Table of Contents


Part I. Financial Information

Item 1. Financial Statements (Unaudited)

Consolidated Balance Sheets		5

~~Part I. Financial Information~~

~~Item 1. Financial Statements (Unaudited)~~

~~Consolidated Balance Sheets~~	4

Consolidated Statements of Operations	56

~~Consolidated Statements of Cash Flows~~		6

Consolidated Statements of Stockholders’ Equity	7

Consolidated Statements of Cash Flows		8

Notes to Consolidated Financial Statements		89

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		2430

Item 3. Quantitative and Qualitative Disclosures about Market Risk		3441

Item 4. Controls and Procedures		3542

Part II. Other Information

Item 1. Legal Proceedings		3643

Item 1A. Risk Factors		3643

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		3644

Item 3. Defaults Upon Senior Securities		3644

Item 4. Mine Safety Disclosures		3644

Item 5. Other Information		3644

Item 6. Exhibits		3745

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:

•ASU: accounting standards update.

•Bbl: 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 natural gas. The ratio of one barrel of oil or NGLs 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 an angle within a specified interval.

•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.

•MMBoe: million Boe.

•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.

•OPEC: Organization of Petroleum Exporting Countries.

•Proved reserves: Those reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time.

The area of the reservoir considered as proved includes all of the following:

a.The area identified by drilling and limited by fluid contacts, if any, and

b.Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when both of the following occur:

a.Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based, and

b.The project has been approved for development by all necessary parties and entities, including governmental entities.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12‑month period before the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

•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.

•

~~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

(inIn thousands, except par and share ~~data)~~amounts)

(Unaudited)


	September 30, 2019			December 31, 2018				March 31, 2020	December 31, 2019
ASSETS	Unaudited						ASSETS
Current assets:							Current assets:
Cash and cash equivalents	$	11,309		$	16,051		Cash and cash equivalents	$14,800	$13,341
Accounts receivable	114,120			131,720
Accounts receivable, net							Accounts receivable, net	93,006	209,463
Fair value of derivatives	25,032			65,114			Fair value of derivatives	224,665	26,056
Other current assets	14,912			9,740			Other current assets	24,280	19,814
Total current assets	165,373			222,625			Total current assets	356,751	268,674
Oil and natural gas properties, full cost accounting method:							Oil and natural gas properties, full cost accounting method:
Evaluated properties	4,830,499			4,585,020			Evaluated properties	5,036,095	4,682,994
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			Unevaluated properties	1,809,104	1,986,124
Total oil and natural gas properties, net	3,778,466			3,718,858			Total oil and natural gas properties, net	6,845,199	6,669,118
Operating lease right-of-use assets	24,447			—			Operating lease right-of-use assets	56,050	63,908
Other property and equipment, net	24,770			21,901			Other property and equipment, net	33,216	35,253
Restricted investments	3,490			3,424
Deferred tax asset							Deferred tax asset	51,250	115,720
Deferred financing costs	5,081			6,087			Deferred financing costs	21,383	22,233
Fair value of derivatives	11,209			—			Fair value of derivatives	1,983	9,216
Other assets, net	4,087			6,278			Other assets, net	14,129	10,716
Total assets	$	4,016,923		$	3,979,173		Total assets	$7,379,961	$7,194,838
LIABILITIES AND STOCKHOLDERS’ EQUITY							LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:							Current liabilities:
Accounts payable and accrued liabilities	$	243,481		$	261,184		Accounts payable and accrued liabilities	$525,326	$511,622
Operating lease liabilities	19,196			—			Operating lease liabilities	37,686	42,858
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			Fair value of derivatives	4,851	71,197
Other current liabilities	1,948			13,310			Other current liabilities	15,905	26,570
Total current liabilities	301,011			314,916			Total current liabilities	583,768	652,247
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
Long-term debt							Long-term debt	3,250,912	3,186,109
Operating lease liabilities	4,995			—			Operating lease liabilities	35,746	37,088
Asset retirement obligations	8,294			10,405			Asset retirement obligations	50,531	48,860
Cash-settleable restricted stock unit awards	1,737			2,067
Deferred tax liability	39,007			9,564			Deferred tax liability	—	—
Fair value of derivatives	2,573			7,440			Fair value of derivatives	4,257	32,695
Other long-term liabilities	—			100			Other long-term liabilities	11,844	14,531
Total liabilities	1,548,271			1,533,965			Total liabilities	3,937,058	3,971,530
Commitments and contingencies							Commitments and contingencies
Stockholders’ equity:							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

Common stock, $0.01 par value, 525,000,000 shares authorized; 396,738,180 and 396,600,022 shares outstanding, respectively							Common stock, $0.01 par value, 525,000,000 shares authorized; 396,738,180 and 396,600,022 shares outstanding, respectively	3,967	3,966
Capital in excess of par value	2,421,559			2,477,278			Capital in excess of par value	3,201,105	3,198,076
Retained earnings (accumulated deficit)	44,809			(34,361		)
Retained earnings							Retained earnings	237,831	21,266
Total stockholders’ equity	2,468,652			2,445,208			Total stockholders’ equity	3,442,903	3,223,308
Total liabilities and stockholders’ equity	$	4,016,923		$	3,979,173		Total liabilities and stockholders’ equity	$7,379,961	$7,194,838



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

(1) Effective January 1, 2020, certain of our natural gas processing agreements were modified to allow us to take title to NGLs resulting from the processing of our natural gas. As a result, sales and reserve volumes, prices, and revenues for NGLs and natural gas are presented separately for periods subsequent to January 1, 2020. For periods prior to January 1, 2020, except for sales and reserve volumes, prices, and revenues specifically associated with Carrizo, we presented our sales and reserves volumes, prices, and revenues for NGLs with natural gas.

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~~

(2) Reflects calendar average daily spot market prices.

Revenues

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


	Oil	Natural Gas	NGLs	Total
	(In thousands)
Revenues for the three months ended March 31, 2019	$141,098	$11,949	$—	$153,047
Volume increase (decrease)	147,572	13,383	18,123	179,078
Price increase (decrease)	(22,903)	(19,303)	—	(42,206)
Net increase (decrease)	124,669	(5,920)	18,123	136,872
Revenues for the three months ended March 31, 2020 ⁽¹⁾	$265,767	$6,029	$18,123	$289,919

(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~~Prices

The prices for oil, ~~and~~ natural gas, and NGLs 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~~OPEC and other countries and ~~government actions.~~governments. Prices of oil, ~~and~~ natural gas, and NGLs 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;~~the revolving credit facility; and

•the value of our oil and natural gas properties.

Period over Period Variances

The change in absolute value for the three months ended March 31, 2020 as compared to March 31, 2019 can be primarily attributed to the Carrizo Acquisition which closed in December 2019, which had a material impact to our reported results of operations. In order to provide a more meaningful basis for comparison, we focused our discussion on per unit metrics and only expanded on changes in absolute value where appropriate.

