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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q
(Mark One)
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended September 30, 2019
or
    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ____________ to ____________
Commission File Number 001-14039

Callon Petroleum Company
 
(Exact Name of Registrant as Specified in Its Charter)
 

Delaware
 
64-0844345
State or Other Jurisdiction of
Incorporation or Organization
 
I.R.S. Employer Identification No.
 
 
 
One Briarlake Plaza
 
 
2000 W. Sam Houston Parkway S., Suite 2000
 
 
Houston,
Texas
 
77042
Address of Principal Executive Offices
 
Zip Code
 
(281)
589-5200
 
 
Registrant’s Telephone Number, Including Area Code
 
 





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

Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
 
Trading Symbol(s)
 
Name of Each Exchange on Which Registered
Common Stock, $0.01 par value
 
CPE
 
New York Stock Exchange

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

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

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

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

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

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



Table of Contents

Part I. Financial Information
 
 
 
Item 1. Financial Statements (Unaudited)
 
 
 
4
 
 
5
 
 
6
 
 
7
 
 
8
 
 
24
 
 
34
 
 
35
 
 
Part II. Other Information
 
 
 
36
 
 
36
 
 
36
 
 
36
 
 
36
 
 
36
 
 
37

2


GLOSSARY OF CERTAIN TERMS

All defined terms under Rule 4-10(a) of Regulation S-X shall have their prescribed meanings when used in this report. As used in this document:
ARO:  asset retirement obligation.
ASU: accounting standards update.
Bbl or Bbls:  barrel or barrels of oil or natural gas liquids.
BOE:  barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas.  The ratio of one barrel of oil or NGL to six Mcf of natural gas is commonly used in the industry and represents the approximate energy equivalence of oil or NGLs to natural gas, and does not represent the economic equivalency of oil and NGLs to natural gas. The sales price of a barrel of oil or NGLs is considerably higher than the sales price of six Mcf of natural gas.
BOE/d:  BOE per day.
Btu:  a British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.
Completion: The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.
Cushing: An oil delivery point that serves as the benchmark oil price for West Texas Intermediate.
FASB: Financial Accounting Standards Board.
GAAP: Generally Accepted Accounting Principles in the United States.
Henry Hub: A natural gas pipeline delivery point that serves as the benchmark natural gas price underlying NYMEX natural gas futures contracts.
Horizontal drilling: A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.
LIBOR:  London Interbank Offered Rate.
LOE:  lease operating expense.
MBbls:  thousand barrels of oil.
MBOE:  thousand BOE.
Mcf:  thousand cubic feet of natural gas.
MEH: Magellan East Houston, a delivery point in Houston, Texas that serves as a benchmark for crude oil.
MMBtu:  million Btu.
MMcf:  million cubic feet of natural gas.
NGL or NGLs:  natural gas liquids, such as ethane, propane, butanes and natural gasoline that are extracted from natural gas production streams.
NYMEX:  New York Mercantile Exchange.
Oil: includes crude oil and condensate.
Realized price: The cash market price less all expected quality, transportation and demand adjustments.
Royalty interest: An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development.
RSU: restricted stock units.
SEC:  United States Securities and Exchange Commission.
Waha: A delivery point in West Texas that serves as the benchmark for natural gas.
Working interest: An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.
WTI: West Texas Intermediate grade crude oil, used as a pricing benchmark for sales contracts and NYMEX oil futures contracts.

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


3


Part I.  Financial Information
Item 1.  Financial Statements
Callon Petroleum Company
Consolidated Balance Sheets
(in thousands, except par and share data)
 
 
September 30, 2019
 
December 31, 2018
ASSETS
 
Unaudited
 
 
Current assets:
 
 
 
 
   Cash and cash equivalents
 
$
11,309

 
$
16,051

   Accounts receivable
 
114,120

 
131,720

   Fair value of derivatives
 
25,032

 
65,114

   Other current assets
 
14,912

 
9,740

      Total current assets
 
165,373

 
222,625

Oil and natural gas properties, full cost accounting method:
 
 
 
 
   Evaluated properties
 
4,830,499

 
4,585,020

   Less accumulated depreciation, depletion, amortization and impairment
 
(2,458,026
)
 
(2,270,675
)
   Evaluated oil and natural gas properties, net
 
2,372,473

 
2,314,345

   Unevaluated properties
 
1,405,993

 
1,404,513

      Total oil and natural gas properties, net
 
3,778,466

 
3,718,858

Operating lease right-of-use assets
 
24,447

 

Other property and equipment, net
 
24,770

 
21,901

Restricted investments
 
3,490

 
3,424

Deferred financing costs
 
5,081

 
6,087

Fair value of derivatives
 
11,209

 

Other assets, net
 
4,087

 
6,278

   Total assets
 
$
4,016,923

 
$
3,979,173

LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
 
Current liabilities:
 
 
 
 
   Accounts payable and accrued liabilities
 
$
243,481

 
$
261,184

   Operating lease liabilities
 
19,196

 

   Accrued interest
 
25,660

 
24,665

   Cash-settleable restricted stock unit awards
 
535

 
1,390

   Asset retirement obligations
 
1,250

 
3,887

   Fair value of derivatives
 
8,941

 
10,480

   Other current liabilities
 
1,948

 
13,310

      Total current liabilities
 
301,011

 
314,916

Senior secured revolving credit facility
 
200,000

 
200,000

6.125% senior unsecured notes due 2024
 
596,337

 
595,788

6.375% senior unsecured notes due 2026
 
394,317

 
393,685

Operating lease liabilities
 
4,995

 

Asset retirement obligations
 
8,294

 
10,405

Cash-settleable restricted stock unit awards
 
1,737

 
2,067

Deferred tax liability
 
39,007

 
9,564

Fair value of derivatives
 
2,573

 
7,440

Other long-term liabilities
 

 
100

   Total liabilities
 
1,548,271

 
1,533,965

Commitments and contingencies
 

 

Stockholders’ equity:
 
 
 
 
   Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation
preference, 2,500,000 shares authorized; 0 and 1,458,948 shares outstanding,
respectively
 

 
15

   Common stock, $0.01 par value, 300,000,000 shares authorized; 228,372,081 and
227,582,575 shares outstanding, respectively
 
2,284

 
2,276

   Capital in excess of par value
 
2,421,559

 
2,477,278

   Retained earnings (accumulated deficit)
 
44,809

 
(34,361
)
      Total stockholders’ equity
 
2,468,652

 
2,445,208

Total liabilities and stockholders’ equity
 
$
4,016,923

 
$
3,979,173


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

4


Callon Petroleum Company
Consolidated Statements of Operations
(Unaudited; in thousands, except per share data)
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2019
 
2018
 
2019
 
2018
Operating revenues:
 
 
 
 
 
 
 
Oil sales
$
148,210

 
$
142,601

 
$
450,036

 
$
380,500

Natural gas sales
7,168

 
18,613

 
25,441

 
45,229

Total operating revenues
155,378

 
161,214

 
475,477

 
425,729

Operating expenses:
 
 
 
 
 
 
 
Lease operating expenses
19,668

 
18,525

 
66,511

 
44,705

Production taxes
11,866

 
10,263

 
33,810

 
26,265

Depreciation, depletion and amortization
56,002

 
48,257

 
178,690

 
122,407

General and administrative
9,388

 
9,721

 
31,705

 
26,779

Merger and integration expense
5,943

 

 
5,943

 

Settled share-based awards

 

 
3,024

 

Accretion expense
128

 
202

 
585

 
626

Other operating expense
(161
)
 
1,435

 
931

 
3,750

Total operating expenses
102,834

 
88,403

 
321,199

 
224,532

Income from operations
52,544

 
72,811

 
154,278

 
201,197

Other (income) expenses:
 
 
 
 
 
 
 
Interest expense, net of capitalized amounts
739

 
711

 
2,218

 
1,765

(Gain) loss on derivative contracts
(21,809
)
 
34,339

 
31,415

 
55,374

Other income
(122
)
 
(1,657
)
 
(270
)
 
(2,571
)
Total other (income) expense
(21,192
)
 
33,393

 
33,363

 
54,568

Income before income taxes
73,736

 
39,418

 
120,915

 
146,629

Income tax expense
17,902

 
1,487

 
29,444

 
2,463

Net income
55,834

 
37,931

 
91,471

 
144,166

Preferred stock dividends
(350
)
 
(1,823
)
 
(3,997
)
 
(5,471
)
Loss on redemption of preferred stock
(8,304
)
 

 
(8,304
)
 

Income available to common stockholders
$
47,180

 
$
36,108

 
$
79,170

 
$
138,695

Income per common share:
 
 
 
 
 
 
 
Basic
$
0.21

 
$
0.16

 
$
0.35

 
$
0.65

Diluted
$
0.21

 
$
0.16

 
$
0.35

 
$
0.65

Weighted average common shares outstanding:
 
