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

FORM 10-Q

Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For The Quarterly Period Ended September 30, 2017
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
(State or Other Jurisdiction of
Incorporation or Organization)
 
64-0844345
(IRS Employer
Identification No.)
 
 
 
200 North Canal Street
Natchez, Mississippi
(Address of Principal Executive Offices)
 
39120
(Zip Code)
601-442-1601
(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 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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post 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 (check one):
Large accelerated filer
Accelerated filer
Non-accelerated filer
(Do not check if smaller reporting company)
 
 
 
 
 
 
 
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 201,836,172 shares of common stock outstanding as of November 1, 2017.




Table of Contents

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

2

Table of Contents

DEFINITIONS

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.
BBtu: billion Btu.
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.
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.
LIBOR:  London Interbank Offered Rate.
LOE:  lease operating expense.
MBbls:  thousand barrels of oil.
MBOE:  thousand BOE.
MMBOE: million 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.
SEC:  United States Securities and Exchange Commission.
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

Table of Contents

Part I.  Financial Information
Item I.  Financial Statements
Callon Petroleum Company
Consolidated Balance Sheets
(in thousands, except par and per share values and share data)
 
September 30, 2017
 
December 31, 2016
ASSETS
Unaudited
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
61,609

 
$
652,993

Accounts receivable
81,973

 
69,783

Fair value of derivatives
3,333

 
103

Other current assets
2,583

 
2,247

Total current assets
149,498

 
725,126

Oil and natural gas properties, full cost accounting method:
 
 
 
Evaluated properties
3,283,985

 
2,754,353

Less accumulated depreciation, depletion, amortization and impairment
(2,026,809
)
 
(1,947,673
)
Net evaluated oil and natural gas properties
1,257,176

 
806,680

Unevaluated properties
1,173,614

 
668,721

Total oil and natural gas properties
2,430,790

 
1,475,401

Other property and equipment, net
18,626

 
14,114

Restricted investments
3,362

 
3,332

Deferred financing costs
5,209

 
3,092

Fair value of derivatives
1,121

 

Acquisition deposit

 
46,138

Prepaid
4,650

 

Other assets, net
827

 
384

Total assets
$
2,614,083

 
$
2,267,587

LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued liabilities
$
147,338

 
$
95,577

Accrued interest
18,375

 
6,057

Cash-settleable restricted stock unit awards
4,158

 
8,919

Asset retirement obligations
1,841

 
2,729

Fair value of derivatives
6,380

 
18,268

Total current liabilities
178,092

 
131,550

Senior secured revolving credit facility

 

6.125% senior unsecured notes due 2024, net of unamortized deferred financing costs
595,115

 
390,219

Asset retirement obligations
3,163

 
3,932

Cash-settleable restricted stock unit awards
2,626

 
8,071

Deferred tax liability
1,158

 
90

Fair value of derivatives
659

 
28

Other long-term liabilities
405

 
295

Total liabilities
781,218

 
534,185

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; 201,827,995 and 201,041,320 shares outstanding, respectively
2,018

 
2,010

Capital in excess of par value
2,179,258

 
2,171,514

Accumulated deficit
(348,426
)
 
(440,137
)
Total stockholders’ equity
1,832,865

 
1,733,402

Total liabilities and stockholders’ equity
$
2,614,083

 
$
2,267,587


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

4

Table of Contents

Callon Petroleum Company
Consolidated Statements of Operations
(Unaudited; in thousands, except per share data)

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
Operating revenues:
 
 
 
 
 
 
 
Oil sales
$
73,349

 
$
49,095

 
$
218,242

 
$
117,093

Natural gas sales
11,265

 
6,832

 
30,019

 
14,677

Total operating revenues
84,614

 
55,927

 
248,261

 
131,770

Operating expenses:
 
 
 
 
 
 
 
Lease operating expenses
11,624

 
9,961

 
36,708

 
24,229

Production taxes
5,444

 
3,478

 
16,168

 
8,153

Depreciation, depletion and amortization
28,525

 
17,303

 
79,172

 
49,318

General and administrative
7,259

 
7,891

 
18,894

 
19,755

Settled share-based awards

 

 
6,351

 

Accretion expense
131

 
187

 
523

 
762

Write-down of oil and natural gas properties

 

 

 
95,788

Acquisition expense
205

 
456

 
3,027

 
2,410

Total operating expenses
53,188

 
39,276

 
160,843

 
200,415

Income (loss) from operations
31,426

 
16,651

 
87,418

 
(68,645
)
Other (income) expenses:
 
