website does not form part of this Quarterly Report on Form 10-Q.

We are an independent oil and natural gas company incorporated in the State of Delaware in 1994, but our roots go back nearly 70 years to our Company’s establishment in 1950. We are 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 historically been focused on the Midland Basin and more recently entered the Delaware Basin through an acquisition completed in February 2017. We further expanded our presence in the Delaware Basin through our acquisitions in 2018. Our operating culture is centered on responsible development of hydrocarbon resources, safety and the environment, which we believe strengthens our operational performance. Our drilling activity is focused on the horizontal development of several prospective intervals, including multiple levels of the Wolfcamp formation and the Lower Spraberry shales. We have assembled a multi-year inventory of potential horizontal well locations and intend to add to this inventory through delineation drilling of emerging zones on our existing acreage and acquisition of additional locations through working interest acquisitions, leasing programs, acreage purchases, joint ventures and asset swaps. Our production was approximately 78% oil and 22% natural gas for the nine months ended September 30, 2019.

Recent Developments

On June 12, 2019, we completed the Ranger Asset Divestiture for net cash proceeds received at closing of $245 million, including customary purchase price adjustments.

On July 18, 2019, we redeemed all outstanding shares of the Preferred Stock at a Redemption Price of $50.24 per share for a total redemption of $73 million. After the Redemption Date, the Preferred Stock were no longer deemed outstanding, dividends on the Preferred Stock ceased to accrue, and all rights of the holders with respect to such Preferred Stock were terminated, except the right of the holders to receive the Redemption Price, without interest.

In July 2019, Callon and Carrizo entered into the Merger Agreement, pursuant to which, upon the terms and subject to the conditions set forth therein, Carrizo will merge with and into Callon, with Callon as the surviving corporation. The combination will result in a portfolio of core oil-weighted assets in both the Permian Basin and Eagle Ford Shale. The Company expects that the acquisition will close during the fourth quarter of 2019. See Note 13 for additional information regarding the Carrizo Acquisition.

Operational Highlights

All of our producing properties are located in the Permian Basin. As a result of our horizontal development and acquisition efforts, our production grew 8% and 31% for the three and nine months ended September 30, 2019, compared to the same periods of 2018, respectively. Production increased to 3,481 MBOE for the three months ended September 30, 2019 from 3,212 MBOE for the same period of 2018, and increased to 10,796 MBOE for the nine months ended September 30, 2019 from 8,238 MBOE for the same period of 2018. As of September 30, 2019, we had 800 gross (602.4 net) working interest oil and natural gas wells.

For the three months ended September 30, 2019, we drilled 12 gross (11.0 net) horizontal wells and completed 16 gross (15.6 net) horizontal wells. For the nine months ended September 30, 2019, we drilled 48 gross (41.7 net) horizontal wells and completed 41 gross (38.1 net) horizontal wells. As of September 30, 2019, we had 18 gross (13.1 net) horizontal wells awaiting completion.



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

Results of Operations

The following tables set forth certain operating information with respect to the Company’s oil and natural gas operations for the periods indicated:



	Three Months Ended September 30,
	2019			2018			Change			% Change
Net production
Oil (MBbls)	2,725			2,521			204			8	%
Natural gas (MMcf)	4,538			4,144			394			10	%
Total (MBOE)	3,481			3,212			269			8	%
Average daily production (BOE/d)	37,837			34,913			2,924			8	%
% oil (BOE basis)	78		%	78		%
Average realized sales price (excluding impact of settled derivatives)
Oil (per Bbl)	$	54.39		$	56.57		$	(2.18	)	(4	)%
Natural gas (per Mcf)	1.58			4.49			(2.91		)	(65	)%
Total (per BOE)	44.64			50.19			(5.55		)	(11	)%
Average realized sales price (including impact of settled derivatives)
Oil (per Bbl)	$	54.01		$	52.87		$	1.14		2	%
Natural gas (per Mcf)	2.03			4.51			(2.48		)	(55	)%
Total (per BOE)	44.93			47.31			(2.38		)	(5	)%
Oil and natural gas revenues (in thousands)
Oil revenue	$	148,210		$	142,601		$	5,609		4	%
Natural gas revenue	7,168			18,613			(11,445		)	(61	)%
Total	$	155,378		$	161,214		$	(5,836	)	(4	)%
Additional per BOE data
Sales price ^(a)	$	44.64		$	50.19		$	(5.55	)	(11	)%
Lease operating expense ^(b)	5.65			5.77			(0.12		)	(2	)%
Production taxes	3.41			3.20			0.21			7	%
Operating margin	$	35.58		$	41.22		$	(5.64	)	(14	)%
Benchmark prices
WTI (per Bbl)	$	56.34		$	69.69		$	(13.35	)	(19	)%
Henry Hub (per Mmbtu)	2.38			2.93			(0.55		)	(19	)%


(a)	Excludes the impact of settled derivatives.


(b)	Excludes gathering and treating expense.



