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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 June 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
 
 
 
 
 
 
 
 
 
 
1401 Enclave Pkwy,
Suite 600,
Houston,
TX
77077
 
 
 
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
10.0% Series A Cumulative Preferred Stock
 
CPE.A
 
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 228,304,366 shares of common stock outstanding as of July 31, 2019.



Table of Contents

Part I. Financial Information
 
 
 
Item 1. Financial Statements (Unaudited)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Part II.  Other Information
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

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.
PUDs:  proved undeveloped reserves.
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)
 
 
June 30, 2019
 
December 31, 2018
ASSETS
 
Unaudited
 
 
Current assets:
 
 
 
 
   Cash and cash equivalents
 
$
16,052

 
$
16,051

   Accounts receivable
 
93,039

 
131,720

   Fair value of derivatives
 
13,164

 
65,114

   Other current assets
 
15,841

 
9,740

      Total current assets
 
138,096

 
222,625

Oil and natural gas properties, full cost accounting method:
 
 
 
 
   Evaluated properties
 
4,665,761

 
4,585,020

   Less accumulated depreciation, depletion, amortization and impairment
 
(2,399,886
)
 
(2,270,675
)
   Evaluated oil and natural gas properties, net
 
2,265,875

 
2,314,345

   Unevaluated properties
 
1,429,624

 
1,404,513

      Total oil and natural gas properties, net
 
3,695,499

 
3,718,858

Operating lease right-of-use assets
 
31,904

 

Other property and equipment, net
 
23,363

 
21,901

Restricted investments
 
3,468

 
3,424

Deferred financing costs
 
5,427

 
6,087

Fair value of derivatives
 
11,679

 

Other assets, net
 
6,061

 
6,278

   Total assets
 
$
3,915,497

 
$
3,979,173

LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
 
Current liabilities:
 
 
 
 
   Accounts payable and accrued liabilities
 
$
221,452

 
$
261,184

   Operating lease liabilities
 
24,141

 

   Accrued interest
 
22,695

 
24,665

   Cash-settleable restricted stock unit awards
 
819

 
1,390

   Asset retirement obligations
 
3,103

 
3,887

   Fair value of derivatives
 
17,251

 
10,480

   Other current liabilities
 
2,472

 
13,310

      Total current liabilities
 
291,933

 
314,916

Senior secured revolving credit facility
 
105,000

 
200,000

6.125% senior unsecured notes due 2024
 
596,154

 
595,788

6.375% senior unsecured notes due 2026
 
394,106

 
393,685

Operating lease liabilities
 
7,680

 

Asset retirement obligations
 
9,315

 
10,405

Cash-settleable restricted stock unit awards
 
2,568

 
2,067

Deferred tax liability
 
21,106

 
9,564

Fair value of derivatives
 
3,663

 
7,440

Other long-term liabilities
 
100

 
100

   Total liabilities
 
1,431,625

 
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; 1,458,948 shares outstanding
 
15

 
15

   Common stock, $0.01 par value, 300,000,000 shares authorized; 228,263,955 and
227,582,575 shares outstanding, respectively
 
2,283

 
2,276

   Capital in excess of par value
 
2,483,945

 
2,477,278

   Accumulated deficit
 
(2,371
)
 
(34,361
)
      Total stockholders’ equity
 
2,483,872

 
2,445,208

Total liabilities and stockholders’ equity
 
$
3,915,497

 
$
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 June 30,
 
Six Months Ended June 30,
 
2019
 
2018
 
2019
 
2018
Operating revenues:
 
 
 
 
 
 
 
Oil sales
$
160,728

 
$
122,613

 
$
301,826

 
$
237,898

Natural gas sales
6,324

 
14,462

 
18,273

 
26,617

Total operating revenues
167,052

 
137,075

 
320,099

 
264,515

Operating expenses:
 
 
 
 
 
 
 
Lease operating expenses
22,776

 
13,141

 
46,843

 
26,179

Production taxes
11,131

 
7,539

 
21,944

 
16,002

Depreciation, depletion and amortization
62,921

 
38,733

 
122,688

 
74,151

General and administrative
10,564

 
8,289

 
22,317

 
17,057

Settled share-based awards

 

 
3,024

 

Accretion expense
216

 
206

 
457

 
424

Other operating expense
935

 
1,767

 
1,092

 
2,315

Total operating expenses
108,543

 
69,675

 
218,365

 
136,128

Income from operations
58,509

 
67,400

 
101,734

 
128,387

Other (income) expenses:
 
 
 
 
 
 
 
