Company Quick10K Filing
Quick10K
Callon Petroleum
Closing Price ($) Shares Out (MM) Market Cap ($MM)
$8.10 228 $1,850
10-Q 2019-03-31 Quarter: 2019-03-31
10-K 2018-12-31 Annual: 2018-12-31
10-Q 2018-09-30 Quarter: 2018-09-30
10-Q 2018-06-30 Quarter: 2018-06-30
10-Q 2018-03-31 Quarter: 2018-03-31
10-K 2017-12-31 Annual: 2017-12-31
10-Q 2017-09-30 Quarter: 2017-09-30
10-Q 2017-06-30 Quarter: 2017-06-30
10-Q 2017-03-31 Quarter: 2017-03-31
10-K 2016-12-31 Annual: 2016-12-31
10-Q 2016-09-30 Quarter: 2016-09-30
10-Q 2016-06-30 Quarter: 2016-06-30
10-Q 2016-03-31 Quarter: 2016-03-31
10-K 2015-12-31 Annual: 2015-12-31
10-Q 2015-09-30 Quarter: 2015-09-30
10-Q 2015-06-30 Quarter: 2015-06-30
10-Q 2015-03-31 Quarter: 2015-03-31
10-K 2014-12-31 Annual: 2014-12-31
10-Q 2014-09-30 Quarter: 2014-09-30
10-Q 2014-06-30 Quarter: 2014-06-30
10-Q 2014-03-31 Quarter: 2014-03-31
10-K 2013-12-31 Annual: 2013-12-31
8-K 2019-07-15 Officers
8-K 2019-07-14 Enter Agreement, Earnings, Regulation FD, Exhibits
8-K 2019-06-18 Other Events, Exhibits
8-K 2019-06-12 M&A, Regulation FD, Exhibits
8-K 2019-05-09 Shareholder Vote
8-K 2019-05-06 Earnings, Regulation FD, Exhibits
8-K 2019-04-05 Other Events, Exhibits
8-K 2019-03-13 Officers
8-K 2019-03-05 Officers
8-K 2019-02-26 Earnings, Regulation FD, Exhibits
8-K 2019-02-12 Earnings, Regulation FD, Exhibits
8-K 2019-01-02 Officers
8-K 2018-11-06 Earnings, Regulation FD, Exhibits
8-K 2018-11-01 Officers, Exhibits
8-K 2018-09-27 Enter Agreement, Off-BS Arrangement, Exhibits
8-K 2018-08-31 M&A, Regulation FD, Exhibits
8-K 2018-08-06 Earnings, Regulation FD, Exhibits
8-K 2018-06-07 Enter Agreement, Off-BS Arrangement, Other Events, Exhibits
8-K 2018-05-31 Enter Agreement, Off-BS Arrangement, Other Events, Exhibits
8-K 2018-05-24 Enter Agreement, Regulation FD, Exhibits
8-K 2018-05-23 Enter Agreement, Regulation FD, Exhibits
8-K 2018-05-10 Shareholder Vote, Other Events, Exhibits
8-K 2018-04-05 Enter Agreement, Off-BS Arrangement, Exhibits
8-K 2018-03-07 Officers, Exhibits
8-K 2018-02-01 Regulation FD, Exhibits
IRM Iron Mountain 8,880
UFS Domtar 2,940
RDFN Redfin 1,540
MBIO Mustang Bio 160
IVAC Intevac 121
ICCH ICC Holdings 50
HIHO Highway Holdings 12
GSRX Green Spirit Industries 0
SENY Sauer Energy 0
IAMXU I-Am Capital Acquisition 0
CPE 2019-03-31
Part I. Financial Information
Item 1. Financial Statements
Note 1 - Description of Business and Basis of Presentation
Note 2 - Revenue Recognition
Note 3 - Acquisitions and Dispositions
Note 4 - Earnings per Share
Note 5 - Borrowings
Note 6 - Derivative Instruments and Hedging Activities
Note 7 - Fair Value Measurements
Note 8 - Income Taxes
Note 9 - Equity Transactions
Note 10 - Leases
Note 11 - Asset Retirement Obligations
Note 12 - Other
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Item 4. Controls and Procedures
Part II. Other Information
Item 1. Legal Proceedings
Item 1A. Risk Factors
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Item 3. Defaults Upon Senior Securities
Item 4. Mine Safety Disclosures
Item 5. Other Information
Item 6. Exhibits
EX-10.1 ex101weantseparationagreem.htm
EX-10.9 ex109amendmentno3to6thamen.htm
EX-31.1 ex311-1q19ceocertification.htm
EX-31.2 ex312-1q19cfocertification.htm
EX-32.1 ex32-1q19section1350certif.htm

Callon Petroleum Earnings 2019-03-31

CPE 10Q Quarterly Report

Balance SheetIncome StatementCash Flow

10-Q 1 a1q19form10q.htm 10-Q Document
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q
(Mark One)
☒     QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended March 31, 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.
1401 Enclave Parkway, Suite 600
Houston, Texas
 