Oil revenue

For the three months ended ~~September 30, 2019,~~March 31, 2020, oil revenues of ~~$148.2~~$265.8 millionincreased ~~$5.6~~$124.7 million, or 4%88%, compared to revenues of ~~$142.6~~$141.1 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.~~2019. The increase was primarily attributable to a ~~32%~~105% increase in production from our acquisition and development efforts, offset by an ~~11%~~8% decrease in the average realized sales price, which fell to ~~$53.38~~$45.45 per Bbl from ~~$59.75~~$49.37 per Bbl.

Natural gas revenue ~~(including NGLs)~~

For the three months ended ~~September 30, 2019,~~March 31, 2020, natural gas revenues of ~~$7.2~~$6.0 million decreased ~~$11.4~~$5.9 million, or ~~61%~~50%, compared to ~~$18.6~~$11.9 million for the same period of ~~2018.~~2019. The decrease was primarily attributable to a ~~65%~~76% decrease in the average realized sales price,which fell to ~~$1.58~~$0.62 per Mcf from ~~$4.49~~$2.59 per Mcf. The decrease in realized natural gas pricing was partially offset by a ~~10%~~112% increase in natural gas volumes.

NGL revenue

For the ~~nine~~three months ended ~~September 30, 2019, natural gas~~March 31, 2020, NGL revenues ~~of $25.4 million decreased $19.8~~were $18.1 million, or ~~44%,~~$10.62 per Bbl, compared to ~~$45.2 million~~no revenues for the same period of ~~2018.~~2019. The ~~decrease~~increase was ~~primarily attributable~~due 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~~modification of certain of our natural gas ~~pricing was partially offset by~~processing agreements, which allowed us to take title to NGLs resulting from the processing of our natural gas. As a ~~26% increase in~~result, sales and reserve volumes, prices, and revenues for NGLs and natural gas ~~volumes.~~



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

are presented separately for periods subsequent to January 1, 2020. For periods prior to January 1, 2020, except for sales and reserve volumes, prices, and revenues specifically associated with Carrizo, we presented our sales and reserves volumes, prices, and revenues for NGLs with natural gas.

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 )%


	Three Months Ended March 31,
		Per		Per	Total Change				Boe Change
	2020	Boe	2019	Boe	$	%		$	%
	(In thousands, except per Boe and % amounts)
Lease operating expenses	$52,383	$5.70	$24,067	$6.63	$28,316	118	%	($0.93)	(14	%)
Production and ad valorem taxes	19,680	2.14	10,813	2.98	8,867	82	%	(0.84)	(28	%)
Gathering, transportation and processing	14,378	1.57	—	—	14,378	100	%	1.57	100	%
Depreciation, depletion and amortization	131,463	14.31	60,184	16.59	71,279	118	%	(2.28)	(14	%)
General and administrative	8,325	0.91	14,777	4.07	(6,452)	(44	%)	(3.16)	(78	%)
Merger and integration expenses	15,830	1.72	—	—	15,830	100	%	1.72	100	%

Lease operating ~~expenses (“LOE”).~~expenses. These are daily costs incurred to extract oil, ~~and~~ natural gas and NGLs 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~~Lease operating expenses for the three months ended ~~September 30, 2019~~March 31, 2020 increased to ~~$19.7~~$52.4 million compared to ~~$18.5~~$24.1 million for the same period of ~~2018.~~2019. The increase in LOE was primarily related to ~~an 8%~~a 153% increase in production over the comparative ~~periods.~~periods, which carries a variable component for each unit of production.

~~LOE~~Lease operating expenses on a per unit basis decreased when comparing the ~~third~~first quarter of ~~2019~~2020 to the same period in ~~2018.~~2019. LOE per BOE decreased to ~~$5.65~~$5.70 for the ~~third~~first quarter of ~~2019,~~2020, which represents a decrease of ~~$0.12~~$0.93 per BOE from the ~~third~~first 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.~~2019. 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~~lower per unit ~~basis increased to $6.16 per BOE compared to $5.43 per BOE for~~metric reflects the ~~same period~~distribution of ~~2018 primarily due to increased non-operated activity related to previous acquisitions and workovers.~~fixed costs spread over higher production volumes.

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~~Production 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. We benefit from tax credits and exemptions in our various taxing jurisdictions where available.

Production taxes for the three months ended ~~September 30, 2019~~March 31, 2020 increased ~~16%~~82% to ~~$11.9~~$19.7 million compared to ~~$10.3~~$10.8 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~~which is ~~partially due~~primarily related to higher ~~severance taxes as a result of higher~~ revenues. ~~Severance~~Production taxes as a percentage of total revenue were consistent across the comparable periods at approximately 5%7%. 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~~jurisdictions.

Gathering, transportation and ~~previous acquisitions.~~processing expenses

~~Production taxes~~. Gathering, transportation and processing costs for the ~~nine~~three months ended ~~September 30, 2019 increased 29% to $33.8 million compared to $26.3 million~~March 31, 2020 were $14.4 million. No expense was recognized for gathering, transportation and processing costs during the same period of ~~2018. On a per BOE basis, production taxes for the nine months ended September 30, 2019 decreased by 2% compared~~2019. The change is due to the ~~same period~~assumption of ~~2018. The increase~~the processing agreements assumed in ~~production taxes is partially due~~the Carrizo acquisition and certain contract modifications effective January 1, 2020. As such, the Company now records contractual fees associated with gathering, processing, treating and compression, as well as any transportation fees incurred to ~~higher severance taxes~~deliver the product to the purchaser, as gathering, transportation and processing expense. These fees were historically recorded as a ~~result~~reduction 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~~depending on when control transferred to 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.

purchaser.

Depreciation, depletion and amortization (“DD&A”). Under the full cost accounting method, we capitalize costs within a cost center and then systematically ~~expense~~amortize those costs on ~~a units-of-production basis~~an equivalent unit-of-production method based on ~~proved oil~~production and ~~natural gas~~estimated proved reserve quantities. ~~We calculate~~Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to twenty years. The following table sets forth the components of our depreciation, depletion onand amortization for 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.periods indicated:


	Three Months Ended March 31,
	2020			2019
	(In thousands, except per Boe amounts)
	Amount	Per Boe	Amount	Per Boe
DD&A of proved oil and gas properties	$129,436	$14.09	$59,767	$16.47
Depreciation of other property and equipment	943	0.10	160	0.04
Amortization of other assets	262	0.03	16	0.01
Accretion of asset retirement obligations	822	0.09	241	0.07
DD&A	$131,463	$14.31	$60,184	$16.59

~~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,~~March 31, 2020, DD&A expense was ~~$56.0~~$131.5 million compared to ~~$48.3~~$60.2 million for the same period of ~~2018.~~2019. The additional DD&A was related to a 8%153% increase in production volumes, ~~combined with higher~~which were partially offset by lower DD&A rates between the ~~periods, which resulted in $4.0~~periods. Those factors accounted for a $79.5 million increase and ~~$3.7~~an $8.2 million offsetting decrease, respectively, ~~of incremental DD&A expense being incurred~~ during the ~~third~~first quarter of ~~2019.~~

2020.