 
 
 
 
 
 
Interest expense, net of capitalized amounts
444

 
831

 
1,698

 
10,502

(Gain) loss on derivative contracts
14,162

 
(5,135
)
 
(11,636
)
 
11,281

Other income
(498
)
 
(122
)
 
(1,270
)
 
(299
)
Total other (income) expense
14,108

 
(4,426
)
 
(11,208
)
 
21,484

Income (loss) before income taxes
17,318

 
21,077

 
98,626

 
(90,129
)
Income tax (benefit) expense
237

 
(62
)
 
1,026

 
(62
)
Net income (loss)
17,081

 
21,139

 
97,600

 
(90,067
)
Preferred stock dividends
(1,824
)
 
(1,824
)
 
(5,471
)
 
(5,471
)
Income (loss) available to common stockholders
$
15,257

 
$
19,315

 
$
92,129

 
$
(95,538
)
Income (loss) per common share:
 
 
 
 
 
 
 
Basic
$
0.08

 
$
0.14

 
$
0.46

 
$
(0.85
)
Diluted
$
0.08

 
$
0.14

 
$
0.46

 
$
(0.85
)
Shares used in computing income (loss) per common share:
 
 
 
 
 
 
Basic
201,827

 
136,983

 
201,422

 
112,925

Diluted
202,337

 
137,483

 
201,995

 
112,925


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


5

Table of Contents

Callon Petroleum Company
Consolidated Statements of Cash Flows
(Unaudited; in thousands)
໿
 
Nine Months Ended September 30,
 
2017
 
2016
Cash flows from operating activities:
 
 
 
Net income (loss)
$
97,600

 
$
(90,067
)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
 
 
 
Depreciation, depletion and amortization
80,829

 
50,560

Write-down of oil and natural gas properties

 
95,788

Accretion expense
523

 
762

Amortization of non-cash debt related items
1,695

 
2,371

Deferred income tax (benefit) expense
1,026

 
(62
)
Net (gain) loss on derivatives, net of settlements
(15,608
)
 
27,105

Loss on sale of other property and equipment
62

 

Non-cash expense related to equity share-based awards
7,014

 
1,954

Change in the fair value of liability share-based awards
2,423

 
6,045

Payments to settle asset retirement obligations
(1,831
)
 
(895
)
Changes in current assets and liabilities:
 
 
 
Accounts receivable
(12,148
)
 
(16,444
)
Other current assets
(336
)
 
(251
)
Current liabilities
7,534

 
19,815

Change in other long-term liabilities
121

 
86

Change in long-term prepaid
(4,650
)
 

Change in other assets, net
(1,376
)
 
(1,671
)
Payments to settle vested liability share-based awards
(13,173
)
 
(10,300
)
Net cash provided by operating activities
149,705

 
84,796

Cash flows from investing activities:
 
 
 
Capital expenditures
(267,218
)
 
(122,698
)
Acquisitions
(714,504
)
 
(302,057
)
Acquisition deposit
46,138

 
(32,700
)
Proceeds from sales of mineral interests and equipment

 
22,923

Net cash used in investing activities
(935,584
)
 
(434,532
)
Cash flows from financing activities:
 
 
 
Borrowings on senior secured revolving credit facility

 
217,000

Payments on senior secured revolving credit facility

 
(257,000
)
Issuance of 6.125% senior unsecured notes due 2024
200,000

 

Premium on the issuance of 6.125% senior unsecured notes due 2024
8,250

 

Issuance of common stock

 
722,715

Payment of preferred stock dividends
(5,471
)
 
(5,471
)
Payment of deferred financing costs
(7,166
)
 
(640
)
Tax withholdings related to restricted stock units
(1,118
)
 
(2,207
)
Net cash provided by financing activities
194,495

 
674,397

Net change in cash and cash equivalents
(591,384
)
 
324,661

Balance, beginning of period
652,993

 
1,224

Balance, end of period
$
61,609

 
$
325,885


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

6

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

INDEX TO THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Description of Business and Basis of Presentation
Fair Value Measurements
Acquisitions
Income Taxes
Earnings Per Share
Asset Retirement Obligations
Borrowings
Equity Transactions
Derivative Instruments and Hedging Activities
Other

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, development, exploration and exploitation of unconventional onshore, oil and natural gas reserves in the Permian Basin. The Company’s operations to date have been predominantly focused on the horizontal development of several prospective intervals, including multiple levels of the Wolfcamp formation and the Lower Spraberry shales. Callon has assembled a multi-year inventory of potential horizontal well locations and intends to add to this inventory through delineation drilling of emerging zones on its existing acreage and acquisition of additional locations through working interest acquisitions, leasing programs, acreage purchases, joint ventures and asset swaps. 