77077
Address of Principal Executive Offices
 
Zip Code
 
(281) 589-5200
 
 
Registrant’s Telephone Number, Including Area Code
 
 
 
 
 
Not Applicable
 
 
Former Name, Former Address and Former Fiscal Year, if Changed Since Last Report
 

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 ☒

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

The Registrant had 227,912,687 shares of common stock outstanding as of May 1, 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.
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 natural gas 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 per share data)
 
 
March 31, 2019
 
December 31, 2018
ASSETS
 
Unaudited
 
 
Current assets:
 
 
 
 
   Cash and cash equivalents
 
$
10,482

 
$
16,051

   Accounts receivable
 
137,110

 
131,720

   Fair value of derivatives
 
11,372

 
65,114

   Other current assets
 
12,034

 
9,740

      Total current assets
 
170,998

 
222,625

Oil and natural gas properties, full cost accounting method:
 
 
 
 
   Evaluated properties
 
4,760,071

 
4,585,020

   Less accumulated depreciation, depletion, amortization and impairment
 
(2,333,589
)
 
(2,270,675
)
   Evaluated oil and natural gas properties, net
 
2,426,482

 
2,314,345

   Unevaluated properties
 
1,432,118

 
1,404,513

      Total oil and natural gas properties, net
 
3,858,600

 
3,718,858

Operating lease right-of-use assets
 
40,977

 

Other property and equipment, net
 
22,413

 
21,901

Restricted investments
 
3,450

 
3,424

Deferred financing costs
 
5,742

 
6,087

Fair value of derivatives
 
385

 

Other assets, net
 
6,269

 
6,278

   Total assets
 
$
4,108,834

 
$
3,979,173

LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
 
Current liabilities:
 
 
 
 
   Accounts payable and accrued liabilities
 
$
230,990

 
$
261,184

   Operating lease liabilities
 
29,134

 

   Accrued interest
 
25,920

 
24,665

   Cash-settleable restricted stock unit awards
 
1,060

 
1,390

   Asset retirement obligations
 
3,771

 
3,887

   Fair value of derivatives
 
24,550

 
10,480

   Other current liabilities
 
8,512

 
13,310

      Total current liabilities
 
323,937

 
314,916

Senior secured revolving credit facility
 
330,000

 
200,000

6.125% senior unsecured notes due 2024
 
595,971

 
595,788

6.375% senior unsecured notes due 2026
 
393,896

 
393,685

Operating lease liabilities
 
11,751

 

Asset retirement obligations
 
10,189

 
10,405

Cash-settleable restricted stock unit awards
 
2,252

 
2,067

Deferred tax liability
 
4,415

 
9,564

Fair value of derivatives
 
6,983

 
7,440

Other long-term liabilities
 
995

 
100

   Total liabilities
 
1,680,389

 
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; 227,884,091 and
227,582,575 shares outstanding, respectively
 
2,279

 
2,276

   Capital in excess of par value
 
2,481,879

 
2,477,278

   Accumulated deficit
 
(55,728
)
 
(34,361
)
      Total stockholders’ equity
 
2,428,445

 
2,445,208

Total liabilities and stockholders’ equity
 
$
4,108,834

 
$
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 March 31,
 
2019
 
2018
Operating revenues:
 
 
 
Oil sales
$
141,098

 
$
115,286

Natural gas sales
11,949

 
12,154

Total operating revenues
153,047

 
127,440

Operating expenses:
 
 
 
Lease operating expenses
24,067

 
13,039

Production taxes
10,813

 
8,463

Depreciation, depletion and amortization
59,767

 
35,417

General and administrative
11,753

 
8,769

Settled share-based awards
3,024

 

Accretion expense
241

 
218

Acquisition expense
157

 
548

Total operating expenses
109,822

 
66,454

Income from operations
43,225

 
60,986

Other (income) expenses:
 
 
 
Interest expense, net of capitalized amounts
738

 
460

Loss on derivative contracts
67,260

 
4,481

Other income
(81
)
 
(211
)
Total other (income) expense
67,917

 
4,730

Income (loss) before income taxes
(24,692
)
 
56,256

Income tax (benefit) expense
(5,149
)
 
495

Net income (loss)
(19,543
)
 
55,761

Preferred stock dividends
(1,824
)
 
(1,824
)
Income (loss) available to common stockholders
$
(21,367
)
 
$
53,937

Income per common share:
 
 
 
Basic
$
(0.09
)
 
$
0.27

Diluted
$
(0.09
)
 
$
0.27

Weighted average common shares outstanding:
 
 
 
Basic
227,784

 
201,921

Diluted
227,784

 
202,588


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


5


Callon Petroleum Company
Consolidated Statements of Cash Flows
(Unaudited; in thousands)
 
Three Months Ended March 31,
Cash flows from operating activities:
2019
 
2018
Net income (loss)
$
(19,543
)
 
$
55,761

Adjustments to reconcile net income to cash provided by operating activities:
 
 
 
   Depreciation, depletion and amortization
60,672

 
36,066

   Accretion expense
241

 
218

   Amortization of non-cash debt related items
738

 
453

   Deferred income tax (benefit) expense
(5,149
)
 