Interest expense, net of capitalized amounts
741

 
594

 
1,479

 
1,053

(Gain) loss on derivative contracts
(14,036
)
 
16,554

 
53,224

 
21,036

Other income
(67
)
 
(703
)
 
(148
)
 
(914
)
Total other (income) expense
(13,362
)
 
16,445

 
54,555

 
21,175

Income (loss) before income taxes
71,871

 
50,955

 
47,179

 
107,212

Income tax (benefit) expense
16,691

 
481

 
11,542

 
976

Net income (loss)
55,180

 
50,474

 
35,637

 
106,236

Preferred stock dividends
(1,823
)
 
(1,824
)
 
(3,647
)
 
(3,647
)
Income (loss) available to common stockholders
$
53,357

 
$
48,650

 
$
31,990

 
$
102,589

Income (loss) per common share:
 
 
 
 
 
 
 
Basic
$
0.23

 
$
0.23

 
$
0.14

 
$
0.50

Diluted
$
0.23

 
$
0.23

 
$
0.14

 
$
0.50

Weighted average common shares outstanding:
 
 
 
 
 
 
 
Basic
228,051

 
210,698

 
227,917

 
206,309

Diluted
228,411

 
211,465

 
228,599

 
207,027


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


5


Callon Petroleum Company
Consolidated Statements of Cash Flows
(Unaudited; in thousands)
 
Six Months Ended June 30,
Cash flows from operating activities:
2019
 
2018
Net income (loss)
$
35,637

 
$
106,236

Adjustments to reconcile net income to cash provided by operating activities:
 
 
 
   Depreciation, depletion and amortization
125,046

 
75,453

   Accretion expense
457

 
424

   Amortization of non-cash debt related items
1,479

 
1,041

   Deferred income tax (benefit) expense
11,542

 
976

   (Gain) loss on derivatives, net of settlements
51,777

 
4,594

   Loss on sale of other property and equipment
49

 
22

   Non-cash expense related to equity share-based awards
6,299

 
2,758

   Change in the fair value of liability share-based awards
1,031

 
549

   Payments to settle asset retirement obligations
(771
)
 
(573
)
   Payments for cash-settled restricted stock unit awards
(1,425
)
 
(4,990
)
Changes in current assets and liabilities:
 
 
 
   Accounts receivable
38,681

 
2,380

   Other current assets
(6,101
)
 
(5,550
)
   Current liabilities
(36,254
)
 
17,061

   Other
(2,401
)
 
(402
)
Net cash provided by operating activities
225,046

 
199,979

Cash flows from investing activities:
 
 
 
Capital expenditures
(359,430
)
 
(298,370
)
Acquisitions
(39,370
)
 
(45,392
)
Acquisition deposit

 
(27,600
)
Proceeds from sale of assets
274,296

 
3,077

Net cash used in investing activities
(124,504
)
 
(368,285
)
Cash flows from financing activities:
 
 
 
Borrowings on senior secured revolving credit facility
360,000

 
165,000

Payments on senior secured revolving credit facility
(455,000
)
 
(190,000
)
Issuance of 6.375% senior unsecured notes due 2026

 
400,000

Issuance of common stock

 
288,357

Payment of preferred stock dividends
(3,647
)
 
(3,647
)
Payment of deferred financing costs
(31
)
 
(8,664
)
Tax withholdings related to restricted stock units
(1,858
)
 
(1,589
)
Other financing activities
(5
)
 

Net cash provided by (used in) financing activities
(100,541
)
 
649,457

Net change in cash and cash equivalents
1

 
481,151

Balance, beginning of period
16,051

 
27,995

Balance, end of period
$
16,052

 
$
509,146

 
 
 
 
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
1,293

 

      Investing cash flows from operating leases
17,865

 

Non-cash investing and financing activities:
 
 
 
   Change in accrued capital expenditures
$
(16,286
)
 
$
16,088

   Change in asset retirement costs

 
4,440

   Right-of-use assets obtained in exchange for operating lease liabilities
2,462

 

   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)

 
Preferred
 
Common
 
Capital in
 
 
 
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 income (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 (loss)

 

 

 

 

 
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



 
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 (loss)

 

 

 

 

 
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 (loss)

 

 

 

 

 
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


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
8.
9.
3.
10.
4.
11.
5.
12.
6.
13.
7.
 
 

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 Callon Petroleum Operating Company.