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 subsidiaries, namely Callon Offshore Production, Inc. and Mississippi Marketing, Inc.

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, 2016. The balance sheet at December 31, 2016 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, 2017.

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, the results of its operations and its cash flows for the periods indicated. Certain prior year amounts may have been reclassified to conform to current year presentation.

Recently issued accounting policies

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 will replace most of the existing revenue recognition requirements in GAAP when it becomes effective. In August 2015, the FASB issued ASU No. 2015-14, deferring the effective date of ASU 2014-09 by one year. As a result, the standard is effective for annual periods beginning on or after December 31, 2017, including interim periods within that reporting period. The standard can be applied using either the full retrospective approach or a modified retrospective approach at the date of adoption.

The Company has substantially completed its assessment of the adoption of this standard on its revenue-related contracts. The Company currently recognizes revenue under the entitlements method of accounting, and to date, has not identified any contracts that would require a change from the entitlements method. The Company continues to evaluate the impact of the standard’s provisions regarding gross-versus-net presentation. To date, the Company has not identified any material impact that the new standard will have on the Company’s

7

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

Consolidated Financial Statements with the exception of new disclosures. The Company intends to adopt the new standard on January 1, 2018 using the modified retrospective method at the date of adoption.

Recently adopted accounting policies

In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). The standard is intended to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows, and will allow companies to estimate the number of stock awards expected to vest. The guidance in ASU 2016-09 is effective for public entities for annual reporting periods beginning after December 15, 2016, including interim periods therein. The Company adopted this ASU on January 1, 2017 and it did not have a material impact on its financial statements. The Company has elected to no longer estimate forfeitures.

Note 2 - Acquisitions 

Acquisitions were accounted for under the acquisition method of accounting, which involves determining the fair value of the assets acquired and liabilities assumed under the income approach.

2017 acquisitions

On February 13, 2017, the Company completed the acquisition of 29,175 gross (16,688 net) acres in the Delaware Basin, primarily located in Ward and Pecos Counties, Texas from American Resource Development, LLC, for total cash consideration of $646,559, excluding customary purchase price adjustments (the “Ameredev Transaction”). The Company funded the cash purchase price with the net proceeds of an equity offering (see Note 9 for additional information regarding the equity offering). The Company obtained an 82% average working interest in the properties acquired in the Ameredev Transaction. In December 2016, in connection with the execution of the purchase and sale agreement for the Ameredev Transaction, the Company paid a deposit in the amount of $46,138 to a third party escrow agent, which was recorded as Acquisition deposit on the balance sheet as of December 31, 2016. The following table summarizes the estimated acquisition date fair values of the acquisition:
Evaluated oil and natural gas properties
$
137,368

Unevaluated oil and natural gas properties
509,359

Asset retirement obligations
(168
)
Net assets acquired
$
646,559


The preliminary purchase price allocation is 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.

On June 5, 2017, the Company completed the acquisition of 7,031 gross (2,488 net) acres in the Delaware Basin, located near the acreage acquired in the Ameredev Transaction discussed above, for total cash consideration of $52,500, excluding customary purchase price adjustments. The Company funded the cash purchase price with its available cash and proceeds from the issuance of an additional $200,000 of its 6.125% senior notes due 2024 (see Note 4 for additional information regarding the Company’s debt obligations).

2016 acquisitions

On October 20, 2016, the Company completed the acquisition of 6,904 gross (5,952 net) acres in the Midland Basin, primarily located in Howard County, Texas from Plymouth Petroleum, LLC and additional sellers that exercised their “tag-along” sales rights, for total cash consideration of $339,687, excluding customary purchase price adjustments (the “Plymouth Transaction”). The Company funded the cash purchase price with the net proceeds of an equity offering (see Note 9 for additional information regarding the equity offering). The Company obtained an 82% average working interest (62% average net revenue interest) in the properties acquired in the Plymouth Transaction.

On May 26, 2016, the Company completed the acquisition of 17,298 gross (14,089 net) acres in the Midland Basin, primarily located in Howard County, Texas from BSM Energy LP, Crux Energy LP and Zaniah Energy LP, for total cash consideration of $220,000 and 9,333,333 shares of common stock (at an assumed offering price of $11.74 per share, which is the last reported sale price of our common stock on the New York Stock Exchange on that date) for a total purchase price of $329,573, excluding customary purchase price adjustments (the “Big Star Transaction”). The Company acquired an 81% average working interest (61% average net revenue interest) in the properties acquired in the Big Star Transaction.