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



	Nine Months Ended September 30,
	2019			2018			Change			% Change
Net production
Oil (MBbls)	8,431			6,368			2,063			32	%
Natural gas (MMcf)	14,188			11,222			2,966			26	%
Total (MBOE)	10,796			8,238			2,558			31	%
Average daily production (BOE/d)	39,546			30,176			9,370			31	%
% oil (BOE basis)	78		%	77		%
Average realized sales price (excluding impact of settled derivatives)
Oil (per Bbl)	$	53.38		$	59.75		$	(6.37	)	(11	)%
Natural gas (per Mcf)	1.79			4.03			(2.24		)	(56	)%
Total (per BOE)	44.04			51.68			(7.64		)	(15	)%
Average realized sales price (including impact of settled derivatives)
Oil (per Bbl)	$	52.54		$	55.61		$	(3.07	)	(6	)%
Natural gas (per Mcf)	2.26			4.09			(1.83		)	(45	)%
Total (per BOE)	44.00			48.56			(4.56		)	(9	)%
Oil and natural gas revenues (in thousands)
Oil revenue	$	450,036		$	380,500		$	69,536		18	%
Natural gas revenue	25,441			45,229			(19,788		)	(44	)%
Total	$	475,477		$	425,729		$	49,748		12	%
Additional per BOE data
Sales price ^(a)	$	44.04		$	51.68		$	(7.64	)	(15	)%
Lease operating expense^(b)	6.16			5.43			0.73			13	%
Production taxes	3.13			3.19			(0.06		)	(2	)%
Operating margin	$	34.75		$	43.06		$	(8.31	)	(19	)%
Benchmark prices
WTI (per Bbl)	$	57.04		$	66.93		$	(9.89	)	(15	)%
Henry Hub (per Mmbtu)	2.62			2.95			(0.33		)	(11	)%


(a)	Excludes the impact of settled derivatives.


(b)	Excludes gathering and treating expense.



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

Revenues

The following tables are intended to reconcile the change in oil, natural gas and total revenue for the respective periods presented by reflecting the effect of changes in volume and in the underlying commodity prices.



(in thousands)	Oil			Natural Gas			Total
Revenues for the three months ended September 30, 2018	$	142,601		$	18,613		$	161,214
Volume increase	11,540			1,769			13,309
Price decrease	(5,931		)	(13,214		)	(19,145		)
Net increase (decrease)	5,609			(11,445		)	(5,836		)
Revenues for the three months ended September 30, 2019	$	148,210		$	7,168		$	155,378



(in thousands)	Oil			Natural Gas			Total
Revenues for the nine months ended September 30, 2018	$	380,500		$	45,229		$	425,729
Volume increase	123,264			11,953			135,217
Price decrease	(53,728		)	(31,741		)	(85,469		)
Net increase (decrease)	69,536			(19,788		)	49,748
Revenues for the nine months ended September 30, 2019	$	450,036		$	25,441		$	475,477

Commodity prices

The prices for oil and natural gas remain extremely volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, weather conditions, economic conditions and actions by the Organization of Petroleum Exporting Countries and other countries and government actions. Prices of oil and natural gas will affect the following aspects of our business:


•	our revenues, cash flows and earnings;


•	the amount of oil and natural gas that we are economically able to produce;


•	our ability to attract capital to finance our operations and cost of the capital;


•	the amount we are allowed to borrow under our Credit Facility; and


•	the value of our oil and natural gas properties.

Oil revenue

For the three months ended September 30, 2019, oil revenues of $148.2 million increased $5.6 million, or 4%, compared to revenues of $142.6 million for the same period of 2018. The increase was primarily attributable to an 8% increase in production from our acquisition and development efforts, offset by a 4% decrease in the average realized sales price, which fell to $54.39 per Bbl from $56.57 per Bbl.

For the nine months ended September 30, 2019, oil revenues of $450.0 million increased $69.5 million, or 18%, compared to revenues of $380.5 million for the same period of 2018. The increase was primarily attributable to a 32% increase in production from our acquisition and development efforts, offset by an 11% decrease in the average realized sales price, which fell to $53.38 per Bbl from $59.75 per Bbl.

Natural gas revenue (including NGLs)

For the three months ended September 30, 2019, natural gas revenues of $7.2 million decreased $11.4 million, or 61%, compared to $18.6 million for the same period of 2018. The decrease was primarily attributable to a 65% decrease in the average realized sales price, which fell to $1.58 per Mcf from $4.49 per Mcf. The decrease in realized natural gas pricing was partially offset by a 10% increase in natural gas volumes.

For the nine months ended September 30, 2019, natural gas revenues of $25.4 million decreased $19.8 million, or 44%, compared to $45.2 million for the same period of 2018. The decrease was primarily attributable to a 56% decrease in the average realized sales price, which fell to $1.79 per Mcf from $4.03 per Mcf. The decrease in realized natural gas pricing was partially offset by a 26% increase in natural gas volumes.