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 sheets at March 31, 2019 and June 30, 2019, resulting from the recognition 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 six months ended June 30, 2019, $2,805 and $5,213 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 six months ended June 30, 2018, $1,952 and $3,204

9

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

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 revenues from contracts with customers of our oil and natural gas production, which had a balance at June 30, 2019 and December 31, 2018 of $67,891 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

On June 12, 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 (loss) per share is computed by dividing income (loss) available to common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings (loss) 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 June 30,
 
Six Months Ended June 30,
 
2019
 
2018
 
2019
 
2018
Net income (loss)
$
55,180

 
$
50,474

 
$
35,637

 
$
106,236

Preferred stock dividends
(1,823
)
 
(1,824
)
 
(3,647
)
 
(3,647
)
Income (loss) available to common stockholders
$
53,357

 
$
48,650

 
$
31,990

 
$
102,589

 
 
 
 
 
 
 
 
Weighted average common shares outstanding
228,051

 
210,698

 
227,917

 
206,309

Dilutive impact of restricted stock
360

 
767

 
682

 
718

Weighted average common shares outstanding for diluted income (loss) per share
228,411

 
211,465

 
228,599

 
207,027

 
 
 
 
 
 
 
 
Basic income (loss) per share
$
0.23

 
$
0.23

 
$
0.14

 
$
0.50

Diluted income (loss) per share
$
0.23

 
$
0.23

 
$
0.14

 
$
0.50

 
 
 
 
 
 
 
 
Restricted stock (a)
641

 

 
498

 


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

Note 5 - Borrowings

The Company’s borrowings consisted of the following:
 
 
As of
Principal components:
 
June 30, 2019
 
December 31, 2018
Senior secured revolving credit facility
 
$
105,000

 
$
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
 
1,105,000

 
1,200,000

Premium on 6.125% senior unsecured notes due 2024, net of accumulated amortization
 
5,906

 
6,469

Unamortized deferred financing costs
 
(15,646
)
 
(16,996
)
Total carrying value of borrowings (a)
 
$
1,095,260

 
$
1,189,473



11

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

(a) 
Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $5,427 and $6,087 as of June 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 (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 June 30, 2019, the Credit Facility’s borrowing base remained at $1,100,000 with an elected commitment amount of $850,000.

As of June 30, 2019, there was $105,000 principal and $17,675 in letters of credit outstanding under the Credit Facility. For the period ended June 30, 2019, the Credit Facility had a weighted-average interest rate of 3.65%, 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 June 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.

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


12

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

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 June 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
 
$2,485
 
 
2020
 
Greater than $60/bbl, less than $65/bbl
 
$9,000
 
Equal to or greater than $65/bbl
 
$20,833
 
$5,085
 
 
2021
 
Greater than $60/bbl, less than $65/bbl
 
$9,000
 
Equal to or greater than $65/bbl
 
$20,833
(c) 
$4,255
 
 
(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.

The following table reflects the fair value of the Company’s derivative instruments for the periods presented:
As of June 30, 2019
Derivative Instrument
 
Balance Sheet Presentation
 
Asset
 
Liability
 
Net Asset (Liability)
Commodity - Oil
 
Fair value of derivatives - Current
 
$
8,671

 
$
(17,251
)
 
$
(8,580
)
Commodity - Natural gas
 
Fair value of derivatives - Current
 
2,008

 

 
2,008

Contingent consideration arrangement
 
Fair value of derivatives - Current
 
2,485

 

 
2,485

Commodity - Oil
 
Fair value of derivatives - Non-current
 
2,335

 
(3,327
)
 
(992
)
Commodity - Natural gas
 
Fair value of derivatives - Non-current
 
4

 
(336
)
 
(332
)
Contingent consideration arrangement
 
Fair value of derivatives - Non-current
 
9,340

 

 
9,340

   Totals
 
 
 
$
24,843

 
$
(20,914
)
 
$
3,929

 
 
 
 
 
 
 
 
 
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 June 30, 2019
 
Presented without
 
 
 
As Presented with
 
Effects of Netting
 
Effects of Netting
 
Effects of Netting
Current assets: Fair value of commodity derivatives
$
20,044

 
$
(9,365
)
 
$
10,679

Long-term assets: Fair value of commodity derivatives
4,420

 
(2,081
)
 
2,339

 
 
 
 
 
 
Current liabilities: Fair value of commodity derivatives
$
(26,616
)
 
$
9,365

 
$
(17,251
)
Long-term liabilities: Fair value of commodity derivatives
(5,744
)
 
2,081

 
(3,663
)

13

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

 
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 June 30,
 
Six Months Ended June 30,
 
2019
 
2018
 
2019
 
2018
Oil derivatives
 
 
 
 
 
 
 
Net gain (loss) on settlements
$
(4,461
)
 
$
(8,131
)
 
$
(6,003
)
 
$
(