8

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

Unaudited pro forma financial statements

The following unaudited summary pro forma financial information for the periods presented is for illustrative purposes only and does not purport to represent what the Company’s results of operations would have been if the Ameredev Transaction, Plymouth Transaction and Big Star Transaction had occurred as presented, or to project the Company’s results of operations for any future periods:

Three Months Ended September 30,
 
Nine Months Ended September 30,

2017
(a) 
 
2016
(a) 
 
2017
(a) 
 
2016
(a) 
Revenues
$
84,614

 
 
$
67,544

 
 
$
251,313

 
 
$
168,618

 
Income (loss) from operations
31,426

 
 
20,644

 
 
90,076

 
 
(61,918
)
 
Income (loss) available to common stockholders
15,257

 
 
23,322

 
 
94,786

 
 
(80,690
)
 

 

 
 
 

 
 
 

 
 
 

 
Net income (loss) per common share:
 

 
 
 

 
 
 

 
 
 

 
Basic
$
0.08

 
 
$
0.13

 
 
$
0.47

 
 
$
(0.53
)
 
Diluted
$
0.08

 
 
$
0.13

 
 
$
0.47

 
 
$
(0.53
)
 

(a)
The pro forma financial information was prepared assuming the Ameredev Transaction occurred as of January 1, 2016 and the Plymouth Transaction and Big Star Transaction occurred as of January 1, 2015.

The pro forma adjustments are based on available information and certain assumptions that management believes are reasonable, including revenue, lease operating expenses, production taxes, depreciation, depletion and amortization expense, accretion expense, interest expense and capitalized interest.

The properties associated with the Ameredev Transaction, Plymouth Transaction and Big Star Transaction have been commingled with our existing properties and it is impractical to provide the stand-alone operational results related to these properties.

Note 3 - Earnings Per Share

The following table sets forth the computation of basic and diluted earnings per share:
(share amounts in thousands)
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
Net income (loss)
$
17,081

 
$
21,139

 
$
97,600

 
$
(90,067
)
Preferred stock dividends
(1,824
)
 
(1,824
)
 
(5,471
)
 
(5,471
)
Income (loss) available to common stockholders
$
15,257

 
$
19,315

 
$
92,129

 
$
(95,538
)

 
 
 
 
 
 
 
Weighted average shares outstanding
201,827

 
136,983

 
201,422

 
112,925

Dilutive impact of restricted stock
510

 
500

 
573

 

Weighted average shares outstanding for diluted income (loss) per share
202,337

 
137,483

 
201,995

 
112,925


 
 
 
 
 
 
 
Basic income (loss) per share
$
0.08

 
$
0.14

 
$
0.46

 
$
(0.85
)
Diluted income (loss) per share
$
0.08

 
$
0.14

 
$
0.46

 
$
(0.85
)

 
 
 
 
 
 
 
Stock options (a)

 
15

 

 
15

Restricted stock (a)
51

 
25

 
51

 
25


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


9

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

Note 4 - Borrowings

The Company’s borrowings consisted of the following at:໿
 
September 30, 2017
 
December 31, 2016
Principal components:
 
 
 
Senior secured revolving credit facility
$

 
$

6.125% senior unsecured notes due 2024
600,000

 
400,000

Total principal outstanding
600,000

 
400,000

Premium on 6.125% senior unsecured notes due 2024, net of accumulated amortization
7,875

 

Unamortized deferred financing costs
(12,760
)
 
(9,781
)
Total carrying value of borrowings
$
595,115

 
$
390,219


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

On May 31, 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. Concurrent with the execution of the Sixth Amended and Restated Credit Agreement, the Credit Facility’s borrowing base increased to $650,000, but the Company elected an aggregate commitment amount of $500,000. As of September 30, 2017, the Company continued to maintain the Credit Facility’s borrowing base at $500,000.

As of September 30, 2017, there was no balance outstanding on the Credit Facility. For the quarter ended September 30, 2017, the Credit Facility had a weighted-average interest rate of 3.23%, calculated as the LIBOR plus a tiered rate ranging from 2.00% to 3.00%, which is determined based on utilization of the facility. In addition, the Credit Facility carries a commitment fee of 0.375% per annum, payable quarterly, on the unused portion of the borrowing base.