For the three months ended ~~September 30, 2019,~~March 31, 2020, DD&A on a per unit basis ~~increased~~decreased to ~~$16.09~~$14.31 per BOE compared to ~~$15.02~~$16.59 per BOE for the same period of ~~2018.~~2019. The ~~primary factor contributing~~rate primarily decreased as a result of the Carrizo acquisition which contributed 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~~a significant increase in our ~~historical rate. Additionally, the rate increase can be partially attributed to recent dispositions with~~proved reserves at a lower relative cost per ~~BOE.~~

~~For the nine months ended September 30, 2019,~~BOE than our historical 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~~March 31, 2020 decreased to ~~$9.4~~$8.3 million compared to ~~$9.7~~$14.8 million for the same period of ~~2018. On~~2019. The decrease was primarily due to a ~~per unit basis, G&A decreased 11% to $2.70 per BOE~~share-based compensation benefit, net as a result of a decrease in the fair value of the Cash-Settled RSU Awards and Cash SARs for the three months ended ~~September 30, 2019~~March 31, 2020 as compared to ~~$3.03 per BOE~~share-based compensation expense, net 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~~three 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.March 31, 2019.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,~~March 31, 2020, the Company incurred ~~$5.9~~$15.8 million of ~~expense~~expenses associated with the ~~planned~~Carrizo Acquisition. See “Note 3 – Acquisitions and Divestitures” of the Notes to our Consolidated Financial Statements for additional information regarding the merger with ~~Carrizo Oil & Gas, Inc.~~Carrizo.



	~~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 March 31,
	2020	2019	$ Change	% Change
	(In thousands, except % amounts)
Interest expense	$44,463	$20,582	$23,881	116	%
Capitalized interest	(23,985)	(19,844)	(4,141)	21	%
Interest expense, net of capitalized amounts	20,478	738	19,740	2,675	%
(Gain) loss on derivative contracts	($251,969)	$67,260	($319,229)	(475	%)

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~~revolving 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, and interest from our financing leases in interest expense.

Interest expense, net of capitalized amounts, incurred during the three months ended ~~September 30, 2019~~March 31, 2020 increased ~~$0.0~~$19.7 million to ~~$0.7~~$20.5 million compared to $0.7 million for the same period of ~~2018. Interest expense, net~~2019. The increase is primarily due to debt that was assumed as a result 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~~

Carrizo Acquisition.

Gain (loss) on derivative ~~instruments.~~contracts. 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):~~following:

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 )


	Three Months Ended March 31,
	2020	2019
	(In thousands)
Gain (loss) on oil derivatives	$257,323	($68,369)
Gain (loss) on natural gas derivatives	(6,829)	1,109
Gain on contingent consideration arrangements	1,475	—
Gain (loss) on derivative contracts	$251,969	($67,260)

See “Note 7 - Derivative Instruments and Hedging Activities” and “Note 8 - Fair Value Measurements” of the Notes ~~6 and 7 in the Footnotes~~ to ~~the~~our Consolidated Financial Statements for additional ~~information on the Company’s derivative contracts and disclosures related to derivative instruments.~~

information.

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~~recorded income tax expense of ~~$17.9~~$64.0 million for the three months ended ~~September 30, 2019,~~March 31, 2020, compared to income tax ~~expense~~benefit of ~~$1.5~~$5.1 million for the same period of ~~2018.~~2019. The ~~Company had~~change is primarily related to income ~~tax expense of $29.4 million~~before income taxes for the ~~nine~~three months ended ~~September 30, 2019,~~March 31, 2020 of $280.6 million compared to a loss before income ~~tax expense~~taxes of ~~$2.5~~$24.7 million for the same period in 2019. See “Note 9 - Income Taxes” of ~~2018. The change in income tax is primarily related~~the Notes 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 theConsolidated Financial Statements for additional information on income tax.

Preferred stock dividends. On July 18, 2019, we redeemed all outstanding shares of Preferred Stock, ~~dividends.~~after which, the Preferred Stock was no longer deemed outstanding and dividends ceased to accrue. As such, we did not make any Preferred Stock dividend payments during the three months ended March 31, 2020. Preferred Stock dividends of ~~$0.4~~$1.8 million were paid during the three months ended March 31, 2019.

Liquidity and ~~$4.0 million decreased~~Capital Resources

Our primary uses of capital have historically been for the ~~three~~acquisition, development, and ~~nine~~exploration of oil and natural gas properties. Our capital program could vary depending upon factors, including, but not limited to, the availability of drilling rigs and completion crews, the cost of completion services, acquisitions and divestitures of oil and gas properties, land and industry partner issues, our available cash flow and financing, success of drilling programs, weather delays, commodity prices, market conditions, the acquisition of leases with drilling commitments and other factors. In addition, depending upon our actual and anticipated sources and uses of liquidity, prevailing market conditions and other factors, we may, from time to time, seek to retire or repurchase our outstanding debt or equity securities through cash purchases in the open market or through privately negotiated transactions or otherwise. The amounts involved in any such transactions, individually or in aggregate, may be material.

Historically, our primary sources of capital have been cash flows from operations, borrowings under our revolving credit facility, proceeds from the issuance of debt securities and public equity offerings, and non-core asset dispositions. We regularly consider which resources, including debt and equity financings, are available to meet our future financial obligations, planned capital expenditures and liquidity requirements.

Overview of Cash Flow Activities. For the three months ended ~~September 30, 2019, respectively, as~~March 31, 2020, cash and cash equivalents decreased $1.5 million to $14.8 million compared to ~~$1.8~~$13.3 million ~~and $5.5~~at December 31, 2019.


	Three Months Ended March 31,
	2020	2019
	(In thousands)
Net cash provided by operating activities	$191,695	$74,559
Net cash used in investing activities	(254,366)	(207,279)
Net cash provided by (used in) financing activities	64,130	127,151
Net change in cash and cash equivalents	$1,459	($5,569)

Operating activities. For the three months ended March 31, 2020, net cash provided by operating activities was $191.7 million compared to net cash provided by operating activities of $74.6 million for the same period in 2019. The change in operating activities was predominantly attributable to the following:

•An increase in revenue due to a 153% increase in production volumes predominantly as a result of the Carrizo Acquisition, which was partially offset by a decrease in realized pricing,

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

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

Production, realized prices, and operating expenses are discussed in Results of Operations. See “Note 7 - Derivative Instruments and Hedging Activities” and “Note 8 - Fair Value Measurements” of the Notes to our Consolidated 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 three months ended March 31, 2020, net cash used in investing activities was $254.4 million compared to $207.3 million for the same period in 2019.

Our investing activities include the following for the periods indicated:


	Three Months Ended March 31,
	2020	2019	$ Change
	(In thousands)




Capital expenditures	$224,448	$193,211	$31,237
Acquisitions	—	27,947	(27,947)
Proceeds from the sale of assets	(10,240)	(13,879)	3,639
Cash paid for settlements of contingent consideration arrangements, net	40,000	—	40,000
Additions to other assets	158	—	158
Total investing activities	$254,366	$207,279	$47,087

Capital expenditures increased by approximately $47.1 million for the three months ended March 31, 2020 compared to the same period in 2019 due primarily to $40.0 million of ~~2018. Dividends historically reflected~~net cash payments for settlements of contingent consideration arrangements.