 
 
 
 
 
 
Basic
228,322

 
227,564

 
228,054

 
213,409

Diluted
228,469

 
228,140

 
228,557

 
214,079


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


5


Callon Petroleum Company
Consolidated Statements of Cash Flows
(Unaudited; in thousands)
 
Nine Months Ended September 30,
Cash flows from operating activities:
2019
 
2018
Net income
$
91,471

 
$
144,166

Adjustments to reconcile net income to cash provided by operating activities:
 
 
 
   Depreciation, depletion and amortization
182,153

 
124,430

   Accretion expense
585

 
626

   Amortization of non-cash debt related items
2,218

 
1,749

   Deferred income tax expense
29,444

 
2,463

   Loss on derivatives, net of settlements
30,979

 
29,696

   (Gain) loss on sale of other property and equipment
36

 
(80
)
   Non-cash expense related to equity share-based awards
7,868

 
4,466

   Change in the fair value of liability share-based awards
106

 
1,428

   Payments to settle asset retirement obligations
(1,425
)
 
(1,080
)
   Payments for cash-settled restricted stock unit awards
(1,425
)
 
(4,990
)
Changes in current assets and liabilities:
 
 
 
   Accounts receivable
17,600

 
(54,384
)
   Other current assets
(5,172
)
 
(1,665
)
   Current liabilities
(13,038
)
 
64,801

   Other
(2,662
)
 
4,389

Net cash provided by operating activities
338,738

 
316,015

Cash flows from investing activities:
 
 
 
Capital expenditures
(503,425
)
 
(455,352
)
Acquisitions
(40,788
)
 
(595,984
)
Proceeds from sale of assets
279,952

 
8,326

Net cash used in investing activities
(264,261
)
 
(1,043,010
)
Cash flows from financing activities:
 
 
 
Borrowings on senior secured revolving credit facility
581,000

 
270,000

Payments on senior secured revolving credit facility
(581,000
)
 
(230,000
)
Issuance of 6.375% senior unsecured notes due 2026

 
400,000

Issuance of common stock

 
288,364

Payment of preferred stock dividends
(3,997
)
 
(5,471
)
Payment of deferred financing costs
(31
)
 
(9,960
)
Tax withholdings related to restricted stock units
(2,174
)
 
(1,804
)
Redemption of preferred stock
(73,017
)
 

Net cash provided by (used in) financing activities
(79,219
)
 
711,129

Net change in cash and cash equivalents
(4,742
)
 
(15,866
)
Balance, beginning of period
16,051

 
27,995

Balance, end of period
$
11,309

 
$
12,129

 
 
 
 
Supplemental cash flow information:
 
 
 
   Interest paid, net of capitalized amounts
$

 
$

   Income taxes paid

 

   Cash paid for amounts included in the measurement of lease liabilities:
 
 
 
      Operating cash flows from operating leases
1,667

 

      Investing cash flows from operating leases
25,455

 

Non-cash investing and financing activities:
 
 
 
   Change in accrued capital expenditures
$
(15,032
)
 
$
42,062

   Change in asset retirement costs
(393
)
 
4,847

   Right-of-use assets obtained in exchange for operating lease liabilities
2,588

 

   Contingent consideration arrangement
8,512

 


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

6


Callon Petroleum Company
Consolidated Statements of Stockholders’ Equity
(Unaudited; in thousands)
 
 
 
 
 
 
 
 
 
 
 
Retained
 
 
 
Preferred
 
Common
 
Capital in
 
Earnings
 
Total
 
Stock
 
Stock
 
Excess
 
(Accumulated
 
Stockholders'
 
Shares
 
$
 
Shares
 
$
 
of Par
 
Deficit)
 
Equity
Balance at 12/31/2018
1,459

 
$
15

 
227,583

 
$
2,276

 
$
2,477,278

 
$
(34,361
)
 
$
2,445,208

Net loss

 

 

 

 

 
(19,543
)
 
(19,543
)
   Shares issued pursuant to employee benefit plans

 

 
24

 

 
154

 

 
154

   Restricted stock

 

 
277

 
3

 
4,447

 

 
4,450

   Preferred stock dividend ($1.25 per share)

 

 

 

 

 
(1,824
)
 
(1,824
)
Balance at 03/31/2019
1,459

 
$
15

 
227,884

 
$
2,279

 
$
2,481,879

 
$
(55,728
)
 
$
2,428,445

Net income

 

 

 

 

 
55,180

 
55,180

   Restricted stock

 

 
380

 
4

 
2,071

 

 
2,075

   Preferred stock dividend ($1.25 per share)

 

 

 

 

 
(1,823
)
 
(1,823
)
   Preferred stock redemption costs

 

 

 

 
(5
)
 

 
(5
)
Balance at 06/30/2019
1,459

 
$
15

 
228,264

 
$
2,283

 
$
2,483,945

 
$
(2,371
)
 
$
2,483,872

Net income

 

 

 

 

 
55,834

 
55,834

   Restricted stock

 

 
108

 
1

 
2,307

 

 
2,308

   Preferred stock dividend ($0.24 per share)

 

 

 

 

 
(350
)
 
(350
)
   Preferred stock redemption
(1,459
)
 
(15
)
 

 

 
(64,693
)
 

 
(64,708
)
   Loss on redemption of preferred stock

 

 

 

 

 
(8,304
)
 
(8,304
)
Balance at 09/30/2019

 
$

 
228,372

 
$
2,284

 
$
2,421,559

 
$
44,809

 
$
2,468,652



 
Preferred
 
Common
 
Capital in
 
 
 
Total
 
Stock
 
Stock
 
Excess
 
Accumulated
 
Stockholders'
 
Shares
 
$
 
Shares
 
$
 
of Par
 
Deficit
 
Equity
Balance at 12/31/2017
1,459

 
$
15

 
201,836

 
$
2,018

 
$
2,181,359

 
$
(327,426
)
 
$
1,855,966

Net income

 

 

 

 

 
55,761

 
55,761

   Shares issued pursuant to employee benefit plans

 

 
7

 

 
88

 

 
88

   Restricted stock

 

 
105

 
1

 
1,152

 

 
1,153

   Preferred stock dividend ($1.25 per share)

 

 

 

 

 
(1,824
)
 
(1,824
)
Balance at 03/31/2018
1,459

 
$
15

 
201,948

 
$
2,019

 
$
2,182,599

 
$
(273,489
)
 
$
1,911,144

Net income

 

 

 

 

 
50,474

 
50,474

   Shares issued pursuant to employee benefit plans

 

 
11

 

 
141

 

 
141

   Restricted stock

 

 
248

 
3

 
1,312

 

 
1,315

   Common stock issued

 

 
25,300

 
253

 
288,103

 

 
288,356

   Preferred stock dividend ($1.25 per share)

 

 

 

 

 
(1,824
)
 
(1,824
)
Balance at 06/30/2018
1,459

 
$
15

 
227,507

 
$
2,275

 
$
2,472,155

 
$
(224,837
)
 
$
2,249,608

Net income

 

 

 

 

 
37,931

 
37,931

   Shares issued pursuant to employee benefit plans

 

 
12

 

 
131

 

 
131

   Restricted stock

 

 
49

 
1

 
2,454

 

 
2,455

   Common stock issued

 

 

 

 
8

 

 
8

   Preferred stock dividend ($1.25 per share)

 

 

 

 

 
(1,823
)
 
(1,823
)
Balance at 09/30/2018
1,459

 
$
15

 
227,568

 
$
2,276

 
$
2,474,748

 
$
(188,731
)
 
$
2,288,308


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


7

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

Index to the Notes to the Consolidated Financial Statements

Note 1 - Description of Business and Basis of Presentation

Description of business

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

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

Basis of presentation

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

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

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

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

Accounting Standards Updates (“ASUs”)

Recently adopted ASUs - Leases

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

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

8

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

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

The new standard was effective for us in the first quarter of 2019, and we adopted the new standard using a modified retrospective approach, with the date of initial application on January 1, 2019. Consequently, upon transition, we recognized the cumulative effect of adoption in retained earnings as of January 1, 2019. We further utilized the package of practical expedients at transition to not reassess the following:
Whether any expired or existing contracts were or contained leases;
The lease classification for any expired or existing leases; and
Initial direct costs for any existing leases.