6.125% senior 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 used the proceeds, in part, to fund an acquisition completed on June 5, 2017 (discussed further in Note 2) and for general corporate purposes.

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.


10

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

Restrictive covenants

The Company’s Credit Facility and the indenture governing our 6.125% Senior Notes contain various covenants including restrictions on additional indebtedness, payment of cash dividends and maintenance of certain financial ratios. The Company was in compliance with these covenants at September 30, 2017.

Note 5 - 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, put and call options and similar derivative financial instruments 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 6 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 6 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. Cash settlements are also recorded as 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: 
 
 
Balance Sheet Presentation
 
Asset Fair Value
 
Liability Fair Value
 
Net Derivative Fair Value
Commodity
 
Classification
 
Line Description
 
9/30/2017
 
12/31/2016
 
9/30/2017
 
12/31/2016
 
9/30/2017
 
12/31/2016
Natural gas
 
Current
 
Fair value of derivatives
 
$
431

 
$

 
$

 
$
(593
)
 
$
431

 
$
(593
)
Oil
 
Current
 
Fair value of derivatives
 
2,902

 
103

 
(6,380
)
 
(17,675
)
 
(3,478
)
 
(17,572
)
Oil
 
Non-current
 
Fair value of derivatives
 
1,121

 

 
(659
)
 
(28
)
 
462

 
(28
)
 
 
Totals
 
 
 
$
4,454

 
$
103

 
$
(7,039
)
 
$
(18,296
)
 
$
(2,585
)
 
$
(18,193
)

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:

11

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

 
September 30, 2017
 
Presented without
 
 
 
As Presented with
 
Effects of Netting
 
Effects of Netting
 
Effects of Netting
Current assets: Fair value of derivatives
$
5,441

 
$
(2,108
)
 
$
3,333

Long-term assets: Fair value of derivatives
1,388

 
(267
)
 
1,121


 
 
 
 
 
Current liabilities: Fair value of derivatives
$
(8,488
)
 
$
2,108

 
$
(6,380
)
Long-term liabilities: Fair value of derivatives
(926
)
 
267

 
(659
)

 
December 31, 2016
 
Presented without
 
 
 
As Presented with
 
Effects of Netting
 
Effects of Netting
 
Effects of Netting
Current assets: Fair value of derivatives
$
1,836

 
$
(1,733
)
 
$
103

 
 
 
 
 
 
Current liabilities: Fair value of derivatives
$
(20,001
)
 
$
1,733

 
$
(18,268
)
Long-term liabilities: Fair value of derivatives
(28
)
 

 
(28
)

For the periods indicated, the Company recorded the following related to its derivatives in the consolidated statement of operations as gain or loss on derivative contracts:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
Oil derivatives
 
 
 
 
 
 
 
Net gain (loss) on settlements
$
(1,373
)
 
$
4,252

 
$
(4,213
)
 
$
15,467

Net gain (loss) on fair value adjustments
(12,811
)
 
699

 
14,584

 
(26,904
)
Total gain (loss) on oil derivatives
$
(14,184
)
 
$
4,951

 
$
10,371

 
$
(11,437
)
Natural gas derivatives
 
 
 
 
 
 
 
Net gain (loss) on settlements
$
159

 
$
(161
)
 
$
241

 
$
357

Net gain (loss) on fair value adjustments
(137
)
 
345

 
1,024

 
(201
)
Total gain on natural gas derivatives
$
22

 
$
184

 
$
1,265

 
$
156

 
 
 
 
 
 
 
 
Total gain (loss) on oil & natural gas derivatives
$
(14,162
)
 
$
5,135

 
$
11,636

 
$
(11,281
)


12

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

Derivative positions

Listed in the tables below are the outstanding oil and natural gas derivative contracts as of September 30, 2017:  
 
For the Remainder of
 
For the Full Year of
Oil contracts (WTI)
2017
 
2018
Swap contracts combined with short puts (enhanced swaps)
 
 
 
Total volume (MBbls)
184

 

Weighted average price per Bbl
 
 
 
Swap
$
44.50

 
$

Short put option
$
30.00

 
$

Swap contracts
 
 
 
Total volume (MBbls)
184

 
1,460

Weighted average price per Bbl
$
45.74

 
$
50.93

Deferred premium put spread option
 
 
 
Total volume (MBbls)
253

 

Premium per Bbl
$
2.45

 
$

Weighted average price per Bbl
 
 
 
Long put option
$
50.00

 
$

Short put option
$
40.00

 
$

Collar contracts (two-way collars)
 
 
 