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

Operating Expenses



	Three Months Ended September 30,
				Per					Per		Total Change					BOE Change
(in thousands, except per unit amounts)	2019			BOE			2018		BOE		$			%		$			%
Lease operating expenses	$	19,668		$	5.65		$	18,525	$	5.77	$	1,143		6	%	$	(0.12	)	(2	)%
Production taxes	11,866			3.41			10,263		3.20		1,603			16	%	0.21			7	%
Depreciation, depletion and amortization	56,002			16.09			48,257		15.02		7,745			16	%	1.07			7	%
General and administrative	9,388			2.70			9,721		3.03		(333		)	(3	)%	(0.33		)	(11	)%
Merger and integration expense	5,943			1.71			—		—		5,943			100	%	1.71			100	%
Accretion expense	128			0.04			202		0.06		(74		)	(37	)%	(0.02		)	(33	)%
Other operating expense	(161		)	(0.05		)	1,435		0.45		(1,596		)	(111	)%	(0.50		)	(111	)%



	Nine Months Ended September 30,
			Per				Per		Total Change					BOE Change
(in thousands, except per unit amounts)	2019		BOE		2018		BOE		$			%		$			%
Lease operating expenses	$	66,511	$	6.16	$	44,705	$	5.43	$	21,806		49	%	$	0.73		13	%
Production taxes	33,810		3.13		26,265		3.19		7,545			29	%	(0.06		)	(2	)%
Depreciation, depletion and amortization	178,690		16.55		122,407		14.86		56,283			46	%	1.69			11	%
General and administrative	31,705		2.94		26,779		3.25		4,926			18	%	(0.31		)	(10	)%
Merger and integration expense	5,943		0.55		—		—		5,943			100	%	0.55			100	%
Settled share-based awards	3,024		0.28		—		—		3,024			100	%	0.28			100	%
Accretion expense	585		0.05		626		0.08		(41		)	(7	)%	(0.03		)	(38	)%
Other operating expense	931		0.09		3,750		0.46		(2,819		)	(75	)%	(0.37		)	(80	)%

Lease operating expenses (“LOE”). These are daily costs incurred to extract oil and natural gas and maintain our producing properties. Such costs also include maintenance, repairs, salt water disposal, insurance and workover expenses related to our oil and natural gas properties.

LOE for the three months ended September 30, 2019 increased to $19.7 million compared to $18.5 million for the same period of 2018. The increase in LOE primarily related to an 8% increase in production over the comparative periods.

LOE on a per unit basis decreased when comparing the third quarter of 2019 to the same period in 2018. LOE per BOE decreased to $5.65 for the third quarter of 2019, which represents a decrease of $0.12 per BOE from the third quarter of 2018.

LOE for the nine months ended September 30, 2019 increased to $66.5 million compared to $44.7 million for the same period of 2018. The increase in LOE primarily related to a 31% increase in production over the comparative periods.

For the nine months ended September 30, 2019, LOE on a per unit basis increased to $6.16 per BOE compared to $5.43 per BOE for the same period of 2018 primarily due to increased non-operated activity related to previous acquisitions and workovers.

Production taxes. Production taxes include severance and ad valorem taxes. In general, production taxes are directly related to commodity price changes; however, severance taxes are based upon current year commodity prices, whereas ad valorem taxes are based upon prior year commodity prices. Severance taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. In the counties where our production is located, we are also subject to ad valorem taxes, which are generally based on the taxing jurisdictions’ valuation of our oil and gas properties.

Production taxes for the three months ended September 30, 2019 increased 16% to $11.9 million compared to $10.3 million for the same period of 2018. On a per BOE basis, production taxes for the three months ended September 30, 2019 increased by 7% compared to the same period of 2018. The increase in production taxes is partially due to higher severance taxes as a result of higher revenues. Severance taxes as a percentage of total revenue were consistent across the comparable periods at approximately 5%. Additionally, ad valorem taxes increased $2.2 million over the comparative periods due to a higher valuation of our oil and gas properties by the taxing jurisdictions and previous acquisitions.

Production taxes for the nine months ended September 30, 2019 increased 29% to $33.8 million compared to $26.3 million for the same period of 2018. On a per BOE basis, production taxes for the nine months ended September 30, 2019 decreased by 2% compared to the same period of 2018. The increase in production taxes is partially due to higher severance taxes as a result of higher revenues. Severance



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

taxes as a percentage of total revenue were relatively unchanged across the comparable periods at approximately 5%. Additionally, ad valorem taxes increased $5.8 million over the comparative periods due to a higher valuation of our oil and gas properties by the taxing jurisdictions and previous acquisitions.

Depreciation, depletion and amortization (“DD&A”). Under the full cost accounting method, we capitalize costs within a cost center and then systematically expense those costs on a units-of-production basis based on proved oil and natural gas reserve quantities. We calculate depletion on the following types of costs: (i) all capitalized costs, other than the cost of investments in unevaluated properties, less accumulated amortization; (ii) the estimated future expenditures to be incurred in developing proved reserves; and (iii) the estimated dismantlement and abandonment costs, net of estimated salvage values.

DD&A rates fluctuate as a result of changes in finding and development costs, acquisitions, impairments, and changes in proved reserves. For the three months ended September 30, 2019, DD&A expense was $56.0 million compared to $48.3 million for the same period of 2018. The additional DD&A was related to a 8% increase in production volumes combined with higher DD&A rates between the periods, which resulted in $4.0 million and $3.7 million, respectively, of incremental DD&A expense being incurred during the third quarter of 2019.