495

   (Gain) loss on derivatives, net of settlements
66,970

 
(3,978
)
   Loss on sale of other property and equipment
28

 

   Non-cash expense related to equity share-based awards
4,545

 
1,131

   Change in the fair value of liability share-based awards
1,881

 
1,012

   Payments to settle asset retirement obligations
(664
)
 
(366
)
   Payments for cash-settled restricted stock unit awards
(1,296
)
 
(3,089
)
Changes in current assets and liabilities:
 
 
 
   Accounts receivable
(5,390
)
 
(8,067
)
   Other current assets
(2,294
)
 
61

   Current liabilities
(26,003
)
 
12,938

   Other
(177
)
 
(420
)
Net cash provided by operating activities
74,559

 
92,215

Cash flows from investing activities:
 
 
 
Capital expenditures
(193,211
)
 
(111,330
)
Acquisitions
(27,947
)
 
(38,923
)
Acquisition deposit

 
900

Proceeds from sale of assets
13,879

 

Net cash used in investing activities
(207,279
)
 
(149,353
)
Cash flows from financing activities:
 
 
 
Borrowings on senior secured revolving credit facility
220,000

 
80,000

Payments on senior secured revolving credit facility
(90,000
)
 
(30,000
)
Payment of preferred stock dividends
(1,824
)
 
(1,824
)
Tax withholdings related to restricted stock units
(1,025
)
 
(560
)
Net cash provided by financing activities
127,151

 
47,616

Net change in cash and cash equivalents
(5,569
)
 
(9,522
)
Balance, beginning of period
16,051

 
27,995

Balance, end of period
$
10,482

 
$
18,473

 
 
 
 
Supplemental cash flow information:
 
 
 
Non-cash investing activities:
 
 
 
   Change in accrued capital expenditures
$
(7,854
)
 
$
20,727

   Change in asset retirement costs
132

 
4,358

   Operating leases
2,022

 

Net cash used in operating activities:
 
 
 
   Interest paid, net of capitalized amounts
$

 
$

   Income taxes paid

 

   Cash paid for amounts included in the measurement of lease liabilities
9,565

 


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 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

 

 

 

 

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

 
$
15

 
227,884

 
$
2,279

 
$
2,481,879

 
$
(55,728
)
 
$
2,428,445


 
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

 

 

 

 

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

 
$
15

 
201,948

 
$
2,019

 
$
2,182,599

 
$
(273,489
)
 
$
1,911,144


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 is an independent oil and natural gas company established in 1950. The Company was incorporated under the laws of the state of Delaware in 1994 and succeeded to the business of a publicly traded limited partnership, a joint venture with a consortium of European investors and an independent energy company. 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.

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.

Summary of Significant Accounting Policies

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 months ended March, 31, 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.

8

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


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.

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.

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


9

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

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 March 31, 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. 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.

Recently issued ASUs

In March 2019, the FASB issued ASU No. 2019-01, Leases (Topic 842): Codification Improvements (“ASU 2019-01”). The standard is intended to clarify the requirements related to interim transition disclosures upon adoption of ASC Topic 842. The guidance in ASU 2019-01 is effective for public entities for annual reporting periods beginning after December 15, 2019, including interim periods therein. The Company does not expect 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 months

10

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

ended March 31, 2019 and 2018, $2,408 and $1,252 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 March 31, 2019 and December 31, 2018 of $98,568 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

During 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 for certain leasehold interests in our WildHorse acreage, including customary purchase price adjustments.

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


The preliminary purchase price allocations are subject to change based on numerous factors, including the final adjusted purchase price and the final estimated fair value of the assets acquired and liabilities assumed. Any such adjustments to the preliminary estimates of fair value could be material.

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.


11

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

Subsequent Event

On April 8, 2019, the Company entered into a definitive agreement regarding the sale of certain non-core assets, the Ranger assets, in the Midland Basin for initial cash proceeds of $260,000, excluding customary purchase price adjustments. The agreement also provides for potential contingency payments of up to $60,000 based on WTI average annual pricing over a three-year period.

The sale of the Company’s Ranger assets will not significantly alter the relationship between capitalized costs and proved reserves, and as such, all proceeds will be recorded as adjustments to our full cost pool with no gain or loss recognized. We expect the transaction to close in the second quarter of 2019.

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:
(share amounts in thousands)
Three Months Ended March 31,
 
2019
 
2018
Net income (loss)
$
(19,543
)
 
$
55,761

Preferred stock dividends
(1,824
)
 
(1,824
)
Income (loss) available to common stockholders
$
(21,367
)
 
$
53,937

 
 
 
 
Weighted average common shares outstanding
227,784

 
201,921

Dilutive impact of restricted stock

 
667

Weighted average common shares outstanding for diluted income per share
227,784

 
202,588

 
 
 
 
Basic income per share
$
(0.09
)
 
$
0.27

Diluted income per share
$
(0.09
)
 
$
0.27

 
 
 
 
Restricted stock (a)
356

 
3


(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:
 
March 31, 2019
 
December 31, 2018
Senior secured revolving credit facility
 
$
330,000

 
$
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
 
1,330,000

 
1,200,000

Premium on 6.125% senior unsecured notes due 2024, net of accumulated amortization
 
6,187

 
6,469

Unamortized deferred financing costs
 
(16,320
)
 
(16,996
)
Total carrying value of borrowings (a)
 
$
1,319,867

 
$
1,189,473

(a)
Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $5,742 and $6,087 as of March 31, 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 with a maturity date of May 25, 2022. 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.