Financing activities. We finance a ~~10% dividend yield.~~portion of our capital expenditures, acquisitions and working capital requirements with borrowings under our credit facility, term debt and equity offerings. For the three months ended March 31, 2020, net cash provided by financing activities was $64.1 million compared to $127.2 million for the same period of 2019.

Net cash provided by financing activities includes the following for the periods indicated:


	Three Months Ended March 31,
	2020	2019	$ Change
	(In thousands)
Net borrowings on Credit Facility	$65,000	$130,000	($65,000)







Payment of deferred financing costs	(275)	—	(275)
Payment of preferred stock dividends⁽¹⁾	—	(1,824)	1,824
Tax withholdings related to restricted stock units	(313)	(1,025)	712
Other, net	(282)	—	—
Net cash provided by (used in) financing activities	$64,130	$127,151	($62,739)

(1) 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~~“Note 6 - Borrowings” 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~~“Note 10 - Stockholders’ Equity” of the ~~components of the Company’s derivative contracts and disclosures related~~Notes 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~~Consolidated Financial Statements for additional information on our debt and equity transactions.

Senior Secured Revolving Credit Facility. We have a senior secured revolving credit facility with a syndicate of lenders that, as of March 31, 2020, had a borrowing base of $2.5 billion, with an elected commitment amount of $2.0 billion, borrowings outstanding of $1.35 billion at a weighted average interest rate of 2.83%, and $17.7 million in letters of credit outstanding. The borrowing base under the credit agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. The revolving credit facility is secured by first preferred mortgages covering our major producing properties. The capitalized terms which are not defined in this description of the revolving credit facility shall have the meaning given to such terms in the credit agreement.

On May 7, 2020, we entered into the first amendment to our credit agreement governing the revolving credit facility. The amendment, among other things, (a) establishes a new borrowing base as a result of the spring 2020 scheduled redetermination in the amount of $1.7 billion and reduces the elected commitments to $1.7 billion; (b) permits the incurrence of, among other things, new second lien notes in an aggregate principal amount of up to $400 million (the “Second Lien Notes”) so long as any such Second Lien Notes are subject to an intercreditor agreement providing that the liens securing the Second Lien Notes rank junior to the liens securing the credit agreement; (c) provides that testing of the ratio of consolidated total debt to Adjusted EBITDAX on a quarterly basis is suspended until March 31, 2022, as of which testing date and the last day of each fiscal quarter ending thereafter, such ratio may not exceed 4.00 to 1.00; (d) provides a new financial covenant testing the ratio of the consolidated total secured debt to Adjusted EBITDAX and provides that such ratio on a quarterly basis as of the last day of each quarter beginning with March 31, 2020 up to and including the quarter ending December 31, 2021 may not exceed 3.00 to 1.00; (e) provides that the testing of the ratio of current assets to current liabilities is suspended until September 30, 2020, as of which testing date and the last day of each fiscal quarter ending thereafter, such ratio may not be less than 1.00 to 1.00; (f) increases the applicable margins for borrowings under the credit agreement for both LIBOR loans and base rate loans by 75 basis points across all commitment utilization ranges; (g) introduces customary anti-cash hoarding protections tested weekly, which restrict our ability to maintain unrestricted cash on our balance sheet in amounts in the excess of the lesser of (i) $125.0 million or (ii) 7.5% of the then current borrowing base; (h) requires us to enter into and maintain minimum hedges for the 12 month period starting January 1, 2021 through December 31, 2021, for which the net notional volumes on a barrel of oil equivalent basis are not less than 40% of the reasonably anticipated production from our oil and gas properties which are classified as proved developed producing reserves as of April 1, 2020; (i) requires mortgage and title coverage on at least 90% of the total value of proved oil and gas properties evaluated in the most recently delivered reserve report; and (j) restricts our ability to make certain investments and cash distributions by lowering the maximum leverage ratio required to make such distributions to 2.50 to 1.00.

We expect to have sufficient liquidity to pay interest on our revolving credit facility and our Senior Notes. However, there could be substantial doubt about our ability to continue as a going concern if our borrowing base is redetermined below our current outstanding borrowings and we are unable to repay the deficiency promptly. If the current commodity price environment were to persist for an extended period, our ability to remain in compliance with our restrictive covenants could be challenged. If we are unable to remain in compliance with our restrictive covenants, we could be subject to lender elections for default resolution.

See “Note 6 – Borrowings” of the Notes to our Consolidated Financial Statements for additional information.

Hedging. As of April 30, 2020, the Company had the following outstanding derivative contracts:


	For the Remainder		For the Full Year
Oil contracts (WTI)	of 2020		of 2021
Swap contracts
Total volume (Bbls)	14,000,720		—
Weighted average price per Bbl	$41.31		$—
Swap contracts with short puts
Total volume (Bbls)	1,650,000		—
Weighted average price per Bbl - Swap	$56.06		$—
Weighted average price per Bbl - Floor (short put)	$42.50		$—
Short call contracts
Total volume (Bbls)	2,750,000	⁽¹⁾	4,825,300	⁽¹⁾
Weighted average price per Bbl	$45.59		$63.62
Oil contracts (WTI Calendar Month Average Roll)
Swap contracts
Total volume (Bbls)	5,697,500		—
Weighted average price per Bbl	($2.66)		$—
Oil contracts (Brent ICE differential)
Swap contracts
Total volume (Bbls)	396,800
Weighted average price per Bbl	($4.00)
Oil contracts (Brent ICE swaps)
Swap contracts
Total volume (Bbls)	366,000		—
Weighted average price per Bbl	$46.15		$—
Oil contracts (Midland basis differential)
Swap contracts
Total volume (Bbls)	6,574,800		4,015,100
Weighted average price per Bbl	($1.24)		$0.40
Oil contracts (Argus Houston MEH basis differential)
Swap contracts
Total volume (Bbls)	4,612,205		—
Weighted average price per Bbl	($0.24)		$—
Oil contracts (Argus Houston MEH swaps)
Swap contracts
Total volume (Bbls)	504,500		—
Weighted average price per Bbl	$58.22		$—
Natural gas contracts (Henry Hub)
Collar contracts
Total volume (MMBtu)	1,525,000		7,750,000
Weighted average price per MMBtu - Ceiling (short call)	$3.25		$2.93
Weighted average price per MMBtu - Floor (long put)	$2.67		$2.55
Collar contracts (three-way collars)
Total volume (MMBtu)	3,665,000		1,350,000
Weighted average price per MMBtu - Ceiling (short call)	$2.74		$2.70
Weighted average price per MMBtu - Floor (long put)	$2.48		$2.42
Weighted average price per MMBtu - Floor (short put)	$2.00		$2.00
Swap contracts
Total volume (MMBtu)	9,170,000		8,675,000
Weighted average price per MMBtu	$2.20		$2.70
Short call contracts
Total volume (MMBtu)	9,075,000		7,300,000
Weighted average price per MMBtu	$3.50		$3.09
Natural gas contracts (Waha basis differential)
Swap contracts
Total volume (MMBtu)	18,982,000		—
Weighted average price per MMBtu	($1.08)		$—

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

Preferred Stock. Holders of the Preferred Stock were entitled to receive, when, as and if declared by the Board of Directors, out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of 10% 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 Board of Directors. Preferred Stock dividends were $1.8 million for the three months ended March 31, 2019.