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

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

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

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

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

Note 2 - Revenue Recognition

Revenue from contracts with customers

Oil sales

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

Natural gas sales

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

9

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

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

Accounts receivable from revenues from contracts with customers

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

Transaction price allocated to remaining performance obligations

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

Prior period performance obligations

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

Note 3 - Acquisitions and Dispositions

2019 Acquisitions and Dispositions

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

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


10

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

2018 Acquisitions

On August 31, 2018, the Company completed the acquisition of approximately 28,000 net surface acres in the Spur operating area, located in the Delaware Basin, from Cimarex Energy Company, for $539,519, including customary purchase price adjustments (the “Delaware Asset Acquisition”). The Company issued debt and equity to fund, in part, the Delaware Asset Acquisition. See Notes 5 and 9 for additional information regarding the Company’s debt obligations and equity offerings. The following table summarizes the estimated acquisition date fair values of the acquisition:
Evaluated oil and natural gas properties
$
253,089

Unevaluated oil and natural gas properties
287,000

Asset retirement obligations
(570
)
Net assets acquired
$
539,519



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

Note 4 - Earnings Per Share

Basic earnings per share is computed by dividing income available to common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings per share includes the potential dilutive impact of non-vested restricted shares outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is anti-dilutive. The following table sets forth the computation of basic and diluted earnings per share:
(amounts in thousands)
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2019
 
2018
 
2019
 
2018
Net income
$
55,834

 
$
37,931

 
$
91,471

 
$
144,166

Preferred stock dividends
(350
)
 
(1,823
)
 
(3,997
)
 
(5,471
)
Loss on redemption of preferred stock
(8,304
)
 

 
(8,304
)
 

Income available to common stockholders
$
47,180

 
$
36,108

 
$
79,170

 
$
138,695

 
 
 
 
 
 
 
 
Weighted average common shares outstanding
228,322

 
227,564

 
228,054

 
213,409

Dilutive impact of restricted stock
147

 
576

 
503

 
670

Weighted average common shares outstanding for diluted income per share
228,469

 
228,140

 
228,557

 
214,079

 
 
 
 
 
 
 
 
Basic income per share
$
0.21

 
$
0.16

 
$
0.35

 
$
0.65

Diluted income per share
$
0.21

 
$
0.16

 
$
0.35

 
$
0.65

 
 
 
 
 
 
 
 
Restricted stock (a)
1,488

 
154

 
829

 
154


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


11

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

Note 5 - Borrowings

The Company’s borrowings consisted of the following:
 
 
As of
Principal components:
 
September 30, 2019
 
December 31, 2018
Senior secured revolving credit facility
 
$
200,000

 
$
200,000

6.125% senior unsecured notes due 2024
 
600,000

 
600,000

6.375% senior unsecured notes due 2026
 
400,000

 
400,000

Total principal outstanding
 
1,200,000

 
1,200,000

Premium on 6.125% senior unsecured notes due 2024, net of accumulated amortization
 
5,625

 
6,469

Unamortized deferred financing costs
 
(14,971
)
 
(16,996
)
Total carrying value of borrowings (a)
 
$
1,190,654

 
$
1,189,473


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

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

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

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

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

Restrictive covenants

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

Note 6 - Derivative Instruments and Hedging Activities

Objectives and strategies for using commodity derivative instruments

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

Counterparty risk and offsetting

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


12

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

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

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

Contingent consideration arrangement

Our Ranger Asset Divestiture in June of 2019 provides for potential contingent consideration to be received by the Company if commodity prices exceed specific thresholds in each of the next several years. On the disposition date, we recognized a derivative asset of $8,512 based on the initial fair value measurement. See Note 7 for additional information regarding fair value measurement. These contingent payments are summarized in the tables below (in thousands):
Year of Potential Settlement
 
Threshold (a)
 
Contingent Payment Amount
 
Threshold (a)
 
Contingent Payment Amount
 
Fair Value as of September 30, 2019 (b)
 
Aggregate Settlements Limit(c)
 
 
 
 
 
 
 
 
 
 
 
 
$
60,000

2019
 
Greater than $60/bbl, less than $65/bbl
 
$9,000
 
Equal to or greater than $65/bbl
 
$20,833
 
$116
 
 
2020
 
Greater than $60/bbl, less than $65/bbl
 
$9,000
 
Equal to or greater than $65/bbl
 
$20,833
 
$3,977
 
 
2021
 
Greater than $60/bbl, less than $65/bbl
 
$9,000
 
Equal to or greater than $65/bbl
 
$20,833
(c) 
$3,496
 
 

(a)
The price used to determine whether the specified thresholds have been met is the average of the final monthly settlements for each month during each annual period end for NYMEX Light Sweet Crude Oil Futures, as reported by the CME Group Inc.
(b)
Contingent consideration to be received will be classified as cash flows from financing activities up to the initial recognition fair value of $8,512; amounts in excess of the initial recognition fair value will be classified as cash flows from operating activities.
(c)
In the event that the 2019 and 2020 prices exceed the $65/bbl threshold, the aggregate amount of contingent consideration is limited to $60,000, resulting in the potential reduction in settlement for 2021 to $18,334.

Derivatives not designated as hedging instruments

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


13

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

The following table reflects the fair value of the Company’s derivative instruments for the periods presented:
As of September 30, 2019
Derivative Instrument
 
Balance Sheet Presentation
 
Asset
 
Liability
 
Net Asset (Liability)
Commodity - Oil
 
Fair value of derivatives - Current
 
$
23,487

 
$
(8,795
)
 
$
14,692

Commodity - Natural gas
 
Fair value of derivatives - Current
 
1,429

 
(146
)
 
1,283

Contingent consideration arrangement
 
Fair value of derivatives - Current
 
116

 

 
116

Commodity - Oil
 
Fair value of derivatives - Non-current
 
3,736

 
(2,233
)
 
1,503

Commodity - Natural gas
 
Fair value of derivatives - Non-current
 

 
(340
)
 
(340
)
Contingent consideration arrangement
 
Fair value of derivatives - Non-current
 
7,473

 

 
7,473

   Totals
 
 
 
$
36,241

 
$
(11,514
)
 
$
24,727

 
 
 
 
 
 
 
 
 
As of December 31, 2018
Derivative Instrument
 
Balance Sheet Presentation
 
Asset
 
Liability
 
Net Asset (Liability)
Commodity - Oil
 
Fair value of derivatives - Current
 
$
60,097

 
$
(10,480
)
 
$
49,617

Commodity - Natural gas
 
Fair value of derivatives - Current
 
5,017

 

 
5,017

Commodity - Oil
 
Fair value of derivatives - Non-current
 

 
(5,672
)
 
(5,672
)
Commodity - Natural gas
 
Fair value of derivatives - Non-current
 

 
(1,768
)
 
(1,768
)
   Totals
 
 
 
$
65,114

 
$
(17,920
)
 
$
47,194



As previously discussed, the Company’s commodity derivative contracts are subject to master netting arrangements. The Company’s policy is to present the fair value of commodity derivative contracts on a net basis in the consolidated balance sheet. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated:
 
As of September 30, 2019
 
Presented without
 
 
 
As Presented with
 
Effects of Netting
 
Effects of Netting
 
Effects of Netting
Current assets: Fair value of commodity derivatives
$
35,936

 
$
(11,020
)
 
$
24,916

Long-term assets: Fair value of commodity derivatives
7,464

 
(3,728
)
 
3,736

 
 
 
 
 
 
Current liabilities: Fair value of commodity derivatives
$
(19,961
)
 
$
11,020

 
$
(8,941
)
Long-term liabilities: Fair value of commodity derivatives
(6,301
)
 
3,728

 
(2,573
)
 
As of December 31, 2018
 
Presented without
 
 
 
As Presented with
 
Effects of Netting
 
Effects of Netting
 
Effects of Netting
Current assets: Fair value of commodity derivatives
$
78,091

 
$
(12,977
)
 
$
65,114

 
 
 
 
 
 
Current liabilities: Fair value of commodity derivatives
$
(23,457
)
 
$
12,977

 
$
(10,480
)
Long-term liabilities: Fair value of commodity derivatives
(7,440
)
 

 
(7,440
)


For the periods indicated, the Company recorded the following in the consolidated statements of operations as a gain or loss on derivative contracts:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2019
 
2018
 
2019
 
2018
Oil derivatives
 
 
 
 
 
 
 
Net gain (loss) on settlements
$
(1,045
)
 
$
(9,306
)
 
$
(7,048
)
 
$
(26,353
)
Net gain (loss) on fair value adjustments
25,767

 
(24,476
)
 
(27,750
)
 
(28,720
)
Total gain (loss) on oil derivatives
24,722

 
(33,782
)
 
(34,798
)
 
(55,073
)
Natural gas derivatives
 
 
 
 
 
 
 
Net gain (loss) on settlements
2,056

 
67

 
6,612

 
675

Net gain (loss) on fair value adjustments
(733
)
 
(624
)
 
(2,306
)
 
(976
)
Total gain (loss) on natural gas derivatives
1,323

 
(557
)
 
4,306

 
(301
)
Contingent consideration arrangement
 
 
 
 
 
 
 
Net gain (loss) on fair value adjustments
(4,236
)
 