12

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

Effective April 5, 2018, the Company entered into the first amendment to the Sixth Amended and Restated Credit Agreement to the Credit Facility, which (1) increased the borrowing base to $825,000, (2) increased the elected commitment amount to $650,000, (3) amended various covenants and terms to reflect current market trends, and (4) extended the maturity date to May 25, 2023.

Effective September 27, 2018, the Company entered into the second amendment to the Sixth Amended and Restated Credit Agreement to the Credit Facility, which (1) increased the borrowing base to $1,100,000, (2) increased the elected commitment amount to $850,000, and (3) amended various covenants and terms to reflect current market trends. As of March 31, 2019, the Credit Facility’s borrowing base remained at $1,100,000 with an elected commitment amount of $850,000.

As of March 31, 2019, there was $330,000 principal and $17,675 in letters of credit outstanding under the Credit Facility. For the period ended March 31, 2019, the Credit Facility had a weighted-average interest rate of 4.00%, 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. 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; and (ii) amend various covenants and terms to reflect current market trends.

6.125% senior unsecured notes due 2024 (“6.125% Senior Notes”)

On October 3, 2016, the Company issued $400,000 aggregate principal amount of 6.125% Senior Notes with a maturity date of October 1, 2024 and interest payable semi-annually beginning on April 1, 2017. The net proceeds of the offering, after deducting initial purchasers’ discounts and estimated offering expenses, were approximately $391,270. The 6.125% Senior Notes are guaranteed on a senior unsecured basis by the Company’s wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. The subsidiary guarantor is 100% owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantor are minor.

On May 19, 2017, the Company issued an additional $200,000 aggregate principal amount of its 6.125% Senior Notes which with the existing $400,000 aggregate principal amount of 6.125% Senior Notes are treated as a single class of notes under the indenture. The net proceeds of the offering, including a premium issue price of 104.125% and after deducting initial purchasers’ discounts and estimated offering expenses, were approximately $206,139.

The Company may redeem the 6.125% Senior Notes in accordance with the following terms: (1) prior to October 1, 2019, a redemption of up to 35% of the principal in an amount not greater than the net proceeds from certain equity offerings, and within 180 days of the closing date of such equity offerings, at a redemption price of 106.125% of principal, plus accrued and unpaid interest, if any, to the date of the redemption, if at least 65% of the principal will remain outstanding after such redemption; (2) prior to October 1, 2019, a redemption of all or part of the principal at a price of 100% of principal of the amount redeemed, plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of the redemption; and (3) a redemption, in whole or in part, at a redemption price, plus accrued and unpaid interest, if any, to the date of the redemption, (i) of 104.594% of principal if the redemption occurs on or after October 1, 2019, but before October 1, 2020, and (ii) of 103.063% of principal if the redemption occurs on or after October 1, 2020, but before October 1, 2021, and (iii) of 101.531% of principal if the redemption occurs on or after October 1, 2021, but before October 1, 2022, and (iv) of 100% of principal if the redemption occurs on or after October 1, 2022.

Following a change of control, each holder of the 6.125% Senior Notes may require the Company to repurchase all or a portion of the 6.125% Senior Notes at a price of 101% of principal of the amount repurchased, plus accrued and unpaid interest, if any, to the date of repurchase.

6.375% senior unsecured notes due 2026 (“6.375% Senior Notes”)

On June 7, 2018, the Company issued $400,000 aggregate principal amount of 6.375% Senior Notes with a maturity date of July 1, 2026 and interest payable semi-annually beginning on January 1, 2019. The net proceeds of the offering, after deducting initial purchasers’ discounts and estimated offering expenses, were approximately $394,000. The 6.375% Senior Notes are guaranteed on a senior unsecured basis by the Company’s wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. The subsidiary guarantor is 100% owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantor are minor.

The Company may redeem the 6.375% Senior Notes in accordance with the following terms: (1) prior to July 1, 2021, a redemption of up to 35% of the principal in an amount not greater than the net proceeds from certain equity offerings, and within 180 days of the closing

13

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

date of such equity offerings, at a redemption price of 106.375% of principal, plus accrued and unpaid interest, if any, to the date of the redemption, if at least 65% of the principal will remain outstanding after such redemption; (2) prior to July 1, 2021, a redemption of all or part of the principal at a price of 100% of principal of the amount redeemed, plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of the redemption; and (3) a redemption, in whole or in part, at a redemption price, plus accrued and unpaid interest, if any, to the date of the redemption, (i) of 103.188% of principal if the redemption occurs on or after July 1, 2021, but before July 1, 2022, and (ii) of 102.125% of principal if the redemption occurs on or after July 1, 2022, but before July 1, 2023, and (iii) of 101.063% of principal if the redemption occurs on or after July 1, 2023, but before July 1, 2024, and (iv) of 100% of principal if the redemption occurs on or after July 1, 2024.