For the three months ended September 30, 2019, DD&A on a per unit basis increased to $16.09 per BOE compared to $15.02 per BOE for the same period of 2018. The primary factor contributing to the increased DD&A rate were higher drilling and completion costs for new wells placed on production over the past 12 months relative to our historical rate. Additionally, the rate increase can be partially attributed to recent dispositions with a lower relative cost per BOE.

For the nine months ended September 30, 2019, DD&A expense was $178.7 million compared to $122.4 million for the same period of 2018. The additional DD&A was related to a 31% increase in production volumes combined with higher DD&A rates between the periods, which resulted in $38.0 million and $18.3 million, respectively, of incremental DD&A expense being incurred during the nine months ended September 30, 2019.

On a per unit basis DD&A increased to $16.55 per BOE compared to $14.86 per BOE for the same period of 2018. As discussed above, the increased DD&A rate is a function of recent drilling and completion costs incurred over the past 12 months relative to our historical rate. Additionally, the rate increase can be partially attributed to recent dispositions with a lower relative cost per BOE.

General and administrative, net of amounts capitalized (“G&A”). G&A for the three months ended September 30, 2019 decreased to $9.4 million compared to $9.7 million for the same period of 2018. On a per unit basis, G&A decreased 11% to $2.70 per BOE for the three months ended September 30, 2019 compared to $3.03 per BOE for the same period in 2018. G&A expenses for the periods indicated include the following (in thousands):



	Three Months Ended September 30,
	2019			2018		$ Change			% Change
Recurring expenses
G&A	$	8,789		$	7,070	$	1,719		24	%
Share-based compensation	1,525			1,730		(205		)	(12	)%
Fair value adjustments of cash-settled RSU awards	(926		)	921		(1,847		)	(201	)%
Total G&A expenses	$	9,388		$	9,721	$	(333	)	(3	)%

G&A for the nine months ended September 30, 2019 increased to $31.7 million compared to $26.8 million for the same period of 2018. The increase is primarily attributable to a rise in personnel costs resulting from the growth in our operating activities. On a per unit basis, G&A decreased 10% to $2.94 per BOE for the nine months ended September 30, 2019 compared to $3.25 per BOE for the same period in 2018. G&A expenses for the periods indicated include the following (in thousands):



	Nine Months Ended September 30,
	2019		2018		$ Change			% Change
Recurring expenses
G&A	$	26,889	$	20,929	$	5,960		28	%
Share-based compensation	4,712		4,422		290			7	%
Fair value adjustments of cash-settled RSU awards	104		1,428		(1,324		)	(93	)%
Total G&A expenses	$	31,705	$	26,779	$	4,926		18	%

Merger and integration expense. For the three and nine months ended September 30, 2019, the Company incurred $5.9 million of expense associated with the planned merger with Carrizo Oil & Gas, Inc.



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

Settled share-based awards. During the first quarter of 2019, the Company settled certain of the outstanding share-based award agreements of two former officers of the Company, resulting in the $3.0 million recorded on the consolidated statements of operations as settled share-based awards.

Other Income and Expenses and Preferred Stock Dividends



	Three Months Ended September 30,
(in thousands)	2019			2018			$ Change			% Change
Interest expense	$	18,869		$	17,244		$	1,625		9	%
Capitalized interest	(18,130		)	(16,533		)	(1,597		)	10	%
Interest expense, net of capitalized amounts	739			711			28			4	%
(Gain) loss on derivative contracts	(21,809		)	34,339			(56,148		)	(164	)%
Other income	(122		)	(1,657		)	1,535			(93	)%
Total other (income) expense	$	(21,192	)	$	33,393		$	(54,585	)	(163	)%

Income tax expense	$	17,902		$	1,487		$	16,415		1,104	%
Preferred stock dividends	(350		)	(1,823		)	1,473			(81	)%
Loss on redemption of preferred stock	(8,304		)	—			(8,304		)	(100	)%



	Nine Months Ended September 30,
(in thousands)	2019			2018			$ Change			% Change
Interest expense	$	58,929		$	40,416		$	18,513		46	%
Capitalized interest	(56,711		)	(38,651		)	(18,060		)	47	%
Interest expense, net of capitalized amounts	2,218			1,765			453			26	%
(Gain) loss on derivative contracts	31,415			55,374			(23,959		)	(43	)%
Other income	(270		)	(2,571		)	2,301			(89	)%
Total other (income) expense	$	33,363		$	54,568		$	(21,205	)	(39	)%

Income tax expense	$	29,444		$	2,463		$	26,981		1,095	%
Preferred stock dividends	(3,997		)	(5,471		)	1,474			(27	)%
Loss on redemption of preferred stock	$	(8,304	)	$	—		$	(8,304	)	(100	)%

Interest expense, net of capitalized amounts. We finance a portion of our capital expenditures, acquisitions and working capital requirements with borrowings under our Credit Facility or with term debt. We incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to our lender in interest expense, net of capitalized amounts. In addition, we include the amortization of deferred financing costs (including origination and amendment fees), commitment fees and annual agency fees in interest expense. Interest expense, net of capitalized amounts, incurred during the three months ended September 30, 2019 increased $0.0 million to $0.7 million compared to $0.7 million for the same period of 2018. Interest expense, net of capitalized amounts, incurred during the nine months ended September 30, 2019 increased $0.5 million to $2.2 million compared to $1.8 million for the same period of 2018.