On July 18, 2019 (the “Redemption Date”), the Preferred Stock were redeemed at a 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 or $73.0 million (the “Redemption Price”).

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.

2020 Capital Plan and ~~Year to Date 2019 Summary~~

Outlook

Our original operational capital budget for ~~2019~~2020 was established ~~in the range of $500 to $525~~at $975.0 million, ~~on an accrual, or GAAP, basis,~~which included running an average of ~~five~~eight to nine drilling rigs ~~to support larger,~~ and ~~more efficient, multi-well pad development.~~an average of three completion crews. In ~~June 2019,~~March 2020, we lowered our annual operational capital budget to a range of ~~$495 to $520~~$700.0 million to ~~reflect realized efficiencies~~$725.0 million, reflecting the initial reduction in capital development activity. We have further reduced activity relative to that plan, including the suspension of all completion activity in April and ~~cost reductions. Of this range, approximately 15% is comprised of infrastructure and facilities capital. In addition~~transitioning to ~~the~~one active drilling rig by mid-May. We currently forecast total operational capital expenditures ~~budget, which includes well costs, facilities and infrastructure capital, and surface land purchases,~~of approximately $250.0 to $325.0 million over the remaining three quarters of 2020, assuming resumption of a reduced level of completion activities in the second half of the year. As a result, 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 thecurrently expect annual operational capital expenditures ~~$27.4 million~~to be a maximum of ~~capitalized general and administrative and $56.7 million of capitalized interest expenses were accrued in the nine months ended September 30, 2019.~~

$525.0 to $600.0 million.

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~~proved reserves. Despite near-term challenges due to COVID-19, 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 we may adjust our capital investment plan accordingly.

Additionally, we may consider divesting certain properties or assets that are not part of our core business or are no longer deemed essential to our future growth, provided we are able to divest such assets on terms that are acceptable to us.

Contractual Obligations

The following table includes our current contractual obligations and purchase commitments as of March 31, 2020:


	Payments due by Period
	April - December 2020	2021	2022	2023	2024 and Thereafter	Total
	(In thousands)
6.25% Senior Notes ⁽¹⁾	$—	$—	$—	$650,000	$—	$650,000
6.125% Senior Notes⁽¹⁾	—	—	—	—	600,000	600,000
8.25% Senior Notes ⁽¹⁾	—	—	—	—	250,000	250,000
6.375% Senior Notes ⁽¹⁾	—	—	—	—	400,000	400,000
Senior secured revolving credit facility⁽²⁾	—	—	—	—	1,350,000	1,350,000
Interest expense and other fees related to debt commitments ⁽³⁾	131,327	151,935	151,935	131,623	181,694	748,514
Drilling rig leases⁽⁴⁾	26,240	3,249	—	—	—	29,489
Operating leases	11,328	10,033	5,369	5,012	22,990	54,732
Delivery commitments ⁽⁵⁾	8,866	13,437	10,980	11,553	51,715	96,551
Produced water disposal commitments ⁽⁶⁾	12,001	14,968	11,933	4,387	3,410	46,699
Asset retirement obligations⁽⁷⁾	883	820	419	191	49,101	51,414
Other commitments	1,516	845	508	392	39	3,300
Total contractual obligations	$192,161	$195,287	$181,144	$803,158	$2,908,949	$4,280,699

(1)Includes the outstanding principal amount only.

(2)The revolving credit facility has a maturity date of December 20, 2024, subject to springing maturity dates as discussed above. See “Note 6 – Borrowings” of the Notes to our Consolidated Financial Statements for additional information.

(3)Includes estimated cash payments on the 6.25% Senior Notes, 6.125% Senior Notes, 8.25% Senior Notes, 6.375% Senior Notes, the Credit Facility and commitment fees calculated based on the unused portion of lender commitments as of March 31, 2020, at the applicable commitment fee rate.

(4)Drilling rig leases represent future minimum expenditure commitments for drilling rig services under contracts to which the Company was a party on March 31, 2020. The value in the table represents the gross amount that we are committed to pay. However, we will record our proportionate share based on our working interest in our consolidated financial statements as incurred.

(5)Delivery commitments represent contractual obligations we have entered into for certain gathering, processing and transportation service agreements which require minimum volumes of oil and natural gas to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any oil or natural gas.

(6)Produced water disposal commitments represent contractual obligations we have entered into for certain service agreements which require minimum volumes of produced water to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any produced water.

(7)Amounts represent our estimates of future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment.

Critical Accounting Policies

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Certain of such estimates and assumptions are inherently unpredictable and will differ from actual results. We have identified the following critical accounting policies and estimates used in the preparation of our financial statements: use of estimates, oil and gas properties, oil and gas reserve estimates, derivative instruments, contingent consideration arrangements, income taxes, and commitments and contingencies. These policies and estimates are described in “Note 2 - Summary of Significant Accounting Policies” of the Notes to Consolidated Financial Statements in our 2019 Annual Report. See “Note 7 - Derivative Instruments and Hedging Activities” and “Note 8 - Fair Value Measurements” for details of the contingent consideration arrangements. We evaluate subsequent events through the date the financial statements are issued.

The table below presents various pricing scenarios to demonstrate the sensitivity of our March 31, 2020 cost center ceiling to changes in 12-month average benchmark crude oil and natural gas prices underlying the 12-Month Average Realized Prices. The sensitivity analysis is as of March 31, 2020 and, accordingly, does not consider drilling and completion activity, acquisitions or dispositions of oil and gas properties, production, changes in crude oil and natural gas prices, and changes in development and operating costs occurring subsequent to March 31, 2020 that may require revisions to estimates of proved reserves.


	12-Month Average Realized Prices			Excess of cost center ceiling over net book value, less related deferred income taxes	Increase (decrease) of cost center ceiling over net book value, less related deferred income taxes
Full Cost Pool Scenarios	Crude Oil ($/Bbl)	Natural Gas ($/Mcf)	(In millions)	(In millions)
March 31, 2020 Actual	$54.63	$0.84	$402

Crude Oil and Natural Gas Price Sensitivity
Crude Oil and Natural Gas +10%	$60.21	$1.08	$1,180	$778
Crude Oil and Natural Gas -10%	$49.05	$0.61	($585)	($987)

Crude Oil Price Sensitivity
Crude Oil +10%	$60.21	$0.84	$1,133	$731
Crude Oil -10%	$49.05	$0.84	($526)	($928)

Natural Gas Price Sensitivity
Natural Gas +10%	$54.63	$1.08	$449	$47
Natural Gas -10%	$54.63	$0.61	$346	($56)

We estimate that the second quarter of 2020 cost center ceiling will not exceed the net book value, less related deferred income taxes, resulting in a write-down of evaluated oil and gas properties. This estimate of the second quarter of 2020 cost center ceiling test is based on an estimated 12-Month Average Realized Price of crude oil of approximately $45.00 per barrel as of June 30, 2020, which is based on the average realized price for sales of crude oil on the first calendar day of each month for the first 11 months and an estimate for the twelfth month based on a quoted forward price.