Following a change of control, each holder of the 6.375% Senior Notes may require the Company to repurchase all or a portion of the 6.375% Senior Notes at a price of 101% of principal of the amount repurchased, plus accrued and unpaid interest, if any, to the date of repurchase.

Restrictive covenants

The Company’s Credit Facility and the indentures governing its 6.125% and 6.375% 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 March 31, 2019.

Note 6 - Derivative Instruments and Hedging Activities

Objectives and strategies for using 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 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.

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: 

14

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

 
 
Balance Sheet Presentation
 
Asset Fair Value
 
Liability Fair Value
 
Net Derivative Fair Value
Commodity
 
Classification
 
Line Description
 
3/31/2019
 
12/31/2018
 
3/31/2019
 
12/31/2018
 
3/31/2019
 
12/31/2018
Oil
 
Current
 
Fair value of derivatives
 
$
7,473

 
$
60,097

 
$
(24,550
)
 
$
(10,480
)
 
$
(17,077
)
 
$
49,617

Oil
 
Non-current
 
Fair value of derivatives
 
385

 

 
(6,190
)
 
(5,672
)
 
(5,805
)
 
(5,672
)
Natural gas
 
Current
 
Fair value of derivatives
 
3,899

 
5,017

 

 

 
3,899

 
5,017

Natural gas
 
Non-current
 
Fair value of derivatives
 

 

 
(793
)
 
(1,768
)
 
(793
)
 
(1,768
)
   Totals
 
 
 
 
 
$
11,757

 
$
65,114

 
$
(31,533
)
 
$
(17,920
)
 
$
(19,776
)
 
$
47,194


As previously discussed, the Company’s derivative contracts are subject to master netting arrangements. The Company’s policy is to present the fair value of 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 March 31, 2019
 
Presented without
 
 
 
As Presented with
 
Effects of Netting
 
Effects of Netting
 
Effects of Netting
Current assets: Fair value of derivatives
$
20,540

 
$
(9,168
)
 
$
11,372

Long-term assets: Fair value of derivatives
829

 
(444
)
 
385

 
 
 
 
 
 
Current liabilities: Fair value of derivatives
$
(33,718
)
 
$
9,168

 
$
(24,550
)
Long-term liabilities: Fair value of derivatives
(7,427
)
 
444

 
(6,983
)
 
As of December 31, 2018
 
Presented without
 
 
 
As Presented with
 
Effects of Netting
 
Effects of Netting
 
Effects of Netting
Current assets: Fair value of derivatives
$
78,091

 
$
(12,977
)
 
$
65,114

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

 
$
(10,480
)
Long-term liabilities: Fair value of 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 March 31,
 
 
2019
 
2018
Oil derivatives
 
 
 
 
Net loss on settlements
 
$
(1,542
)
 
$
(8,916
)
Net gain (loss) on fair value adjustments
 
(66,827
)
 
4,067

Total loss on oil derivatives
 
(68,369
)
 
(4,849
)
Natural gas derivatives
 
 
 
 
Net gain on settlements
 
1,252

 
457

Net loss on fair value adjustments
 
(143
)
 
(89
)
Total gain on natural gas derivatives
 
1,109

 
368

Total loss on oil & natural gas derivatives
 
$
(67,260
)
 
$
(4,481
)


15

 
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 March 31, 2019:  
 
For the Remainder
 
For the Full Year
Oil contracts (WTI)
of 2019
 
of 2020
Puts
 
 
 
   Total volume (Bbls)
687,500

 

   Weighted average price per Bbl
$
65.00

 
$

Put spreads
 
 
 
Total volume (Bbls)
687,500

 

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

 
$

Floor (short put)
$
42.50

 
$

Collar contracts combined with short puts (three-way collars)
 
 
 
Total volume (Bbls)
3,484,000

 
915,000

Weighted average price per Bbl
 
 
 
Ceiling (short call)
$
67.56

 
$
65.02

Floor (long put)
$
56.58

 
$
55.00

Floor (short put)
$
43.62

 
$
45.00

Collar contracts (two-way collars)
 
 
 
Total volume (Bbls)

 
732,000

Weighted average price per Bbl
 
 
 
Ceiling (short call)
$

 
$
64.63

Floor (long put)
$

 
$
55.00

 
 
 
 
Oil contracts (Midland basis differential)
 
 
 
Swap contracts
 
 
 
Total volume (Bbls)
5,102,000

 
4,576,000

Weighted average price per Bbl
$
(3.95
)
 
$
(1.29
)
 
 
 
 
Natural gas contracts (Henry Hub)
 
 
 
Collar contracts (two-way collars)
 
 
 
   Total volume (MMBtu)
2,697,500

 

   Weighted average price per MMBtu
 
 
 
      Ceiling (short call)
$
3.68

 
$

      Floor (long put)
$
3.09

 
$

Swap contracts
 
 
 
   Total volume (MMBtu)
1,852,000

 

   Weighted average price per MMBtu
$
2.88

 

 
 
 
 
Natural gas contracts (Waha basis differential)
 
 
 
Swap contracts
 
 
 
   Total volume (MMBtu)
5,961,000

 
4,758,000

   Weighted average price per MMBtu
$
(1.19
)
 
$
(1.12
)

Note 7 - Fair Value Measurements

The fair value hierarchy included in GAAP 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.