 
(923
)
 

   Total gain (loss) on derivatives
$
21,809

 
$
(34,339
)
 
$
(31,415
)
 
$
(55,374
)


14

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

Derivative positions

Listed in the tables below are the outstanding oil and natural gas derivative contracts as of September 30, 2019:  
 
For the Remainder
 
For the Full Year
 
For the Full Year
 
Oil contracts (WTI)
of 2019
 
of 2020
 
of 2021
 
   Puts
 
 
 
 
 
 
      Total volume (Bbls)
230,000

 

 

 
      Weighted average price per Bbl
$
65.00

 
$

 
$

 
   Put spreads
 
 
 
 
 
 
   Total volume (Bbls)
230,000

 

 

 
   Weighted average price per Bbl
 
 
 
 
 
 
   Floor (long put)
$
65.00

 
$

 
$

 
   Floor (short put)
$
42.50

 
$

 
$

 
   Collar contracts with short puts (three-way collars)
 
 
 
 
 
 
   Total volume (Bbls)
1,196,000

 
5,124,000

 

 
   Weighted average price per Bbl
 
 
 
 
 
 
   Ceiling (short call)
$
67.46

 
$
65.46

 
$

 
   Floor (long put)
$
56.54

 
$
55.45

 
$

 
   Floor (short put)
$
43.65

 
$
44.66

 
$

 
   Collar contracts (two-way collars)
 
 
 
 
 
 
   Total volume (Bbls)
276,000

 

 

 
   Weighted average price per Bbl
 
 
 
 
 
 
   Ceiling (short call)
$
60.00

 
$

 
$

 
   Floor (long put)
$
55.00

 
$

 
$

 
   Short call
 
 
 
 
 
 
   Total volume (Bbls)

 

 
1,825,000

(a) 
   Weighted average price per Bbl
$

 
$

 
$
63.00

 
   Swap contracts
 
 
 
 
 
 
   Total volume (Bbls)
276,000

 
1,098,000

 

 
   Weighted average price per Bbl
$
60.17

 
$
56.17

 
$

 
 
 
 
 
 
 
 
Oil contracts (Brent ICE)
 
 
 
 
 
 
   Collar contracts with short puts (three-way collars)
 
 
 
 
 
 
   Total volume (Bbls)

 
837,500

 

 
   Weighted average price per Bbl
 
 
 
 
 
 
   Ceiling (short call)
$

 
$
70.00

 
$

 
   Floor (long put)
$

 
$
58.24

 
$

 
   Floor (short put)
$

 
$
50.00

 
$

 
 
 
 
 
 
 
 
Oil contracts (Midland basis differential)
 
 
 
 
 
 
   Swap contracts
 
 
 
 
 
 
   Total volume (Bbls)
2,176,000

 
4,576,000

 
1,095,000

 
   Weighted average price per Bbl
$
(2.50
)
 
$
(1.29
)
 
$
1.00

 
 
 
 
 
 
 
 
Oil contracts (Argus Houston MEH basis differential)
 
 
 
 
 
 
   Swap contracts
 
 
 
 
 
 
   Total volume (Bbls)

 
1,439,205

 

 
   Weighted average price per Bbl
$

 
$
2.40

 
$

 
 
 
 
 
 
 
 
Natural gas contracts (Henry Hub)
 
 
 
 
 
 
   Collar contracts (two-way collars)
 
 
 
 
 
 
      Total volume (MMBtu)
598,000

 

 

 
      Weighted average price per MMBtu
 
 
 
 
 
 
         Ceiling (short call)
$
3.50

 
$

 
$

 
         Floor (long put)
$
3.13

 
$

 
$

 
   Swap contracts
 
 
 
 
 
 
      Total volume (MMBtu)
155,000

 

 

 
      Weighted average price per MMBtu
$
2.87

 
$

 
$

 
 
 
 
 
 
 
 
Natural gas contracts (Waha basis differential)
 
 
 
 
 
 
   Swap contracts
 
 
 
 
 
 
      Total volume (MMBtu)
2,116,000

 
4,758,000

 

 
      Weighted average price per MMBtu
$
(1.18
)
 
$
(1.12
)
 
$

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

15

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

Note 7 - Fair Value Measurements

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

Fair value of financial instruments

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

Debt. The carrying amount of the Company’s floating-rate debt approximated fair value, because the interest rates were variable and reflective of market rates.
 
 
September 30, 2019
 
December 31, 2018
 
 
Carrying Value
 
Fair Value
 
Carrying Value
 
Fair Value
Credit Facility (a)
 
$
200,000

 
$
200,000

 
$
200,000

 
$
200,000

6.125% Senior Notes (b)
 
596,337

 
595,194

 
595,788

 
558,000

6.375% Senior Notes (b)
 
394,317

 
393,540

 
393,685

 
372,000

Total
 
$
1,190,654

 
$
1,188,734

 
$
1,189,473

 
$
1,130,000


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

Assets and liabilities measured at fair value on a recurring basis

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

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

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


16

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

The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis:
September 30, 2019
 
Classification
 
Level 1
 
Level 2
 
Level 3
 
Total
Assets
 
 
 
 
 
 
 
 
 
 
Derivative financial instruments
 
Fair value of derivatives
 
$

 
$
36,241

 
$

 
$
36,241

Liabilities
 
 
 
 
 
 
 
 
 
 
Derivative financial instruments
 
Fair value of derivatives
 

 
(11,514
)
 

 
(11,514
)
Total net assets (liabilities)
 
 
 
$

 
$
24,727

 
$

 
$
24,727

 
 
 
 
 
 
 
 
 
 
 
December 31, 2018
 
Classification
 
Level 1
 
Level 2
 
Level 3
 
Total
Assets
 
 
 
 
 
 
 
 
 
 
Derivative financial instruments
 
Fair value of derivatives
 
$

 
$
65,114

 
$

 
$
65,114

Liabilities
 
 
 
 
 
 
 
 
 
 
Derivative financial instruments
 
Fair value of derivatives
 

 
(17,920
)
 

 
(17,920
)
Total net assets
 
 
 
$

 
$
47,194

 
$

 
$
47,194


Assets and liabilities measured at fair value on a nonrecurring basis

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

Note 8 - Income Taxes

The Company provides for income taxes at the statutory rate of 21% adjusted for permanent differences expected to be realized, which primarily relate to non-deductible executive compensation expenses, restricted stock windfalls, and state income taxes. The following table presents a reconciliation of the reported amount of income tax expense to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income from continuing operations:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
Components of income tax rate reconciliation
2019
 
2018
 
2019
 
2018
Income tax expense computed at the statutory federal income tax rate
21
%
 
21
 %
 
21
%
 
21
 %
State taxes net of federal expense
1
%
 
3
 %
 
1
%
 
2
 %
Section 162(m)
%
 
2
 %
 
%
 
1
 %
Valuation allowance
%
 
(21
)%
 
%
 
(21
)%
Effective income tax rate, before discrete items
22
%
 
5
 %
 
22
%
 
3
 %
   Discrete items (a)
2
%
 
(1
)%
 
2
%
 
(1
)%
Effective income tax rate, after discrete items
24
%
 
4
 %
 
24
%
 
2
 %

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

Note 9 - Equity Transactions

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

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

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

17

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

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

Common stock  

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

Note 10 - Leases

Leases

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

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

Nature of leases

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

Drilling rigs

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

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

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

Corporate and field offices

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


18

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

Transportation, gathering and processing arrangements

We engage in various types of transactions in which midstream entities transport, gather and/or process our product leveraging integrated systems and facilities wholly-owned and operated by the midstream counterparty. Under most of these arrangements, we do not utilize substantially all of the underlying pipeline, gathering system or processing facilities, and thus, we have concluded that those underlying assets do not meet the definition of an identified asset.
The following tables reflect the current period impact of our adoption of the new leases standard. As we have no leases that meet the criteria for classification as a finance lease, all information contained herein represents our operating leases.
The components of our total lease cost were as follows:
 
Three Months Ended
 
Nine Months Ended
 
September 30, 2019
 
September 30, 2019
Operating lease cost
$
7,964

 
$
27,122

Short-term lease cost (a)
293

 
3,640

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

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

Our operating lease liabilities with enforceable contract terms that are greater than one year mature as follows:
 
As of September 30, 2019
Remainder of 2019
$
7,932

2020
13,933

2021
1,576

2022
534

2023
517

Thereafter
431

   Total lease payments
24,923

Less imputed interest
732

   Total
$
24,191



Note 11 - Asset Retirement Obligations

The table below summarizes the activity for the Company’s ARO:
 
Nine Months Ended
 
September 30, 2019
Asset retirement obligations at January 1, 2019
$
14,292

Accretion expense
585

Liabilities incurred
325

Liabilities settled
(3,187
)
Dispositions
(1,753
)
Revisions to estimate
(718
)
Asset retirement obligations at end of period
9,544

Less: Current asset retirement obligations
(1,250
)
Long-term asset retirement obligations at September 30, 2019
$
8,294



Liabilities incurred include additions from acquisitions, asset swaps, and new wells drilled during the year.
Liabilities settled include the retirement of 28 wells during the year and settlement of abandonment obligations attributable to historical activity within the Gulf of Mexico.
Dispositions are primarily attributable to the Ranger Asset Divestiture in the second quarter of 2019. See Note 3 for details about the Ranger Asset Divestiture.
Revisions to estimates were due to changes in plugging cost estimates, timing of abandonment activities, and changes in working interest of producing wells.