Both of these estimates assume that all other inputs and assumptions are as of March 31, 2020, other than the price of crude oil, and remain unchanged. As such, drilling and completion activity, acquisitions or dispositions of oil and gas properties, production, and changes in development and operating costs occurring subsequent to March 31, 2020 may require revisions to estimates of proved reserves, which would impact the calculation of the cost center ceiling.

Income taxes

The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and natural gas prices). The Company had no ~~material changes~~valuation allowance as of March 31, 2020 and 2019. However, given our current estimate that we will recognize a write-down of our evaluated properties in the second quarter of 2020, it is possible that we will not be able to conclude that it is more likely than not that the deferred tax assets will be realized and we will record a valuation allowance against the net deferred tax assets later in 2020. Any valuation allowance recorded does not preclude us from utilizing the tax attributes if we recognize taxable income. See “Note 9 - Income Taxes” of the Notes to our ~~contractual obligations from amounts listed under “Part II, Item 7. Management’s Discussion~~Consolidated Financial Statements for additional information regarding income taxes.

Recently Adopted and ~~Analysis~~Recently Issued Accounting Pronouncements

See “Note 1 - Description of ~~Financial Condition~~Business and ~~Results~~Basis of ~~Operations—Contractual Obligations” in our Annual Report on Form 10-K~~Presentation” for discussion of the ~~year ended December 31, 2018.~~pronouncements we recently adopted.

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 credit risk. We mitigate these risks through a program of risk management including the use of commodity 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~~period. 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~~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,~~March 31, 2020, for the remainder of ~~2019. We~~2020, the Company had 15,606,220 Bbls of fixed price oil hedges across NYMEX WTI, ICE Brent and Argus WTI-Houston benchmarks. The Company also ~~have commodity hedging contracts indexed to Midland~~had 6,574,800 Bbls of WTI Midland-Cushing oil basis ~~differentials relative to Cushing~~hedges and4,612,205 Bbls of WTI Houston-Cushing oil basis hedges. Additionally, for the remainder of 2020, the Company had 12,835,000 MMBtus of fixed price NYMEX natural gas hedges and 18,982,000 MMBtus of Waha natural gas basis ~~differentials covering approximately 2,176,000 Bbls~~hedges. See “Note 7 - Derivative Instruments and ~~2,116,000 MMBtu, respectively,~~Hedging Activities” of the Notes to our ~~expected oil and natural gas production~~Consolidated Financial Statements for a description of the ~~remainder of 2019. As of September 30, 2019, we had~~Company’s 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

March 31, 2020.

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,~~puts, 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,~~March 31, 2020, the Company had ~~$200.0 million~~$1.4 billion outstanding under the Credit Facility with a weighted average interest rate of ~~3.55%~~2.83%. 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~~$13.5 million, based on the balance outstanding at ~~September 30, 2019.~~March 31, 2020. See ~~Note 5 in~~“Note 6 - Borrowings” of the ~~Footnotes~~Notes to ~~the~~our Consolidated Financial Statements for more information on the Company’s interest rates on ~~its~~our 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 and NGL production to energy marketing companies. We are subject to credit risk due to the concentration of our oil, ~~and~~ natural gas and NGL 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~~March 31, 2020 our total receivables from the sale of our oil and natural gas production were approximately ~~$83.4 million.~~$66.2 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~~March 31, 2020 our joint interest receivables were approximately ~~$25.1 million.~~$23.0 million.

Our oil and natural gas commodity derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. ~~Most~~All of the counterparties on our commodity derivative instruments currently in place are lenders under our Credit Facility. We are likely to enter into additional commodity 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~~ISDA Agreements ~~(“ISDA Agreements”)~~ with our commodity 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 commodity derivative, whereby the party not in default may offset all commodity derivative liabilities owed to the defaulting party against all commodity derivative asset receivables from the defaulting party. At March 31, 2020, we had a net commodity derivative asset position of $219.9 million.

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.~~March 31, 2020.

Changes in internal control over financial reporting. The Company recently completed the implementation of Enertia Software (“Enertia”), which is an integrated enterprise solution for managing accounting and financial reporting information, and utilized Enertia for its accounting and reporting for the quarter ended March 31, 2020. The Company believes the implementation of the system and related changes to internal controls will enhance internal controls over financial reporting. The Company has updated its internal controls, as applicable, to facilitate modifications to its business processes and accounting procedures and will continue to evaluate the operating effectiveness of related key controls during subsequent periods. The Company does not believe that the Enertia implementation has had an adverse effect on its internal control over financial reporting.

There were no other changes to our internal control over financial reporting during ~~our last fiscal quarter~~the three months ended March 31, 2020 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~~We are a defendant in various legal proceedings and claims, which arise in the ordinary course of our business. WeWhile the outcome of these events cannot be predicted with certainty, we believe that 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~~2019 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.

The widespread outbreak of an illness, pandemic or any other public health crisis may have material adverse effects on our business, financial position, results of operations and/or cash flows. The recent worldwide outbreak of COVID-19, the uncertainty regarding the impact of COVID-19 and various governmental actions taken to mitigate the impact of COVID-19, have resulted in an unprecedented decline in demand for oil and natural gas. At the same time, the decision by Saudi Arabia in March 2020 to drastically reduce export prices and increase oil production followed by curtailment agreements among OPEC and other countries such as Russia further increased uncertainty and volatility around global oil supply-demand dynamics.The COVID-19 pandemic has negatively impacted the global economy, disrupted global supply chains, reduced global demand for oil and natural gas, and created significant volatility and disruption of financial and commodity markets. The extent of the impact of the COVID-19 pandemic on our operational and financial performance, including our ability to execute our business strategies and initiatives in the expected time frame, is uncertain and depends on various factors, including the demand for oil and natural gas, the availability of personnel, equipment and services critical to our ability to operate our properties and the impact of potential governmental restrictions on travel, transports and operations. There is uncertainty around the extent and duration of the disruption. The degree to which the COVID-19 pandemic or any other public health crisis adversely impacts our results will depend on future developments, which are highly uncertain and cannot be predicted, including, but not limited to, the duration and spread of the outbreak, its severity, the actions to contain the virus or treat its impact, its impact on the economy and market conditions, and how quickly and to what extent normal economic and operating conditions can resume. Therefore, while the Company expects this matter will likely disrupt our operations in some way, the degree of the adverse financial impact cannot be reasonably estimated at this time.

The excess supply of oil and natural gas resulting from the reduced demand caused by the COVID-19 pandemic and the effects of actions by, or disputes among or between, oil and natural gas producing countries has resulted in transportation and storage constraints, and may cause us to reduce production and shut-in our wells, any of which could adversely affect our business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures. As a result of the COVID-19 pandemic and the effects of actions by, or disputes among or between, oil and natural gas producing countries, there is an excess supply of oil, NGLs, and natural gas in the United States, which could continue for a sustained period. This excess supply has, in turn, resulted in transportation and storage capacity constraints in the United States, and may even cause the elimination of available storage, including in the Permian Basin. If, in the future, our transportation or storage arrangements become constrained or unavailable, we may incur significant operational costs if there is an increase in price for services or we may be required to shut-in or curtail production or flare our natural gas. If we were required to shut-in wells, we might also be obligated to pay certain demand charges for gathering and processing services and firm transportation charges for pipeline capacity we have ~~been~~reserved. Further, any prolonged shut-in of our wells may result in materially decreased well productivity once we are able to resume operations, and any cessation of drilling and development of our acreage could result in the expiration, in whole or in part, of our leases. All of these impacts resulting from the confluence of the COVID-19 pandemic and the price war between Saudi Arabia and Russia may adversely affect our business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures.