16

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

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.
 
 
March 31, 2019
 
December 31, 2018
 
 
Carrying Value
 
Fair Value
 
Carrying Value
 
Fair Value
Credit Facility (a)
 
$
330,000

 
$
330,000

 
$
200,000

 
$
200,000

6.125% Senior Notes (b)
 
595,971

 
604,008

 
595,788

 
558,000

6.375% Senior Notes (b)
 
393,896

 
402,264

 
393,685

 
372,000

Total
 
$
1,319,867

 
$
1,336,272

 
$
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.
 
The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis:
March 31, 2019
 
Classification
 
Level 1
 
Level 2
 
Level 3
 
Total
Assets
 
 
 
 
 
 
 
 
 
 
Derivative financial instruments
 
Fair value of derivatives
 
$

 
$
11,757

 
$

 
$
11,757

Liabilities
 
 
 
 
 
 
 
 
 
 
Derivative financial instruments
 
Fair value of derivatives
 

 
(31,533
)
 

 
(31,533
)
Total net assets (liabilities)
 
 
 
$

 
$
(19,776
)
 
$

 
$
(19,776
)
 
 
 
 
 
 
 
 
 
 
 
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:

17

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

 
Three Months Ended
Components of income tax rate reconciliation
March 31, 2019
 
March 31, 2018
Income tax expense computed at the statutory federal income tax rate
21
 %
 
21
 %
State taxes net of federal expense
1
 %
 
1
 %
Section 162(m)
1
 %
 
 %
Valuation allowance
 %
 
(21
)%
Effective income tax rate, before discrete items
23
 %
 
1
 %
   Discrete items (a)
(2
)%
 
 %
Effective income tax rate, after discrete items
21
 %
 
1
 %

(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 Preferred Stock are 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 are 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 of $1,824 for the three months ended March 31, 2019 remained consistent compared to the same period of 2018.

The Preferred Stock has no stated maturity and is not subject to any sinking fund or other mandatory redemption. The Company may, at its option, redeem the Preferred Stock, in whole or in part, at any time on or after May 30, 2018, by paying $50.00 per share, plus any accrued and unpaid dividends to the redemption date.

Following a change of control in which the Company or the acquirer no longer have a class of common securities listed on a national exchange, the Company will have the option to redeem the Preferred Stock, in whole but not in part, for $50.00 per share in cash plus accrued and unpaid dividends (whether or not declared) to the redemption date. If the Company does not exercise its option to redeem the Preferred Stock upon such change of control, the holders of the Preferred Stock have the option to convert the Preferred Stock into a number of shares of the Company’s common stock based on the value of the common stock on the date of the change of control as determined under the certificate of designations for the Preferred Stock. If the change of control occurred on March 31, 2019, and the Company did not exercise its right to redeem the Preferred Stock, using the closing price of $7.55 as the value of a share of common stock, each share of Preferred Stock would be convertible into approximately 6.6 shares of common stock. If the Company exercises its redemption rights relating to shares of Preferred Stock, the holders of Preferred Stock will not have the conversion right described above.

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

As previously described in Note 1 - Summary of Significant Accounting Policies, 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. 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
 
March 31, 2019
Operating lease cost
$
9,565

Short-term lease cost (a)
$
1,498


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

18

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

 
 
Supplemental balance sheet information related to our operating leases is included in the table below:
 
As of March 31, 2019
Operating lease right-of-use assets
$
40,977

 
 
Current operating lease liabilities
29,134

Operating lease liabilities
11,751

Total operating lease liabilities
$
40,885


As of March 31, 2019, our weighted average remaining lease term and our weighted average discount rate for our operating leases were 1.6 years and 4.02%, respectively.

Our operating lease liabilities with enforceable contract terms that are greater than one year mature as follows:
 
As of March 31, 2019
Remainder of 2019
$
25,505

2020
13,765

2021
1,573

2022
534

2023
517

Thereafter
388

   Total lease payments
42,282

Less imputed interest
1,397

   Total
$
40,885


Note 11 - Asset Retirement Obligations

The table below summarizes the activity for the Company’s ARO:
 
Three Months Ended
 
March 31, 2019
Asset retirement obligations at January 1, 2019
$
14,292

Accretion expense
241

Liabilities incurred
111

Liabilities settled
(618
)
Dispositions
(87
)
Revisions to estimate
21

Asset retirement obligations at end of period
13,960

Less: Current asset retirement obligations
(3,771
)
Long-term asset retirement obligations at March 31, 2019
$
10,189


Certain of the Company’s operating agreements require that assets be restricted for abandonment obligations. Amounts recorded in the consolidated balance sheet at March 31, 2019 as long-term restricted investments were $3,450. 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.