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

Gain (loss) on derivative instruments. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in commodity prices. This amount represents the (i) gain (loss) related to fair value adjustments on our open derivative contracts and (ii) gains (losses) on settlements of derivative contracts for positions that have settled within the period. The net gain (loss) on derivative instruments for the periods indicated includes the following (in thousands):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Oil derivatives
Net gain (loss) on settlements	$	(1,045	)	$	(9,306	)	$	(7,048	)	$	(26,353	)
Net gain (loss) on fair value adjustments	25,767			(24,476		)	(27,750		)	(28,720		)
Total gain (loss) on oil derivatives	24,722			(33,782		)	(34,798		)	(55,073		)
Natural gas derivatives
Net gain (loss) on settlements	2,056			67			6,612			675
Net gain (loss) on fair value adjustments	(733		)	(624		)	(2,306		)	(976		)
Total gain (loss) on natural gas derivatives	1,323			(557		)	4,306			(301		)
Contingent consideration arrangement
Net gain (loss) on fair value adjustments	(4,236		)	—			(923		)	—
Total gain (loss) on derivatives	$	21,809		$	(34,339	)	$	(31,415	)	$	(55,374	)

See Notes 6 and 7 in the Footnotes to the Financial Statements for additional information on the Company’s derivative contracts and disclosures related to derivative instruments.

Income tax expense. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. When appropriate, based on our analysis, we record a valuation allowance for deferred tax assets when it is more likely than not that the deferred tax assets will not be realized.

The Company had income tax expense of $17.9 million for the three months ended September 30, 2019, compared to income tax expense of $1.5 million for the same period of 2018. The Company had income tax expense of $29.4 million for the nine months ended September 30, 2019, compared to income tax expense of $2.5 million for the same period of 2018. The change in income tax is primarily related to the change in our tax position in the current period, for which there is no longer a cumulative three year loss trend and booking of a valuation allowance for deferred tax benefits as compared to the prior period. See Note 8 in the Footnotes to the Financial Statements for additional information on income tax.

Preferred Stock dividends. Preferred Stock dividends of $0.4 million and $4.0 million decreased for the three and nine months ended September 30, 2019, respectively, as compared to $1.8 million and $5.5 million for the same periods of 2018. Dividends historically reflected a 10% dividend yield. On July 18, 2019, we redeemed all outstanding shares of the Preferred Stock, after which, the Preferred Stock were no longer deemed outstanding and dividends on the Preferred Stock ceased to accrue. See Note 9 in the Footnotes to the Financial Statements for additional information.

Loss on redemption of preferred stock. As a result of our planned redemption of all outstanding shares of Preferred Stock on July 18, 2019, we recognized a loss on redemption of $8.3 million for the three and nine months ended September 30, 2019. See Note 9 in the Footnotes to the Financial Statements for additional information.

Liquidity and Capital Resources

Historically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions, the sale of debt and equity securities, and non-core asset dispositions. Our primary uses of capital have been for the acquisition and development of oil and natural gas properties, in addition to refinancing of debt instruments. We continue to evaluate other sources of capital to complement our cash flow from operations and as we pursue our long-term growth plans.

As of September 30, 2019, we had $200 million principal outstanding on our Credit Facility, which had a borrowing base of $1.1 billion with an elected commitment of $850 million. At September 30, 2019 and at December 31, 2018, we held cash and cash equivalents of $11.3 million and $16.1 million, respectively.



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



	Nine Months Ended September 30,
(in thousands)	2019			2018
Net cash provided by operating activities	$	338,738		$	316,015
Net cash used in investing activities	(264,261		)	(1,043,010		)
Net cash provided by (used in) financing activities	(79,219		)	711,129
Net change in cash and cash equivalents	$	(4,742	)	$	(15,866	)

Operating activities. For the nine months ended September 30, 2019, net cash provided by operating activities was $338.7 million compared to net cash provided by operating activities of $316.0 million for the same period in 2018. The change was predominantly attributable to the following:


•	An increase in revenues due to higher production volumes, offset by a decrease in realized pricing,


•	An offsetting increase in operating expenses as a result of higher production volumes,


•	An offsetting increase in cash G&A expense due to costs from personnel growth, and


•	Changes related to the timing of working capital payments and receipts.

Production, realized prices, and operating expenses are discussed in Results of Operations. See Notes 6 and 7 in the Footnotes to the Financial Statements for a reconciliation of the components of the Company’s derivative contracts and disclosures related to derivative instruments including their composition and valuation.

Investing activities. For the nine months ended September 30, 2019, net cash used in investing activities was $264.3 million compared to $1,043.0 million for the same period in 2018. The change was predominantly attributable to the following:


•	Acquisitions and divestiture activity, resulting in an increase to net cash provided of $826.8 million, which reflects a combination of proceeds received from our Ranger Asset Divestiture completed in June 2019 and fewer cash outflows from net acquisition activity between the comparative periods.