19

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

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

Note 12 - Other

Other commitments

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

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

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

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

Note 13 - Carrizo Acquisition

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

Subject to the terms and conditions of the Merger Agreement, at the effective time of the Merger (the “Effective Time”), each outstanding share of Carrizo common stock, will be converted into the right to receive 2.05 shares of Callon common stock. Following the closing of the Merger, Callon’s existing shareholders and Carrizo’s existing shareholders will own approximately 54% and 46%, respectively, of the outstanding shares of the combined company.
The Merger Agreement provides that, upon consummation of the Merger, the board of directors of Callon will consist of the eight members of the board of directors of Callon immediately prior to the Effective Time and three members of the board of directors of Carrizo. Callon and Carrizo have agreed that the Director Designees will be appointed to the Callon board immediately after the effective time, with the Callon designee being appointed as a Class III director, with a term ending at the 2021 annual meeting of the shareholders of Callon, and the Carrizo designees being appointed as Class I directors, each with a term ending at the 2022 annual meeting of the shareholders of Callon. Callon and Carrizo expect that the Callon designee will be Frances Aldrich Sevilla-Sacasa and the Carrizo designees will be S.P. Johnson IV and Steven A. Webster.

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

20

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

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


21


Special Note Regarding Forward Looking Statements

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

All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect or anticipate will or may occur in the future are forward-looking statements, including such things as:
matters relating to the Carrizo Acquisition;
our oil and natural gas reserve quantities, and the discounted present value of these reserves;
the amount and nature of our capital expenditures;
our future drilling and development plans and our potential drilling locations;
the timing and amount of future capital and operating costs;
production decline rates from our wells being greater than expected;
commodity price risk management activities and the impact on our average realized prices;
business strategies and plans of management;
our ability to consummate and efficiently integrate recent acquisitions; and
prospect development and property acquisitions.

Some of the risks, which could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements, include:
general economic conditions including the availability of credit and access to existing lines of credit;
the volatility of oil and natural gas prices;
the uncertainty of estimates of oil and natural gas reserves;
impairments;
the impact of competition;
the availability and cost of seismic, drilling and other equipment, waste and water disposal infrastructure, and personnel;
operating hazards inherent in the exploration for and production of oil and natural gas;
difficulties encountered during the exploration for and production of oil and natural gas;
the potential impact of future drilling on production from existing wells;
difficulties encountered in delivering oil and natural gas to commercial markets;
changes in customer demand and producers’ supply;
the uncertainty of our ability to attract capital and obtain financing on favorable terms;
compliance with, or the effect of changes in, the extensive governmental regulations regarding the oil and natural gas business including those related to climate change and greenhouse gases;
the impact of government regulation, including regulation of hydraulic fracturing and water disposal wells;
any increase in severance or similar taxes;
the financial impact of accounting regulations and critical accounting policies;
the comparative cost of alternative fuels;
credit risk relating to the risk of loss as a result of non-performance by our counterparties;
cyberattacks on the Company or on systems and infrastructure used by the oil and gas industry;
weather conditions;
risks associated with acquisitions, including the Carrizo Acquisition;
failure to consummate the Carrizo Acquisition in a timely manner, or at all, and failure to realize the expected benefits thereof;
any litigation relating to the Carrizo Acquisition; and
any other factors listed in the reports we have filed and may file with the SEC.

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

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

22


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

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


23

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


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

General

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

We are an independent oil and natural gas company incorporated in the State of Delaware in 1994, but our roots go back nearly 70 years to our Company’s establishment in 1950. We are focused on the acquisition and development of unconventional onshore oil and natural gas reserves in the Permian Basin. The Permian Basin is located in West Texas and southeastern New Mexico and is comprised of three primary sub-basins: the Midland Basin, the Delaware Basin, and the Central Basin Platform. Since our entry into the Permian Basin in late 2009, we have historically been focused on the Midland Basin and more recently entered the Delaware Basin through an acquisition completed in February 2017. We further expanded our presence in the Delaware Basin through our acquisitions in 2018. Our operating culture is centered on responsible development of hydrocarbon resources, safety and the environment, which we believe strengthens our operational performance. Our drilling activity is focused on the horizontal development of several prospective intervals, including multiple levels of the Wolfcamp formation and the Lower Spraberry shales. We have assembled a multi-year inventory of potential horizontal well locations and intend to add to this inventory through delineation drilling of emerging zones on our existing acreage and acquisition of additional locations through working interest acquisitions, leasing programs, acreage purchases, joint ventures and asset swaps. Our production was approximately 78% oil and 22% natural gas for the nine months ended September 30, 2019.

Recent Developments

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

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

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

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

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


24

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


Results of Operations

The following tables set forth certain operating information with respect to the Company’s oil and natural gas operations for the periods indicated: 
 
 
Three Months Ended September 30,
 
 
2019
 
2018
 
Change
 
% Change
Net production
 
 
 
 
 
 
 
 
Oil (MBbls)
 
2,725

 
2,521

 
204

 
8
 %
Natural gas (MMcf)
 
4,538

 
4,144

 
394

 
10
 %
   Total (MBOE)
 
3,481

 
3,212

 
269

 
8
 %
Average daily production (BOE/d)
 
37,837

 
34,913

 
2,924

 
8
 %
   % oil (BOE basis)
 
78
%
 
78
%
 
  
 
  
Average realized sales price
(excluding impact of settled derivatives)
 
 
 
  
 
  
 
  
   Oil (per Bbl)
 
$
54.39

 
$
56.57

 
$
(2.18
)
 
(4
)%
   Natural gas (per Mcf)
 
1.58

 
4.49

 
(2.91
)
 
(65
)%
   Total (per BOE)
 
44.64

 
50.19

 
(5.55
)
 
(11
)%
Average realized sales price
(including impact of settled derivatives)
 
 
 
 
 
 
 
 
   Oil (per Bbl)
 
$
54.01

 
$
52.87

 
$
1.14

 
2
 %
   Natural gas (per Mcf)
 
2.03

 
4.51

 
(2.48
)
 
(55
)%
   Total (per BOE)
 
44.93

 
47.31

 
(2.38
)
 
(5
)%
Oil and natural gas revenues
(in thousands)
 
  

 
  

 
  

 
  

   Oil revenue
 
$
148,210

 
$
142,601

 
$
5,609

 
4
 %
   Natural gas revenue
 
7,168

 
18,613

 
(11,445
)
 
(61
)%
      Total
 
$
155,378

 
$
161,214

 
$
(5,836
)
 
(4
)%
Additional per BOE data
 
  

 
 
 
  

 
  

   Sales price (a)
 
$
44.64

 
$
50.19

 
$
(5.55
)
 
(11
)%
      Lease operating expense (b)
 
5.65

 
5.77

 
(0.12
)
 
(2
)%
      Production taxes
 
3.41

 
3.20

 
0.21

 
7
 %
   Operating margin
 
$
35.58

 
$
41.22

 
$
(5.64
)
 
(14
)%
Benchmark prices
 
 
 
 
 
 
 
 
   WTI (per Bbl)
 
$
56.34

 
$
69.69

 
$
(13.35
)
 
(19
)%
   Henry Hub (per Mmbtu)
 
2.38

 
2.93

 
(0.55
)
 
(19
)%

(a)
Excludes the impact of settled derivatives.
(b)
Excludes gathering and treating expense.