19

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

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, Ward, Reagan and Upton 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, Ward, and Reagan 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.


20


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

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

Should one or more of the risks or uncertainties described above or in our 2018 Annual Report on Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. Any forward-looking statement speaks only as of the date of which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except required by applicable law.


21


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.

22

 
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 79% oil and 21% natural gas for the three months ended March 31, 2019.

Recent Developments

On April 8, 2019, the Company entered into a definitive agreement regarding the sale of certain non-core assets, the Ranger assets, in the Midland Basin for initial cash proceeds of $260 million, excluding customary purchase price adjustments. The agreement also provides for potential contingency payments of up to $60 million based on WTI average annual pricing over a three-year period.

The proceeds from this divestiture will accelerate our debt reduction initiatives and also provide the opportunity to retire our preferred stock, reducing our cash financing costs.

The sale of the Company’s Ranger assets will not significantly alter the relationship between capitalized costs and proved reserves, and as such, all proceeds will be recorded as adjustments to our full cost pool with no gain or loss recognized. We expect the transaction to close in the second quarter of 2019.

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 52% for the three months ended March 31, 2019, compared to the same period of 2018. Production increased to 3,628 MBOE for the three months ended March 31, 2019 from 2,391 MBOE for the three months ended March 31, 2018.

For the three months ended March 31, 2019, we drilled 21 gross (16.4 net) horizontal wells and completed 11 gross (10.1 net) horizontal wells. As of March 31, 2019, we had 21 gross (16.0 net) horizontal wells awaiting completion.

As of March 31, 2019, we had 940 gross (712.9 net) working interest oil wells, three gross (0.1 net) royalty interest oil wells and no natural gas wells. A well is categorized as an oil well or a natural gas well based upon the ratio of oil to natural gas reserves on a BOE basis. However, most of our wells produce both oil and natural gas.


23

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


Results of Operations

The following table sets forth certain operating information with respect to the Company’s oil and natural gas operations for the periods indicated: 
 
 
Three Months Ended March 31,
 
 
2019
 
2018
 
Change
 
% Change
Net production
 
 
 
 
 
 
 
 
Oil (MBbls)
 
2,858

 
1,851

 
1,007

 
54
 %
Natural gas (MMcf)
 
4,619

 
3,240

 
1,379

 
43
 %
   Total (MBOE)
 
3,628

 
2,391

 
1,237

 
52
 %
Average daily production (BOE/d)
 
40,311

 
26,567

 
13,744

 
52
 %
   % oil (BOE basis)
 
79
%
 
77
%
 
  
 
  
Average realized sales price
(excluding impact of settled derivatives)
 
 
 
  
 
  
 
  
   Oil (per Bbl)
 
$
49.37

 
$
62.28

 
$
(12.91
)
 
(21
)%
   Natural gas (per Mcf)
 
2.59

 
3.75

 
(1.16
)
 
(31
)%
   Total (per BOE)
 
42.18

 
53.30

 
(11.12
)
 
(21
)%
Average realized sales price
(including impact of settled derivatives):
 
 
 
 
 
 
 
 
   Oil (per Bbl)
 
$
48.83

 
$
57.47

 
$
(8.64
)
 
(15
)%
   Natural gas (per Mcf)
 
2.86

 
3.89

 
(1.03
)
 
(26
)%
   Total (per BOE)
 
42.11

 
49.76

 
(7.65
)
 
(15
)%
Oil and natural gas revenues
(in thousands)
 
  

 
  

 
  

 
  

   Oil revenue
 
$
141,098

 
$
115,286

 
$
25,812

 
22
 %
   Natural gas revenue
 
11,949

 
12,154

 
(205
)
 
(2
)%
      Total
 
$
153,047

 
$
127,440

 
$
25,607

 
20
 %
Additional per BOE data
 
  

 
 
 
  

 
  

   Sales price (a)
 
$
42.18

 
$
53.30

 
$
(11.12
)
 
(21
)%
      Lease operating expense (b)
 
6.63

 
5.45

 
1.18

 
22
 %
      Production taxes
 
2.98

 
3.54

 
(0.56
)
 
(16
)%
   Operating margin
 
$
32.57

 
$
44.31

 
$
(11.74
)
 
(26
)%
Benchmark prices
 
 
 
 
 
 
 
 
   WTI (per Bbl)
 
$
54.82

 
$
62.91

 
$
(8.09
)
 
(13
)%
   Henry Hub (per Mcf)
 
2.92

 
3.08

 
(0.16
)
 
(5
)%

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



24

 
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 March 31, 2018
 
$
115,286

 
$
12,154

 
$
127,440

   Volume increase
 
62,716

 
5,171

 
67,887

   Price decrease
 
(36,904
)
 
(5,376
)
 
(42,280
)
   Net increase (decrease)
 
25,812

 
(205
)
 
25,607

Revenues for the three months ended March 31, 2019
 
$
141,098

 
$
11,949

 
$
153,047


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 March 31, 2019, oil revenues of $141.1 million increased $25.8 million, or 22%, compared to revenues of $115.3 million for the same period of 2018. The increase was primarily attributable to a 54% increase in production offset by a 21% decrease in the average realized sales price, which fell to $49.37 per Bbl from $62.28 per Bbl.