Total volume (MBbls)
340

 

Weighted average price per Bbl
 
 
 
Ceiling (short call)
$
58.19

 
$

Floor (long put)
$
47.50

 
$

Call option contracts
 
 
 
Total volume (MBbls)
169

 

   Premium per Bbl
$
1.82

 
$

Weighted average price per Bbl
 
 
 
Short call strike price (a)
$
50.00

 
$

     Long call strike price (a)
$
50.00

 
$

Collar contracts combined with short puts (three-way collars)
 
 
 
Total volume (MBbls)

 
3,468

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

 
$
60.86

Floor (long put option)
$

 
$
48.95

Short put option
$

 
$
39.21


(a)
Offsetting contracts.

 
For the Remainder of
 
For the Full Year of
Oil contracts (Midland basis differential)
2017
 
2018
Swap contracts
 
 
 
Volume (MBbls)
552

 
4,563

Weighted average price per Bbl
$
(0.52
)
 
$
(0.98
)


13

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

 
For the Remainder of
 
For the Full Year of
Natural gas contracts
2017
 
2018
Collar contracts combined with short puts (Henry Hub, three-way collars)
 
 
 
Total volume (BBtu)
368

 

Weighted average price per MMBtu
 
 
 
Ceiling (short call option)
$
3.71

 
$

Floor (long put option)
$
3.00

 
$

Short put option
$
2.50

 
$

Collar contracts (Henry Hub, two-way collars)
 
 
 
Total volume (BBtu)
856

 
720

Weighted average price per MMBtu
 
 
 
Ceiling (short call option)
$
3.77

 
$
3.84

Floor (long put option)
$
3.23

 
$
3.40

Swap contracts
 

 
 

Total volume (BBtu)
124

 

Weighted average price per MMBtu
$
3.39

 
$


Subsequent event

The following derivative contracts were executed subsequent to September 30, 2017:໿
 
For the Remainder of
 
For the Full Year of
Oil contracts (Midland basis differential)
2017
 
2018
Swap contracts
 
 
 
Volume (MBbls)

 
546

Weighted average price per Bbl
$

 
$
(0.23
)

 
 
 
 
For the Remainder of
 
For the Full Year of
Oil contracts (WTI)
2017
 
2018
Swap contracts
 
 
 
Volume (MBbls)

 
365

Weighted average price per Bbl
$

 
$
53.40


Note 6 - 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.

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

September 30, 2017
 
December 31, 2016

Carrying Value
 
Fair Value
 
Carrying Value
 
Fair Value
Credit Facility (a)
$

 
$

 
$

 
$

6.125% Senior Notes (b)
595,115

 
621,000

 
390,219

 
412,000

Total
$
595,115

 
$
621,000

 
$
390,219

 
$
412,000


໿
(a)
Floating-rate debt.
(b)
The fair value was based upon Level 2 inputs. See Note 4 for additional information about the Company’s 6.125% Senior Notes.


14

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

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 5 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:
September 30, 2017
Classification
 
Level 1
 
Level 2
 
Level 3
 
Total
Assets
 
 
 
 
 
 
 
 
 
Derivative financial instruments
Fair value of derivatives
 
$

 
$
4,454

 
$

 
$
4,454

Liabilities
 
 
 
 
 
 
 
 
 
Derivative financial instruments
Fair value of derivatives
 

 
(7,039
)
 

 
(7,039
)
Total net liabilities
 
 
$

 
$
(2,585
)
 
$

 
$
(2,585
)

 
 
 
 
 
 
 
 
 
December 31, 2016
Classification
 
Level 1
 
Level 2
 
Level 3
 
Total
Assets
 
 
 
 
 
 
 
 
 
Derivative financial instruments
Fair value of derivatives
 
$

 
$
103

 
$

 
$
103

Liabilities
 
 
 
 
 
 
 
 
 
Derivative financial instruments
Fair value of derivatives
 

 
(18,296
)
 

 
(18,296
)
Total net liabilities
 
 
$

 
$
(18,193
)
 
$

 
$
(18,193
)

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 2 and Level 3 inputs.