Due to the commodity price environment, we have postponed or eliminated a portion of our developmental drilling. A sustained period of weakness in oil, natural gas and NGLs prices, and the resultant effects of such prices on our drilling economics and ability to raise capital, will require us to reevaluate and further postpone or eliminate additional drilling. Additionally, as of March 31, 2020, approximately 35% of our total net acreage was not held by production and we had undeveloped leases representing 5% and 1% of our total net acreage scheduled to expire during 2020 and during 2021, respectively, in each case assuming no exercise of lease extension options where applicable. If we are required to further curtail our drilling program, we may be unable to continue to hold such leases that are scheduled to expire, which may further reduce our reserves. As a result, if oil, natural gas and/or NGL prices experience a sustained period of weakness, our future business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures may be materially and adversely affected.

Our production is not fully hedged, and we are exposed to fluctuations in oil, natural gas and NGL prices and will be affected by continuing and prolonged declines in oil, natural gas and NGL prices. Our production is not fully hedged, and we are exposed

to fluctuations in oil, natural gas and NGL prices and will be affected by continuing and prolonged declines in oil, natural gas and NGL prices. 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 60% of our anticipated internally forecast production for the next 12 to 24 months, subject to the covenants under our revolving credit facility. We intend to continue to hedge our production, but we may not be able to do so at favorable prices. Accordingly, our revenues and cash flows are subject to increased volatility and may be subject to significant

reduction in prices which would have a material ~~changes~~negative impact on our results of operations.

We cannot assure you that in connection with our ~~risk factors from those~~semi-annual borrowing base redeterminations, our borrowing base will not be reduced to a lesser amount than what we expect. The borrowing base under our revolving credit facility is redetermined semiannually in the spring and fall, as well as special redeterminations described in the credit agreement governing the revolving credit facility. The lenders have sole discretion in determining the amount of the borrowing base and may cause our ~~2018 Annual Report~~borrowing base to be redetermined to a materially lower amount, including to below our outstanding borrowings as of such redetermination, which would adversely affect our development plans as currently anticipated and could have a material adverse effect on ~~Form 10-K or~~ our production, revenues and results of operations.

If we cannot meet the continued listing requirements of the NYSE, the NYSE may delist our common stock. On April 10, 2020, we received written notification from the NYSE that the average closing price of our common stock had fallen below $1.00 per share over a period of 30 consecutive trading days, which is the minimum average closing share price required to maintain listing on the NYSE under Section 802.01C of the NYSE Listed Company Manual. The notice has no immediate impact on the listing of our common stock, which will continue to be listed and traded on the NYSE during this period, subject to our compliance with other ~~SEC filings, including our Quarterly Report~~listing standards. Our common stock is permitted to continue to trade on ~~Form 10-Q~~the NYSE under the symbol “CPE.” but will have an added designation of “.BC” to indicate the status of the common stock as “below compliance.”

We informed the NYSE that we intend to cure the deficiency and to return to compliance with the NYSE continued listing requirement. We initially had until October 10, 2020 to regain compliance with the minimum share price requirement, but due to recent market turmoil the NYSE has filed a rule change tolling the compliance periods for ~~the period ended~~price-based listing requirements through June 30, ~~2019~~2020, which extended our compliance period until December 18, 2020. We can regain compliance at any time during the cure period if our common stock has a closing share price of at least $1.00 on the last trading day of any calendar month during the cure period and also has an average closing share price of at least $1.00 over the 30-trading day period ending on the last trading day of that month.

Further, our ~~Registration Statement~~common stock could be delisted if (i) our average market capitalization over a consecutive 30 trading-day period is less than $15 million, or (ii) our common stock trades at an “abnormally low” price, which in either case, we would not have an opportunity to cure the deficiency, our common stock would be suspended from trading on ~~Form S-4~~the NYSE immediately, and the NYSE would begin the process to delist our common stock, subject to our right to appeal under NYSE rules. There is no assurance that ~~was initially filed on August 20, 2019~~any appeal we undertake in these or other circumstances will be successful. While we are considering various options, it may take a significant effort to cure this deficiency and ~~declared effective on October 9, 2019.~~regain compliance with this continued listing standard, and there can be no assurance that we will be able to cure this deficiency or if we will cease to comply with another NYSE continued listing standard.

If our common stock ultimately were to be delisted for any reason, it could negatively impact us by, among other things, reducing the liquidity and market price of our common stock, reducing the number of investors willing to hold or acquire our common stock, and negatively impacting our ability to access equity markets and obtain financing.

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

We are providing the following disclosure in lieu of filing a Current Report on Form 8-K relating to “Item 1.01 Entry into a Material Definitive Agreement” and “Item 2.03 Creation of Direct Financial Obligation or an Obligation under an Off-Balance Sheet Arrangement of a Registrant” of Form 8-K.

~~None.~~On May 7, 2020, the Company entered into the first amendment to its credit agreement governing the revolving credit facility. For a description of that amendment, please see “Note 15 - Subsequent Events—First Amendment to the Credit Agreement” above, which is incorporated herein by reference. The description of such amendment is qualified in its entirety by reference to the amendment, a copy of which is attached hereto as Exhibit 10.1 and is incorporated into this “Item 5. Other Information” by reference.

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

3.1

Certificate of Incorporation of the Company, as amended through May 12, 2016

10-Q

3.1

11/03/2016

3.2

Certificate of Amendment to the Certificate of Incorporation of Callon, effective December 20, 2019

8-K

3.1

11/20/2019

3.3

Amended and Restated Bylaws of the Company

10-K

3.2

2/27/2019

10.1

(a)(c)

First Amendment, dated May 7, 2020, to the Credit Agreement by and between Callon Petroleum Company and JPMorgan Chase Bank, N.A., as administrative agent, and the lender parties thereto

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.

(c)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.