Our investing activities, on a cash basis, include the following for the periods indicated (in thousands):



	Nine Months Ended September 30,
	2019			2018			$ Change
Operational expenditures	$	416,958		$	411,109		$	5,849
Seismic, leasehold and other	6,794			7,137			(343		)
Capitalized general and administrative costs	23,957			16,544			7,413
Capitalized interest	55,716			20,562			35,154
Total capital expenditures^(a)	503,425			455,352			48,073
Acquisitions	40,788			595,984			(555,196		)
Proceeds from sale of assets	(279,952		)	(8,326		)	(271,626		)
Total investing activities	$	264,261		$	1,043,010		$	(778,749	)


(a)	On an accrual basis, which is the methodology used for establishing our annual capital budget, operational expenditures for the nine months ended September 30, 2019 were $398.3 million. Inclusive of seismic, leasehold and other, capitalized general and administrative, and capitalized interest costs, total capital expenditures for the nine months ended September 30, 2019 were $489.1 million.

See Note 3 in the Footnotes to the Financial Statements for additional information on acquisitions and dispositions.

Financing activities. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our Credit Facility, term debt and equity offerings. For the nine months ended September 30, 2019, net cash used in financing activities was $79.2 million compared to net cash provided by financing activities of $711.1 million for the same period of 2018. In the

second quarter of 2019, the Company completed the Ranger Asset Divestiture for net cash proceeds received at closing of $244.9 million, including customary purchase price adjustments. The proceeds were used to accelerate our debt reduction initiatives and also allow us to retire our preferred stock, reducing our cash financing costs. This reduction in financing activity as compared to the same period in 2018 can also be partially attributed to funding our Delaware Asset Acquisition in the third quarter of 2018.



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

Net cash provided by financing activities includes the following for the periods indicated (in thousands):



	Nine Months Ended September 30,
	2019			2018			$ Change
Net borrowings on Credit Facility	$	—		$	40,000		$	(40,000	)
Issuance of 6.375% senior unsecured notes due 2026	—			400,000			(400,000		)
Issuance of common stock	—			288,364			(288,364		)
Payment of preferred stock dividends	(3,997		)	(5,471		)	1,474
Payment of deferred financing costs	(31		)	(9,960		)	9,929
Tax withholdings related to restricted stock units	(2,174		)	(1,804		)	(370		)
Redemption of preferred stock	(73,017		)	—			(73,017		)
Net cash provided by (used in) financing activities	$	(79,219	)	$	711,129		$	(790,348	)

See Notes 5 and 9 in the Footnotes to the Financial Statements for additional information on our debt and equity transactions.

Capital Plan and Year to Date 2019 Summary

Our original operational capital budget for 2019 was established in the range of $500 to $525 million on an accrual, or GAAP, basis, running an average of five drilling rigs to support larger, and more efficient, multi-well pad development. In June 2019, we lowered our annual operational capital budget to a range of $495 to $520 million to reflect realized efficiencies and cost reductions. Of this range, approximately 15% is comprised of infrastructure and facilities capital. In addition to the operational capital expenditures budget, which includes well costs, facilities and infrastructure capital, and surface land purchases, we budgeted an estimated $100 to $105 million for capitalized interest and general and administrative expenses.

Operational capital expenditures, including other items, on an accrual basis were $405.1 million for the nine months ended September 30, 2019. During the nine months ended September 30, 2019, we placed 47 gross (42.7 net) horizontal wells on production. As of September 30, 2019, we have built a drilled, uncompleted inventory of 18 gross (13.1 net) wells to support a transition to larger pad development. In addition to the operational capital expenditures, $27.4 million of capitalized general and administrative and $56.7 million of capitalized interest expenses were accrued in the nine months ended September 30, 2019.

Our revenues, earnings, liquidity and ability to grow are substantially dependent on the prices we receive for, and our ability to develop our reserves of oil and natural gas. We believe the long-term outlook for our business is favorable due to our resource base, low cost structure, financial strength, risk management, and disciplined investment of capital. We monitor current and expected market conditions, including the commodity price environment, and our liquidity needs and may adjust our capital investment plan accordingly.

Contractual Obligations

We had no material changes in our contractual obligations from amounts listed under “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contractual Obligations” in our Annual Report on Form 10-K for the year ended December 31, 2018.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We mitigate these risks through a program of risk management including the use of derivative instruments.

Commodity price risk

The Company’s revenues are derived from the sale of its oil and natural gas production. The prices for oil and natural gas remain volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, weather conditions, economic conditions and government actions. From time to time, the Company enters into derivative financial instruments to manage oil and natural gas price risk, related both to NYMEX benchmark prices and regional basis differentials. The total volumes which we hedge through use of our derivative instruments varies from period to period; however, generally our objective is to hedge approximately 40% to 60% of our anticipated internally forecast production for the next 12 to 24 months, subject to the covenants under our Credit Facility. Our hedge policies and objectives may change significantly with movements in commodities prices or futures prices.