Note 7 - Income Taxes

The Company typically provides for income taxes at a statutory rate of 35% adjusted for permanent differences expected to be realized, which primarily relate to non-deductible executive compensation expenses and state income taxes. As a result of the write-down of oil and natural gas properties in the latter part of 2015 and the first half of 2016, the Company incurred a cumulative three year loss. Because of the impact the cumulative loss has on the determination of the recoverability of deferred tax assets through future earnings, the Company assessed the ability to realize its deferred tax assets based on the future reversals of existing deferred tax liabilities. Accordingly, the Company established a full valuation allowance for the net U.S. federal deferred tax asset in 2015. In subsequent periods where the Company has recorded pre-tax income, it has reversed a portion of the U.S. federal valuation allowance, net of discrete items, to the extent necessary to offset U.S. federal income tax expense on pre-tax income recorded for the period. Income tax expense recorded in this period relates to deferred State of Texas gross margin tax. The valuation allowance was $109,815 as of September 30, 2017

The Company recently adopted a new accounting standard that simplified the accounting for stock-based compensation. As a result, the Company recorded a cumulative-effect adjustment to retained earnings as of January 1, 2017 for all windfall tax benefits that were not previously recognized because the related tax deduction had not reduced current taxes payable. Due to the Company’s valuation allowance position, a cumulative-effect adjustment was recorded to retained earnings as of January 1, 2017, and therefore, the net effect of this new accounting standard was zero. See Note 1 for additional information about this new accounting standard.


15

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

 
Note 8 - Asset Retirement Obligations

The table below summarizes the activity for the Company’s asset retirement obligations:

For The Nine Months Ended

September 30, 2017
Asset retirement obligations at January 1, 2017
$
6,661

Accretion expense
523

Liabilities incurred
224

Liabilities settled
(227
)
Revisions to estimate (a)
(2,177
)
Asset retirement obligations at end of period
5,004

Less: Current asset retirement obligations
(1,841
)
Long-term asset retirement obligations at September 30, 2017
$
3,163


Certain of the Company’s operating agreements require that assets be restricted for abandonment obligations. Amounts recorded in the Consolidated Balance Sheets at September 30, 2017 as long-term restricted investments were $3,362. These assets, which primarily include short-term U.S. Government securities, are held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s oil and natural gas properties.

Note 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 our 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 our Board of Directors. Preferred Stock dividends were $1,824 and $1,824 for the three months ended September 30, 2017 and 2016, respectively, and $5,471 and $5,471 for the nine months ended September 30, 2017 and 2016, respectively.

The Preferred Stock has no stated maturity and is not subject to any sinking fund or other mandatory redemption. On or after May 30, 2018, the Company may, at its option, redeem the Preferred Stock, in whole or in part, 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 September 30, 2017, and the Company did not exercise its right to redeem the Preferred Stock, using the closing price of $11.24 as the value of a share of common stock, each share of Preferred Stock would be convertible into approximately 4.4 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.

On February 4, 2016, the Company exchanged a total of 120,000 shares of Preferred Stock for 719,000 shares of common stock. As of September 30, 2017, the Company had 1,458,948 shares of its Preferred Stock issued and outstanding.

Common stock  

On December 19, 2016, the Company completed an underwritten public offering of 40,000,000 shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering expenses) of approximately $634,934. Proceeds from the offering were used to substantially fund the Ameredev Transaction, described in Note 2.

On September 6, 2016, the Company completed an underwritten public offering of 29,900,000 shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering expenses) of approximately $421,864. Proceeds from the offering were used to substantially fund the Plymouth Transaction, described in Note 2


16

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

On May 26, 2016, the Company issued 9,333,333 shares of common stock to partially fund the Big Star Transaction, described in Note 2, at an assumed offering price of $11.74 per share, which is the last reported sale price of our common stock on the New York Stock Exchange on that date.

On April 25, 2016, the Company completed an underwritten public offering of 25,300,000 shares of its common stock for total net proceeds (after the underwriter’s discounts and commissions and estimated offering expenses) of approximately $205,869. Proceeds from the offering were used to fund the Big Star Transaction, described in Note 2, and other working interest acquisitions.

On March 9, 2016, the Company completed an underwritten public offering of 15,250,000 shares of its common stock for total net proceeds (after the underwriting discounts and estimated offering costs) of approximately $94,948. Proceeds from the offering were used to pay down the balance on the Company’s Credit Facility and for general corporate purposes.

Note 10 - Other

Operating leases

As of September 30, 2017 the Company had contracts for four horizontal drilling rigs (the “Cactus 1 Rig”, “Cactus 2 Rig”, “Cactus 3 Rig”, and “Independence Rig”). The contract terms, as amended in July 2017, of the Cactus 1 Rig and Cactus 2 Rig will end in January 2020 and February 2021, respectively. The contract terms, as amended in July 2017, of the Cactus 3 Rig that commenced drilling in mid-January 2017, will end in July 2018. Effective April 2017, the Company entered into a contract for the Independence Rig, which commenced drilling in July 2017. The contract terms of the Independence Rig will end in July 2019. The rig lease agreements include early termination provisions that obligate the Company to pay reduced minimum rentals for the remaining term of the agreement. These payments would be reduced assuming the lessor is able to re-charter the rig and staffing personnel to another lessee.