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

~~Signature~~		~~Title~~	~~Date~~

/s/ Joseph C. Gatto, Jr.	President and		~~November 4, 2019~~May 11, 2020
Joseph C. Gatto, Jr.		Chief Executive Officer



/s/ James P. Ulm, II	Senior Vice President and	~~November 4, 2019~~May 11, 2020
James P. Ulm, II	Chief Financial Officer



	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			—


						Preliminary Purchase Price Allocation
						(In thousands)
Consideration:
Fair value of the Company’s common stock issued						$765,373
Total consideration						$765,373

Liabilities:
Accounts payable						$37,657
Revenues and royalties payable						52,449
Operating lease liabilities - current						29,924
Fair value of derivatives - current						61,015
Other current liabilities						88,547
Long-term debt						1,984,135
Operating lease liabilities - non-current						30,070
Asset retirement obligation						26,151
Fair value of derivatives - non-current						26,960
Other long-term liabilities						17,260
Common stock warrants						10,029
Total liabilities assumed						$2,364,197

Assets:
Accounts receivable, net						$48,479
Fair value of derivatives - current						17,451
Other current assets						4,945
Evaluated oil and natural gas properties						2,133,280
Unevaluated properties						689,391
Other property and equipment						9,614
Fair value of derivatives - non-current						4,518
Deferred tax asset						159,320
Operating lease right-of-use-assets						59,994
Other long term assets						2,578
Total assets acquired						$3,129,570


						For the Year Ended
						December 31, 2019
						(In thousands)
Revenues						$1,620,357
Income from operations						614,668
Net income						369,777
Basic earnings per common share						0.89
Diluted earnings per common share						0.89


	March 31, 2020	December 31, 2019
Oil and natural gas properties, full cost accounting method	(In thousands)
Evaluated properties	$7,686,019	$7,203,482
Accumulated depreciation, depletion, amortization and impairments	(2,649,924)	(2,520,488)
Net evaluated oil and natural gas properties	5,036,095	4,682,994
Unevaluated properties
Unevaluated leasehold and seismic costs	1,659,262	1,843,725
Capitalized interest	149,842	142,399
Total unevaluated properties	1,809,104	1,986,124
Total oil and natural gas properties, net	$6,845,199	$6,669,118

Other property and equipment	$66,108	$67,202
Accumulated depreciation	(32,892)	(31,949)
Other property and equipment, net	$33,216	$35,253



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



	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



	Preferred			Common			Capital in		Total
	Stock			Stock			Excess	Retained	Stockholders'
	Shares	$	Shares	$	of Par	Earnings	Equity
Balance at 12/31/2019	—	$—	396,600	$3,966	$3,198,076	$21,266	$3,223,308
Net income	—	—	—	—	—	216,565	216,565
Restricted stock	—	—	138	1	3,141	—	3,142
Other	—	—	—	—	(112)	—	(112)
Balance at 3/31/2020	—	$—	396,738	$3,967	$3,201,105	$237,831	$3,442,903



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


1.	Description of Business and Basis of Presentation	9.	Income Taxes
2.	Revenue Recognition	10.	Share-based Compensation
3.	Acquisitions and Divestitures	11.	Leases
4.	Property and Equipment, Net	12.	Accounts Receivable, Net
5.	Earnings Per Share	13.	Accounts Payable and Accrued Liabilities
6.	Borrowings	14.	Supplemental Cash Flow
7.	Derivative Instruments and Hedging Activities	15.	Subsequent Events
8.	Fair Value Measurements



(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.~~



	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.~~



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.



			(Exact Name of Registrant as Specified in Its Charter)


~~(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.



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 of March 31, 2020
	Presented without		As Presented with
	Effects of Netting	Effects of Netting	Effects of Netting
ASSETS	(In thousands)
Commodity derivative instruments	$262,178	($37,863)	$224,315
Contingent consideration arrangements	350	—	350
Fair value of derivatives - current	$262,528	($37,863)	$224,665
Commodity derivative instruments	1,187	(208)	979
Contingent consideration arrangements	1,004	—	1,004
Fair value of derivatives - non current	$2,191	($208)	$1,983
LIABILITIES
Commodity derivative instruments	($41,750)	$37,863	($3,887)
Contingent consideration arrangements	(964)	—	(964)
Fair value of derivatives - current	($42,714)	$37,863	($4,851)
Commodity derivative instruments	(1,723)	208	(1,515)
Contingent consideration arrangements	(2,742)	—	(2,742)
Fair value of derivatives - non current	($4,465)	$208	($4,257)


	As of December 31, 2019
	Presented without		As Presented with
	Effects of Netting	Effects of Netting	Effects of Netting
ASSETS	(In thousands)
Commodity derivative instruments	$26,849	($17,511)	$9,338
Contingent consideration arrangements	16,718	—	16,718
Fair value of derivatives - current	$43,567	($17,511)	$26,056
Commodity derivative instruments	—	—	—
Contingent consideration arrangements	9,216	—	9,216
Fair value of derivatives - non current	$9,216	$—	$9,216
LIABILITIES
Commodity derivative instruments	($38,708)	$17,511	($21,197)
Contingent consideration arrangements	(50,000)	—	(50,000)
Fair value of derivatives - current	($88,708)	$17,511	($71,197)
Commodity derivative instruments	(12,935)	—	(12,935)
Contingent consideration arrangements	(19,760)	—	(19,760)
Fair value of derivatives - non current	($32,695)	$—	($32,695)



	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


~~(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.~~


	March 31, 2020			December 31, 2019
	Principal Amount	Fair Value	Principal Amount	Fair Value
	(In thousands)
6.25% Senior Notes	$650,000	$453,050	$650,000	$658,125
6.125% Senior Notes	600,000	373,020	600,000	611,130
8.25% Senior Notes	250,000	152,905	250,000	256,250
6.375% Senior Notes	400,000	215,176	400,000	405,424
Total	$1,900,000	$1,194,151	$1,900,000	$1,930,929


	March 31, 2020
	Level 1	Level 2	Level 3
	(In thousands)
Assets
Commodity derivative instruments	$—	$225,294	$—
Contingent consideration arrangements	—	1,354	—
Liabilities
Commodity derivative instruments	—	(5,402)	—
Contingent consideration arrangements	—	(3,706)	—
Total net assets (liabilities)	$—	$217,540	$—

	December 31, 2019
	Level 1	Level 2	Level 3
	(In thousands)
Assets
Commodity derivative instruments	$—	$9,338	$—
Contingent consideration arrangements	—	25,934	—
Liabilities
Commodity derivative instruments	—	(34,132)	—
Contingent consideration arrangements	—	(69,760)	—
Total net assets (liabilities)	$—	($68,620)	$—



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



	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.~~


	Three Months Ended March 31,
Performance-based Awards	2020		2019
Number of simulations	100,000		100,000
Expected term (in years)	2.9		2.9
Expected volatility	54.8	%	47.9	%
Risk-free interest rate	1.3	%	2.4	%
Dividend yield	—	%	—	%
Grant date fair value per performance-based RSU Equity Award	$3.39		$10.78



	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


	As of March 31,
	2020	2019
	(In thousands)
Leases
Operating leases:
Operating lease ROU assets	$56,050	$40,977

Current operating lease liabilities	$37,686	$29,134
Long-term operating lease liabilities	35,746	11,751
Total operating lease liabilities	$73,432	$40,885

Financing leases:
Other property and equipment	$2,313	$—
Accumulated depreciation	(658)	—
Other property and equipment, net	$1,655	$—

Current financing lease liabilities	$927	$—
Long-term financing lease liabilities	724	—
Total financing lease liabilities	$1,651	$—



	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


	As of March 31, 2020
Weighted Average Remaining Lease Term (In years)
Operating leases	4.5
Financing leases	2.3

Weighted Average Discount Rate
Operating leases	5.5	%
Financing leases	8.1	%



	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.~~