The Company’s hedging portfolio as of September 30, 2019, indexed to NYMEX benchmark pricing, covers approximately 2,208,000 Bbls and 753,000 MMBtu of our expected oil and natural gas production, respectively, for the remainder of 2019. We also have commodity hedging contracts indexed to Midland WTI oil basis differentials relative to Cushing and Waha natural gas basis differentials covering approximately 2,176,000 Bbls and 2,116,000 MMBtu, respectively, of our expected oil and natural gas production for the remainder of 2019. As of September 30, 2019, we had outstanding oil and natural gas derivative contracts with a net asset position of $17.1 million. The following table provides a sensitivity analysis of the projected incremental effect on income (loss) before income taxes of a hypothetical 10% change in NYMEX WTI, Henry Hub, Midland WTI, Waha, and Houston MEH prices on our open commodity derivative instruments as of September 30, 2019 (in thousands):



	Hypothetical Price Increase of 10%			Hypothetical Price Decrease of 10%
Oil derivatives	$	(33,212	)	$	31,480
Natural gas derivatives	670			(666		)
Total	$	(32,542	)	$	30,814

The Company may utilize fixed price swaps, which reduce the Company’s exposure to decreases in commodity prices and limit the benefit the Company might otherwise have received from any increases in commodity prices. Swap contracts may also be enhanced by the simultaneous sale of call or put options to effectively increase the effective swap price as a result of the receipt of premiums from the option sales.

The Company may utilize price collars to reduce the risk of changes in oil and natural gas prices. Under these arrangements, no payments are due by either party as long as the applicable market price is above the floor price (purchased put option) and below the ceiling price (sold call option) set in the collar. If the price falls below the floor, the counterparty to the collar pays the difference to the Company, and if the price rises above the ceiling, the counterparty receives the difference from the Company. Additionally, the Company may sell put (or call) options at a price lower than the floor price (or higher than the ceiling price) in conjunction with a collar (three-way collar) and use the proceeds to increase either or both the floor or ceiling prices. In a three-way collar, to the extent that realized prices are below the floor price of the sold put option (or above the ceiling price of the sold call option), the Company’s net realized benefit from the three-way collar will be reduced on a dollar-for-dollar basis.

The Company may purchase put and call options, which reduce the Company’s exposure to decreases in oil and natural gas prices while allowing realization of the full benefit from any increases in oil and natural gas prices. If the price falls below the floor, the counterparty pays the difference to the Company.

The Company enters into these various agreements from time to time to reduce the effects of volatile oil and natural gas prices and does not enter into derivative transactions for speculative purposes. Presently, none of the Company’s derivative positions are designated as hedges for accounting purposes. See Note 6 in the Footnotes to the Financial Statements for a description of the Company’s outstanding derivative contracts at September 30, 2019.

Interest rate risk

The Company is subject to market risk exposure related to changes in interest rates on our indebtedness under our Credit Facility. As of September 30, 2019, the Company had $200.0 million outstanding under the Credit Facility with a weighted average interest rate of 3.55%. An increase or decrease of 1.00% in the interest rate would have a corresponding increase or decrease in our annual net income of approximately $2.0 million, based on the balance outstanding at September 30, 2019. See Note 5 in the Footnotes to the Financial Statements for more information on the Company’s interest rates on its Credit Facility.

Counterparty and customer credit risk

The Company’s principal exposures to credit risk are through receivables from the sale of our oil and natural gas production, joint interest receivables and receivables resulting from derivative financial contracts.

The Company markets its oil and natural gas production to energy marketing companies. We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. The inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In order to mitigate potential exposure to credit risk, we may require from time to time for our customers to provide financial security. At September 30, 2019 our total receivables from the sale of our oil and natural gas production were approximately $83.4 million.

Joint interest receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we have or intend to drill. We have little ability to control whether these entities will participate in our wells. At September 30, 2019 our joint interest receivables were approximately $25.1 million.

Our oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. Most of the counterparties on our derivative instruments currently in place are lenders under our Credit Facility. We are likely to enter into additional derivative instruments with these or other lenders under our Credit Facility, representing institutions with investment grade ratings. We have existing International Swap Dealers Association Master Agreements (“ISDA Agreements”) with our derivative counterparties. The terms of the ISDA Agreements provide us and the counterparties with rights of offset upon the occurrence of defined acts of default by either us or a counterparty to a derivative, whereby the party not in default may offset all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party.

The fair value of our contingent consideration arrangement was determined by a third-party valuation specialist using an option pricing model and includes significant inputs such as forward oil price curves, time to expiration, and implied volatility. See Note 7 in the Footnotes to the Financial Statements for more information on the fair value of the contingent consideration arrangement. The following table provides a sensitivity analysis of the projected incremental effect on income (loss) before income taxes based on a hypothetical 10% change in the underlying forward oil price curve as of September 30, 2019 (in thousands):



	Hypothetical Price Increase of 10%		Hypothetical Price Decrease of 10%
Contingent consideration arrangement	$	4,013	$	(3,161	)

Item 4. Controls and Procedures

Disclosure controls and procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Our Chief Executive Officer and Chief Financial Officer performed an evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on this evaluation, our principal executive and principal financial officers have concluded that the Company’s disclosure controls and procedures were effective as of September 30, 2019.

Changes in internal control over financial reporting. There were no changes to our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Part II. Other Information

Item 1. Legal Proceedings

In addition to the below, we are a defendant in various legal proceedings and claims, which arise in the ordinary course of our business. We believe the ultimate resolution of any such actions will not have a material effect on our financial position or results of operations.