Natural gas revenue (including NGLs)

For the three months ended March 31, 2019, natural gas revenues of $11.9 million decreased $0.2 million, or 2%, compared to $12.2 million for the same period of 2018. The decrease was primarily attributable to a 31% decrease in the average realized sales price, which fell to $2.59 per Mcf from $3.75 per Mcf. Offsetting the decrease in natural gas revenues was a 43% increase in natural gas volumes.

Operating Expenses
 
 
Three Months Ended March 31,
 
 
 
 
Per
 
 
 
Per
 
Total Change
 
BOE Change
(in thousands, except per unit amounts)
 
2019
 
BOE
 
2018
 
BOE
 
$
 
%
 
$
 
%
Lease operating expenses
 
$
24,067

 
$
6.63

 
$
13,039

 
$
5.45

 
$
11,028

 
85
 %
 
$
1.18

 
22
 %
Production taxes
 
10,813

 
2.98

 
8,463

 
3.54

 
2,350

 
28
 %
 
(0.56
)
 
(16
)%
Depreciation, depletion and amortization
 
59,767

 
16.47

 
35,417

 
14.81

 
24,350

 
69
 %
 
1.66

 
11
 %
General and administrative
 
11,753

 
3.24

 
8,769

 
3.67

 
2,984

 
34
 %
 
(0.43
)
 
(12
)%
Settled share-based awards
 
3,024

 
0.83

 

 

 
3,024

 
100
 %
 
0.83

 
100
 %
Accretion expense
 
241

 
0.07

 
218

 
0.09

 
23

 
11
 %
 
(0.02
)
 
(22
)%
Acquisition expense
 
157

 
0.04

 
548

 
0.23

 
(391
)
 
(71
)%
 
(0.19
)
 
(83
)%

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 March 31, 2019 increased to $24.1 million compared to $13.0 million for the same period of 2018. For the three months ended March 31, 2019, LOE on a per unit basis increased to $6.63 per BOE compared to $5.45 per BOE for the same period of 2018 primarily due to a 52% increase in production related to our continued drilling program and acquisition activities, workovers and participation in non-operated wells.


25

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


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 March 31, 2019 increased 28% to $10.8 million compared to $8.5 million for the same period of 2018, due to an increase in severance taxes based on higher production volumes. Also attributable is the increase in ad valorem taxes due to a higher valuation of our oil and gas properties by the taxing jurisdictions resulting from an increased number of producing wells in the current period, as a result of our horizontal drilling program and acquisition efforts. On a per BOE basis, production taxes for the three months ended March 31, 2019 decreased by 16% compared to the same period of 2018.

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. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to forty years.

For the three months ended March 31, 2019, DD&A increased 69% to $59.8 million compared to $35.4 million for the same period of 2018. For the three months ended March 31, 2019, DD&A on a per unit basis increased to $16.47 per BOE compared to $14.81 per BOE for the same period of 2018. The increase is primarily attributable to higher production levels and an increase in our depreciable base and assumed future development costs related to undeveloped proved reserves relative to our estimated proved reserves as a result of additions made through our horizontal drilling efforts and acquisitions.

General and administrative, net of amounts capitalized (“G&A”). G&A for the three months ended March 31, 2019 increased to $11.8 million compared to $8.8 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. G&A expenses for the periods indicated include the following (in thousands):
 
 
Three Months Ended March 31,
 
 
2019
 
2018
 
$ Change
 
% Change
G&A
 
$
8,364

 
$
6,673

 
$
1,691

 
25
%
Share-based compensation
 
1,500

 
1,105

 
395

 
36
%
Fair value adjustments of cash-settled RSU awards
 
1,889

 
991

 
898

 
91
%
   Total G&A expenses
 
$
11,753

 
$
8,769

 
$
2,984

 
34
%

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

Other Income and Expenses and Preferred Stock Dividends
 
 
Three Months Ended March 31,
(in thousands)
 
2019
 
2018
 
$ Change
 
% Change
Interest expense
 
$
20,582

 
$
10,528

 
$
10,054

 
95
 %
Capitalized interest
 
(19,844
)
 
(10,068
)
 
(9,776
)
 
97
 %
Interest expense, net of capitalized amounts
 
738

 
460

 
278

 
60
 %
(Gain) loss on derivative contracts
 
67,260

 
4,481

 
62,779

 
1,401
 %
Other income
 
(81
)
 
(211
)
 
130

 
(62
)%
   Total other (income) expense
 
$
67,917

 
$
4,730

 
 
 
 
 
 
 
 
 
 
 
 
 
Income tax (benefit) expense