25

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


 
 
Nine Months Ended September 30,
 
 
2019
 
2018
 
Change
 
% Change
Net production
 
 
 
 
 
 
 
 
Oil (MBbls)
 
8,431

 
6,368

 
2,063

 
32
 %
Natural gas (MMcf)
 
14,188

 
11,222

 
2,966

 
26
 %
   Total (MBOE)
 
10,796

 
8,238

 
2,558

 
31
 %
Average daily production (BOE/d)
 
39,546

 
30,176

 
9,370

 
31
 %
   % oil (BOE basis)
 
78
%
 
77
%
 
  
 
  
Average realized sales price
(excluding impact of settled derivatives)
 
 
 
  
 
  
 
  
   Oil (per Bbl)
 
$
53.38

 
$
59.75

 
$
(6.37
)
 
(11
)%
   Natural gas (per Mcf)
 
1.79

 
4.03

 
(2.24
)
 
(56
)%
   Total (per BOE)
 
44.04

 
51.68

 
(7.64
)
 
(15
)%
Average realized sales price
(including impact of settled derivatives)
 
 
 
 
 
 
 
 
   Oil (per Bbl)
 
$
52.54

 
$
55.61

 
$
(3.07
)
 
(6
)%
   Natural gas (per Mcf)
 
2.26

 
4.09

 
(1.83
)
 
(45
)%
   Total (per BOE)
 
44.00

 
48.56

 
(4.56
)
 
(9
)%
Oil and natural gas revenues
(in thousands)
 
  
 
  
 
  
 
  
   Oil revenue
 
$
450,036

 
$
380,500

 
$
69,536

 
18
 %
   Natural gas revenue
 
25,441

 
45,229

 
(19,788
)
 
(44
)%
      Total
 
$
475,477

 
$
425,729

 
$
49,748

 
12
 %
Additional per BOE data
 
  
 
 
 
  
 
  
   Sales price (a)
 
$
44.04

 
$
51.68

 
$
(7.64
)
 
(15
)%
      Lease operating expense (b)
 
6.16

 
5.43

 
0.73

 
13
 %
      Production taxes
 
3.13

 
3.19

 
(0.06
)
 
(2
)%
   Operating margin
 
$
34.75

 
$
43.06

 
$
(8.31
)
 
(19
)%
Benchmark prices
 
 
 
 
 
 
 
 
   WTI (per Bbl)
 
$
57.04

 
$
66.93

 
$
(9.89
)
 
(15
)%
   Henry Hub (per Mmbtu)
 
2.62

 
2.95

 
(0.33
)
 
(11
)%

(a)
Excludes the impact of settled derivatives.
(b)
Excludes gathering and treating expense.


26

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


Revenues

The following tables are intended to reconcile the change in oil, natural gas and total revenue for the respective periods presented by reflecting the effect of changes in volume and in the underlying commodity prices.
(in thousands)
 
Oil
 
Natural Gas
 
Total
Revenues for the three months ended September 30, 2018
 
$
142,601

 
$
18,613

 
$
161,214

   Volume increase
 
11,540

 
1,769

 
13,309

   Price decrease
 
(5,931
)
 
(13,214
)
 
(19,145
)
   Net increase (decrease)
 
5,609

 
(11,445
)
 
(5,836
)
Revenues for the three months ended September 30, 2019
 
$
148,210

 
$
7,168

 
$
155,378


(in thousands)
 
Oil
 
Natural Gas
 
Total
Revenues for the nine months ended September 30, 2018
 
$
380,500

 
$
45,229

 
$
425,729

   Volume increase
 
123,264

 
11,953

 
135,217

   Price decrease
 
(53,728
)
 
(31,741
)
 
(85,469
)
   Net increase (decrease)
 
69,536

 
(19,788
)
 
49,748

Revenues for the nine months ended September 30, 2019
 
$
450,036

 
$
25,441

 
$
475,477


Commodity prices

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

our revenues, cash flows and earnings;
the amount of oil and natural gas that we are economically able to produce;
our ability to attract capital to finance our operations and cost of the capital;
the amount we are allowed to borrow under our Credit Facility; and
the value of our oil and natural gas properties.

Oil revenue 

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

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

Natural gas revenue (including NGLs)

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

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


27

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


Operating Expenses
 
 
Three Months Ended September 30,
 
 
 
 
Per
 
 
 
Per
 
Total Change
 
BOE Change
(in thousands, except per unit amounts)
 
2019
 
BOE
 
2018
 
BOE
 
$
 
%
 
$
 
%
Lease operating expenses
 
$
19,668

 
$
5.65

 
$
18,525

 
$
5.77

 
$
1,143

 
6
 %
 
$
(0.12
)
 
(2
)%
Production taxes
 
11,866

 
3.41

 
10,263

 
3.20

 
1,603

 
16
 %
 
0.21

 
7
 %
Depreciation, depletion and amortization
 
56,002

 
16.09

 
48,257

 
15.02

 
7,745

 
16
 %
 
1.07

 
7
 %
General and administrative
 
9,388

 
2.70

 
9,721

 
3.03

 
(333
)
 
(3
)%
 
(0.33
)
 
(11
)%
Merger and integration expense
 
5,943

 
1.71

 

 

 
5,943

 
100
 %
 
1.71

 
100
 %
Accretion expense
 
128

 
0.04

 
202

 
0.06

 
(74
)
 
(37
)%
 
(0.02
)
 
(33
)%
Other operating expense
 
(161
)
 
(0.05
)
 
1,435

 
0.45

 
(1,596
)
 
(111
)%
 
(0.50
)
 
(111
)%

 
 
Nine Months Ended September 30,
 
 
 
 
Per
 
 
 
Per
 
Total Change
 
BOE Change
(in thousands, except per unit amounts)
 
2019
 
BOE
 
2018
 
BOE
 
$
 
%
 
$
 
%
Lease operating expenses
 
$
66,511

 
$
6.16

 
$
44,705

 
$
5.43

 
$
21,806

 
49
 %
 
$
0.73

 
13
 %
Production taxes
 
33,810

 
3.13

 
26,265

 
3.19

 
7,545

 
29
 %
 
(0.06
)
 
(2
)%
Depreciation, depletion and amortization
 
178,690

 
16.55

 
122,407

 
14.86

 
56,283

 
46
 %
 
1.69

 
11
 %
General and administrative
 
31,705

 
2.94

 
26,779

 
3.25

 
4,926

 
18
 %
 
(0.31
)
 
(10
)%
Merger and integration expense
 
5,943

 
0.55

 

 

 
5,943

 
100
 %
 
0.55

 
100
 %
Settled share-based awards
 
3,024

 
0.28

 

 

 
3,024

 
100
 %
 
0.28

 
100
 %
Accretion expense
 
585

 
0.05

 
626

 
0.08

 
(41
)
 
(7
)%
 
(0.03
)
 
(38
)%
Other operating expense
 
931

 
0.09

 
3,750

 
0.46

 
(2,819
)
 
(75
)%
 
(0.37
)
 
(80
)%

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

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

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

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

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

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

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

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

28

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


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

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

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

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

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

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

General and administrative, net of amounts capitalized (“G&A”). G&A for the three months ended September 30, 2019 decreased to $9.4 million compared to $9.7 million for the same period of 2018. On a per unit basis, G&A decreased 11% to $2.70 per BOE for the three months ended September 30, 2019 compared to $3.03 per BOE for the same period in 2018. G&A expenses for the periods indicated include the following (in thousands):
 
 
Three Months Ended September 30,
 
 
2019
 
2018
 
$ Change
 
% Change
Recurring expenses
 
 
 
 
 
 
 
 
   G&A
 
$
8,789

 
$
7,070

 
$
1,719

 
24
 %
   Share-based compensation
 
1,525

 
1,730

 
(205
)
 
(12
)%
   Fair value adjustments of cash-settled RSU awards
 
(926
)
 
921

 
(1,847
)
 
(201
)%
Total G&A expenses
 
$
9,388

 
$
9,721

 
$
(333
)
 
(3
)%

G&A for the nine months ended September 30, 2019 increased to $31.7 million compared to $26.8 million for the same period of 2018. The increase is primarily attributable to a rise in personnel costs resulting from the growth in our operating activities. On a per unit basis, G&A decreased 10% to $2.94 per BOE for the nine months ended September 30, 2019 compared to $3.25 per BOE for the same period in 2018. G&A expenses for the periods indicated include the following (in thousands):
 
 
Nine Months Ended September 30,
 
 
2019
 
2018
 
$ Change
 
% Change
Recurring expenses
 
 
 
 
 
 
 
 
   G&A
 
$
26,889

 
$
20,929

 
$
5,960

 
28
 %
   Share-based compensation
 
4,712

 
4,422

 
290

 
7
 %
   Fair value adjustments of cash-settled RSU awards
 
104

 
1,428

 
(1,324
)
 
(93
)%
Total G&A expenses
 
$
31,705

 
$
26,779

 
$
4,926

 
18
 %

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


29

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


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

Other Income and Expenses and Preferred Stock Dividends
 
 
Three Months Ended September 30,
(in thousands)
 
2019
 
2018
 
$ Change
 
% Change
Interest expense
 
$
18,869

 
$
17,244

 
$
1,625

 
9
 %
Capitalized interest
 
(18,130
)
 
(16,533
)
 
(1,597
)
 
10
 %
Interest expense, net of capitalized amounts
 
739

 
711

 
28

 
4
 %
(Gain) loss on derivative contracts
 
(21,809
)
 
34,339

 
(56,148
)
 