On August 28, 2019, a purported shareholder of Carrizo filed an individual complaint in the United States District Court for the District of Delaware, captioned Shiva Stein v. Carrizo Oil & Gas, Inc., Callon Petroleum Company et al., Case No. 1:19-cv-01599-LPS (the “Stein Action”). On September 3, 2019, a purported shareholder of Carrizo filed a complaint in a putative class action in the United States District Court for the District of Delaware, captioned Eric Sabatini v. Carrizo Oil & Gas, Inc., Callon Petroleum Company et al., Case No. 1:19-cv-01644-CFC (the “Sabatini Action”). On September 5, 2019, a purported shareholder of Carrizo filed a complaint in a putative class action in the United States District Court for the District of Delaware, captioned Manoj Fernandes v. Carrizo Oil & Gas, Inc., Callon Petroleum Company et al., Case No. 1:19-cv-01658-LPS (the “Fernandes Action”). On October 9, 2019, a purported shareholder of Callon filed a putative class action in the United States District Court for the District of Delaware, captioned Desmond Davis et al. v. L. Richard Flury et al., Case No. 2019-0811 (the “Davis Action”)

The Stein Action, the Sabatini Action and the Fernandes Action allege that the preliminary joint proxy statement/prospectus, filed with the SEC on August 20, 2019, omits material information with respect to the Merger, rendering it false and misleading and thus that Carrizo, Callon and the directors of Carrizo violated Section 14(a) of the Exchange Act as well as Rule 14a-9 under the Exchange Act. The Stein Action, the Sabatini Action and the Fernandes Action further allege that the directors of Carrizo and Callon violated Section 20(a) of the Exchange Act. The Davis Action alleges that the directors of Callon failed to fulfill their fiduciary duties in connection with the Merger by failing to disclose all material information. The complaints seek injunctive relief enjoining the Merger, damages and costs, among other remedies. It is possible that additional, similar complaints may be filed. The defendants believe that the lawsuits are without merit and intend to vigorously defend them.

Item 1A. Risk Factors

In addition to the other information set forth in this Quarterly Report, you should carefully consider the risk factors and other cautionary statements described under the heading “Item 1A. Risk Factors” included in our 2018 Annual Report on Form 10-K and the risk factors and other cautionary statements contained in our other SEC filings, including our Quarterly Report on Form 10-Q for the period ended June 30, 2019 and our Registration Statement on Form S-4 that was initially filed on August 20, 2019 and declared effective on October 9, 2019, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. There have been no material changes in our risk factors from those described in our 2018 Annual Report on Form 10-K or our other SEC filings, including our Quarterly Report on Form 10-Q for the period ended June 30, 2019 and our Registration Statement on Form S-4 that was initially filed on August 20, 2019 and declared effective on October 9, 2019.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

The following exhibits are filed as part of this Form 10-Q.



			Incorporated by reference (File No. 001-14039, unless otherwise indicated)
Exhibit Number		Description	Form	Exhibit	Filing Date
2.1	±	Agreement and Plan of Merger, dated as of July 14, 2019, by and between Callon and Carrizo	8-K	2.1	07/14/2019
2.2	(a)	Amendment No. 1 to Agreement and Plan of Merger, dated August 19, 2019, by and between Callon and Carrizo
3.1		Certificate of Incorporation of the Company, as amended through May 12, 2016	10-Q	3.1	11/03/2016
3.2		Amended and Restated Bylaws of the Company	10-K	3.2	02/27/2019
10.1		Form of Voting and Support Agreement, dated as of July 14, 2019, by and between Callon and certain Carrizo shareholders	8-K	10.1	07/14/2019
31.1	(a)	Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a)
31.2	(a)	Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a)
32.1	(b)	Section 1350 Certifications of Chief Executive and Financial Officers pursuant to Rule 13(a)-14(b)
101.INS	(a)	XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH	(a)	Inline XBRL Taxonomy Extension Schema Document
101.CAL	(a)	Inline XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF	(a)	Inline XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB	(a)	Inline XBRL Taxonomy Extension Label Linkbase Document.
101.PRE	(a)	Inline XBRL Taxonomy Extension Presentation Linkbase Document.
104	(a)	Cover Page Interactive Data File - the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.


(a)	Filed herewith.

(b)

Furnished herewith. Pursuant to SEC Release No. 33-8212, this certification will be treated as “accompanying” this report and not “filed” as part of such report for purposes of Section 18 of the Exchange Act or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, except to the extent that the registrant specifically incorporates it by reference.


±	Certain schedules and similar attachments have been omitted pursuant to Item 601(a)(5) of Regulation S-K. Callon agrees to furnish a supplemental copy of any omitted schedule or attachment to the SEC upon request.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Callon Petroleum Company



Signature	Title	Date

/s/ Joseph C. Gatto, Jr.	President and	November 4, 2019
Joseph C. Gatto, Jr.	Chief Executive Officer



/s/ James P. Ulm, II	Senior Vice President and	November 4, 2019
James P. Ulm, II	Chief Financial Officer