(164
)%
Other income
 
(122
)
 
(1,657
)
 
1,535

 
(93
)%
   Total other (income) expense
 
$
(21,192
)
 
$
33,393

 
$
(54,585
)
 
(163
)%
 
 
 
 
 
 
 
 
 
Income tax expense
 
$
17,902

 
$
1,487

 
$
16,415

 
1,104
 %
Preferred stock dividends
 
(350
)
 
(1,823
)
 
1,473

 
(81
)%
Loss on redemption of preferred stock
 
(8,304
)
 

 
(8,304
)
 
(100
)%

 
 
Nine Months Ended September 30,
(in thousands)
 
2019
 
2018
 
$ Change
 
% Change
Interest expense
 
$
58,929

 
$
40,416

 
$
18,513

 
46
 %
Capitalized interest
 
(56,711
)
 
(38,651
)
 
(18,060
)
 
47
 %
Interest expense, net of capitalized amounts
 
2,218

 
1,765

 
453

 
26
 %
(Gain) loss on derivative contracts
 
31,415

 
55,374

 
(23,959
)
 
(43
)%
Other income
 
(270
)
 
(2,571
)
 
2,301

 
(89
)%
   Total other (income) expense
 
$
33,363

 
$
54,568

 
$
(21,205
)
 
(39
)%
 
 
 
 
 
 
 
 
 
Income tax expense
 
$
29,444

 
$
2,463

 
$
26,981

 
1,095
 %
Preferred stock dividends
 
(3,997
)
 
(5,471
)
 
1,474

 
(27
)%
Loss on redemption of preferred stock
 
$
(8,304
)
 
$

 
$
(8,304
)
 
(100
)%

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


30

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


Gain (loss) on derivative instruments. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in commodity prices. This amount represents the (i) gain (loss) related to fair value adjustments on our open derivative contracts and (ii) gains (losses) on settlements of derivative contracts for positions that have settled within the period. The net gain (loss) on derivative instruments for the periods indicated includes the following (in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2019
 
2018
 
2019
 
2018
Oil derivatives
 
 
 
 
 
 
 
Net gain (loss) on settlements
$
(1,045
)
 
$
(9,306
)
 
$
(7,048
)
 
$
(26,353
)
Net gain (loss) on fair value adjustments
25,767

 
(24,476
)
 
(27,750
)
 
(28,720
)
Total gain (loss) on oil derivatives
24,722

 
(33,782
)
 
(34,798
)
 
(55,073
)
Natural gas derivatives
 
 
 
 
 
 
 
Net gain (loss) on settlements
2,056

 
67

 
6,612

 
675

Net gain (loss) on fair value adjustments
(733
)
 
(624
)
 
(2,306
)
 
(976
)
Total gain (loss) on natural gas derivatives
1,323

 
(557
)
 
4,306

 
(301
)
Contingent consideration arrangement
 
 
 
 
 
 
 
Net gain (loss) on fair value adjustments
(4,236
)
 

 
(923
)
 

   Total gain (loss) on derivatives
$
21,809

 
$
(34,339
)
 
$
(31,415
)
 
$
(55,374
)

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

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

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

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

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

Liquidity and Capital Resources

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

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


31

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


 
 
Nine Months Ended September 30,
(in thousands)
 
2019
 
2018
Net cash provided by operating activities
 
$
338,738

 
$
316,015

Net cash used in investing activities
 
(264,261
)
 
(1,043,010
)
Net cash provided by (used in) financing activities
 
(79,219
)
 
711,129

   Net change in cash and cash equivalents
 
$
(4,742
)
 
$
(15,866
)

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

An increase in revenues due to higher production volumes, offset by a decrease in realized pricing,
An offsetting increase in operating expenses as a result of higher production volumes,
An offsetting increase in cash G&A expense due to costs from personnel growth, and
Changes related to the timing of working capital payments and receipts.

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

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

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

Our investing activities, on a cash basis, include the following for the periods indicated (in thousands):
 
 
Nine Months Ended September 30,
 
 
2019
 
2018
 
$ Change
Operational expenditures
 
$
416,958

 
$
411,109

 
$
5,849

Seismic, leasehold and other
 
6,794

 
7,137

 
(343
)
Capitalized general and administrative costs
 
23,957

 
16,544

 
7,413

Capitalized interest
 
55,716

 
20,562

 
35,154

   Total capital expenditures(a)
 
503,425

 
455,352

 
48,073

Acquisitions
 
40,788

 
595,984

 
(555,196
)
Proceeds from sale of assets
 
(279,952
)
 
(8,326
)
 
(271,626
)
   Total investing activities
 
$
264,261

 
$
1,043,010

 
$
(778,749
)

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

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

Financing activities. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our Credit Facility, term debt and equity offerings. For the nine months ended September 30, 2019, net cash used in financing activities was $79.2 million compared to net cash provided by financing activities of $711.1 million for the same period of 2018. In the
second quarter of 2019, the Company completed the Ranger Asset Divestiture for net cash proceeds received at closing of $244.9 million, including customary purchase price adjustments. The proceeds were used to accelerate our debt reduction initiatives and also allow us to retire our preferred stock, reducing our cash financing costs. This reduction in financing activity as compared to the same period in 2018 can also be partially attributed to funding our Delaware Asset Acquisition in the third quarter of 2018.


32

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


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

Nine Months Ended September 30,

2019
 
2018
 
$ Change
Net borrowings on Credit Facility
$

 
$
40,000

 
$
(40,000
)
Issuance of 6.375% senior unsecured notes due 2026

 
400,000

 
(400,000
)
Issuance of common stock

 
288,364

 
(288,364
)
Payment of preferred stock dividends
(3,997
)
 
(5,471
)
 
1,474

Payment of deferred financing costs
(31
)
 
(9,960
)
 
9,929

Tax withholdings related to restricted stock units
(2,174
)
 
(1,804
)
 
(370
)
Redemption of preferred stock
(73,017
)
 

 
(73,017
)
Net cash provided by (used in) financing activities
$
(79,219
)
 
$
711,129

 
$
(790,348
)

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

Capital Plan and Year to Date 2019 Summary

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

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

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

Contractual Obligations

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

33


Item 3. Quantitative and Qualitative Disclosures about Market Risk

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

Commodity price risk

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

The Company’s hedging portfolio as of September 30, 2019, indexed to NYMEX benchmark pricing, covers approximately 2,208,000 Bbls and 753,000 MMBtu of our expected oil and natural gas production, respectively, for the remainder of 2019. We also have commodity hedging contracts indexed to Midland WTI oil basis differentials relative to Cushing and Waha natural gas basis differentials covering approximately 2,176,000 Bbls and 2,116,000 MMBtu, respectively, of our expected oil and natural gas production for the remainder of 2019. As of September 30, 2019, we had outstanding oil and natural gas derivative contracts with a net asset position of $17.1 million. The following table provides a sensitivity analysis of the projected incremental effect on income (loss) before income taxes of a hypothetical 10% change in NYMEX WTI, Henry Hub, Midland WTI, Waha, and Houston MEH prices on our open commodity derivative instruments as of September 30, 2019 (in thousands):
 
Hypothetical Price Increase of 10%
 
Hypothetical Price Decrease of 10%
Oil derivatives
$
(33,212
)
 
$
31,480

Natural gas derivatives
670

 
(666
)
   Total
$
(32,542
)
 
$
30,814


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

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

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

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


34


Interest rate risk

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

Counterparty and customer credit risk

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

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

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

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

The fair value of our contingent consideration arrangement was determined by a third-party valuation specialist using an option pricing model and includes significant inputs such as forward oil price curves, time to expiration, and implied volatility. See Note 7 in the Footnotes to the Financial Statements for more information on the fair value of the contingent consideration arrangement. The following table provides a sensitivity analysis of the projected incremental effect on income (loss) before income taxes based on a hypothetical 10% change in the underlying forward oil price curve as of September 30, 2019 (in thousands):
 
Hypothetical Price Increase of 10%
 
Hypothetical Price Decrease of 10%
Contingent consideration arrangement
$
4,013

 
$
(3,161
)

Item 4. Controls and Procedures

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

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

35


Part II.  Other Information

Item 1.  Legal Proceedings

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

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

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

Item 1A. Risk Factors

In addition to the other information set forth in this Quarterly Report, you should carefully consider the risk factors and other cautionary statements described under the heading “Item 1A. Risk Factors” included in our 2018 Annual Report on Form 10-K and the risk factors and other cautionary statements contained in our other SEC filings, including our Quarterly Report on Form 10-Q for the period ended June 30, 2019 and our Registration Statement on Form S-4 that was initially filed on August 20, 2019 and declared effective on October 9, 2019, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. There have been no material changes in our risk factors from those described in our 2018 Annual Report on Form 10-K or our other SEC filings, including our Quarterly Report on Form 10-Q for the period ended June 30, 2019 and our Registration Statement on Form S-4 that was initially filed on August 20, 2019 and declared effective on October 9, 2019.
 
Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3.  Defaults Upon Senior Securities

None.

Item 4.  Mine Safety Disclosures

Not applicable.

Item 5.  Other Information

None.


36


Item 6.  Exhibits

The following exhibits are filed as part of this Form 10-Q.
 
 
 
 
 
Incorporated by reference (File No. 001-14039, unless otherwise indicated)
Exhibit Number
Description
 
Form
 
Exhibit
 
Filing Date
2.1
±
 
 
8-K
 
2.1
 
07/14/2019
2.2
(a)
 
 
 
 
 
 
 
3.1
 
 
 
10-Q
 
3.1
 
11/03/2016
3.2
 
 
 
10-K
 
3.2
 
02/27/2019
10.1
 
 
 
8-K
 
10.1
 
07/14/2019
31.1
(a)
 
 
 
 
 
 
 
31.2
(a)
 
 
 
 
 
 
 
32.1
(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.


37


SIGNATURES

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

Callon Petroleum Company

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

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


38


Exhibit 2.2


AMENDMENT NO. 1
TO
AGREEMENT AND PLAN OF MERGER

This Amendment No. 1 to the Agreement and Plan of Merger (this “Amendment”) is effective as of August 19, 2019, by and between Callon Petroleum Company, a Delaware corporation (“Parent”), and Carrizo Oil & Gas, Inc., a Texas corporation (the “Company”).

RECITALS

WHEREAS, Parent and the Company are parties to that certain Agreement and Plan of Merger, dated as of July 14, 2019 (the “Merger Agreement”);

WHEREAS, in accordance with Section 8.11 of the Merger Agreement, Parent and the Company desire to amend the Merger Agreement as set forth herein.

AGREEMENT

NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, and intending to be legally bound, Parent and the Company agree as follows:

Section 1.    Definitions. Each capitalized term used but not otherwise defined herein shall have the meaning ascribed to such term in the Merger Agreement, as amended hereby.

Section 2.    Amendments to the Merger Agreement. The Exhibits to the Merger Agreement are hereby amended by deleting Exhibit A (Form of Parent Charter Amendment) of the Merger Agreement in its entirety and replacing it with a revised Exhibit A attached hereto as Exhibit A.

Section 3.    References to and Effect on Merger Agreement. On and after the date hereof, each reference in the Merger Agreement to “this Agreement,” “herein,” “hereby,” “hereunder,” “hereof,” or words of similar import referring to the Merger Agreement, and any reference to the Merger Agreement in any other agreements, instruments and documents executed and delivered in connection therewith, shall mean the Merger Agreement as amended by this Amendment. The provisions set forth in this Amendment shall be deemed to be and shall be construed as part of the Merger Agreement to the same extent as if fully set forth verbatim therein. Except as set forth in this Amendment, the terms of the Merger Agreement are unchanged and remain in full force and effect. The execution, delivery and effectiveness of this Amendment shall not operate as a waiver of any right, power or remedy of Parent or the Company under the Merger Agreement, nor constitute a waiver of any provision of the Merger Agreement.

Section 4.    Governing Law. This Amendment and all claims or causes of action (whether at Law, in contract or in tort or otherwise) that may be based upon, arise out of or relate to this Amendment or the negotiation, execution or performance hereof, shall be governed by and construed




in accordance with the laws of the State of Delaware, without giving effect to any choice or conflict of law provision or rule (whether of the State of Delaware or any other jurisdiction) that would cause the application of the laws of any jurisdiction other than the State of Delaware, except that notwithstanding the foregoing, issues related to the Merger, general corporation law and other provisions set forth herein that are required to be governed by the TBOC shall be covered by and construed in accordance with the laws of the State of Texas, without giving effect to any choice or conflict of law provision or rule (whether of the State of Texas or any other jurisdiction) that would cause the application of the laws of any jurisdiction other than the State of Texas.

Section 5.    Counterparts; Effectiveness. This Amendment may be executed in two or more counterparts, each of which shall be an original, with the same effect as if the signatures thereto and hereto were upon the same instrument, and shall become effective when one or more counterparts have been signed by each of the parties and delivered (by telecopy, electronic delivery or otherwise) to the other party. Signatures to this Amendment transmitted by electronic mail in .pdf form, or by any other electronic means intended to preserve the original graphic and pictorial appearance of a document, will have the same effect as physical delivery of the paper document bearing the original signature.

Section 6.    Headings. Headings of the Sections of this Amendment are for convenience of the parties only and shall be given no substantive or interpretive effect whatsoever.

[Signature pages follow]


2


IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed and delivered as of the date first written above.

CARRIZO OIL & GAS, INC.
 
 
 
 
 
 
By:
 
/s/ S.P. Johnson IV
 
 
 
 
Name: S.P. Johnson IV
 
Title: President and Chief Executive Officer
 
 
 
CALLON PETROLEUM COMPANY
 
 
 
 
 
 
By:
 
/s/ Joseph C. Gatto, Jr.
 
 
 
 
Name: Joseph C. Gatto, Jr.
 
Title: President and Chief Executive Officer

[Signature Page to Amendment No. 1 to Merger Agreement]


EXHIBIT A

(See attached.)






Exhibit A

FORM OF CERTIFICATE OF AMENDMENT
OF
CERTIFICATE OF INCORPORATION
OF
CALLON PETROLEUM COMPANY

The undersigned, Michol L. Ecklund, Corporate Secretary of Callon Petroleum Company, a corporation organized and existing under and by virtue of the General Corporation Law of the State of Delaware (the “Corporation”), does hereby certify as follows:

FIRST: The name of the Corporation is Callon Petroleum Company.

SECOND: This Amendment (the “Amendment”) to the Certificate of lncorporation of the Corporation (the “Certificate”) was duly adopted in accordance with the provisions of Section 242 of the Delaware General Corporation Law. The Board of Directors has duly adopted resolutions setting forth and declaring advisable this Amendment and the holders of a majority of the outstanding stock of the Corporation entitled to vote at the annual meeting of the stockholders called and held upon notice in accordance with Section 222 of the General Corporation Law of the State of Delaware for the purpose of voting on the Amendment have voted in favor of this Amendment.

THIRD: The Certificate is hereby amended by amending and restating the first sentence of Article Four to be and read as follows:

“The Corporation shall have authority to issue two classes of stock, and the total number authorized shall be 750,000,000 shares of Common Stock, par value $.01 per share, and 2,500,000 shares of Preferred Stock, par value $.01 per share.”

IN WITNESS WHEREOF, the undersigned has executed this Amendment on behalf of the Corporation and has attested such execution and does, verify and affirm, under penalty of perjury, that this Amendment is the act and deed of the Corporation and that the facts stated herein are true as of this [●] day of [●], [●].

Callon Petroleum Company

By:

Michol L. Ecklund, Corporate Secretary




Exhibit 31.1



CERTIFICATIONS

I, Joseph C. Gatto, Jr., certify that:

1.
I have reviewed this Quarterly Report on Form 10-Q of Callon Petroleum Company;

2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by this report based on such evaluation; and

d.
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a.
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:
November 4, 2019
 
/s/ Joseph C. Gatto, Jr.
 
 
 
Joseph C. Gatto, Jr.
 
 
 
President and Chief Executive Officer
 
 
 
(Principal executive officer)



Exhibit 31.2


CERTIFICATIONS

I, James P. Ulm, II, certify that:

1.
I have reviewed this Quarterly Report on Form 10-Q of Callon Petroleum Company;

2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by this report based on such evaluation; and

d.
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a.
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:
November 4, 2019
 
/s/ James P. Ulm, II
 
 
 
James P. Ulm, II
 
 
 
Senior Vice President and Chief Financial Officer
 
 
 
(Principal financial officer)



Exhibit 32.1


CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the Quarterly Report on Form 10-Q of Callon Petroleum Company for the quarterly period ended September 30, 2019, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, in the capacities and on the dates indicated below, each hereby certify pursuant to 18 U.S.C. section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Report fully complies with requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:
November 4, 2019
 
/s/ Joseph C. Gatto, Jr.
 
 
 
Joseph C. Gatto, Jr.
 
 
 
(Principal executive officer)
 
 
 
 
 
 
 
 
Date:
November 4, 2019
 
/s/ James P. Ulm, II
 
 
 
James P. Ulm, II
 
 
 
(Principal financial officer)

The foregoing certification is being furnished as an exhibit to the Report pursuant to Item 601(b)(32) of Regulation S-K and Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and, accordingly, is not being filed as part of the Report for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not incorporated by reference into any filing of the Company, whether made before or after the date hereof, regardless of any general incorporation language in such filing.