17

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

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 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 production and operating costs;
commodity price risk management activities and the impact on our average realized prices;
business strategies and plans of management;
our ability to efficiently integrate recently completed 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;
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;
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 endangered species;
any increase in severance or similar taxes;
litigation relating to hydraulic fracturing, the climate and over-the-counter derivatives;
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;
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, 2016 (the  “2016 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 herein or in our 2016 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. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages.

All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.


18

Callon Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results


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 2016 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 report on Form 10-Q.

We are an independent oil and natural gas company established in 1950. We are focused on the acquisition, development, exploration and exploitation 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. We have historically been focused on the Midland Basin and recently entered the Delaware Basin through an acquisition completed in February 2017. 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 predominantly focused on the horizontal development of several prospective intervals, including multiple levels of the Wolfcamp formation and the Lower Spraberry shales. We have assembled a multi-year inventory of potential horizontal well locations and intend to add to this inventory through delineation drilling of emerging zones on our existing acreage and acquisition of additional locations through working interest acquisitions, leasing programs, acreage purchases, joint ventures and asset swaps. Our production was approximately 78% oil and 22% natural gas for the nine months ended September 30, 2017. On September 30, 2017, our net acreage position in the Permian Basin was approximately 58,336 net acres. See Note 2 in the Footnotes to the Financial Statements for additional information about the Company’s acquisitions.


Operational Highlights

All of our producing properties are located in the Permian Basin. As a result of our acquisition and horizontal development efforts, our production grew 36% and 53% for the three and nine months ended September 30, 2017, respectively, compared to the same periods of 2016. Production increased to 2,074 MBOE for the three months ended September 30, 2017 from 1,527 MBOE for the three months ended September 30, 2016 and increased to 5,934 MBOE for the nine months ended September 30, 2017 from 3,884 MBOE for the nine months ended September 30, 2016.

For the three months ended September 30, 2017, we drilled 13 gross (10.3 net) horizontal wells and completed 15 gross (13.2 net) horizontal wells. For the nine months ended September 30, 2017 we drilled 36 gross (28.9 net) horizontal wells and completed 34 gross (27.7 net) horizontal wells. As of September 30, 2017, we had 9 gross (6.4 net) horizontal wells awaiting completion.

As of September 30, 2017, we had 535 gross (418.1 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.

Liquidity and Capital Resources

Historically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions, the sale of debt and equity securities, and asset dispositions. Our primary uses of capital have been for the acquisition, development, exploration and exploitation of oil and natural gas properties, in addition to refinancing of debt instruments. We continue to evaluate other sources of capital to complement our cash flows from operations as we pursue our long-term growth plans. As of September 30, 2017, there was no balance outstanding on the Credit Facility, which has a borrowing base of $650 million with a current elected commitment of $500 million. For the nine months ended September 30, 2017, cash and cash equivalents decreased $264.3 million to $61.6 million compared to $325.9 million at September 30, 2016.  

Liquidity and cash flow
 
 
Nine Months Ended September 30,
(in millions)
 
2017
 
2016
Net cash provided by operating activities
 
$
149.7

 
$
84.8

Net cash used in investing activities
 
(935.6
)
 
(434.5
)
Net cash provided by financing activities
 
194.5

 
674.4

   Net change in cash and cash equivalents
 
$
(591.4
)
 
$
324.7


19

Callon Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results



Operating activities. For the nine months ended September 30, 2017, net cash provided by operating activities was $149.7 million compared to net cash provided by operating activities of $84.8 million for the same period in 2016. The change was predominantly attributable to the following:

An increase in revenue;
A decrease on settlements of derivative contracts;
An increase in certain operating expenses related to acquired properties;  
An increase in payments in cash-settled restricted stock unit (“RSU”) awards; and
A change related to the timing of working capital payments and receipts.

Production, realized prices, and operating expenses are discussed below in Results of Operations. See Notes 4, 5 and 6 in the Footnotes to the Financial Statements for additional information on our debt and a reconciliation of the components of the Company’s derivative contracts and disclosures related to derivative instruments including their composition and valuation. 

Investing activities. For the nine months ended September 30, 2017, net cash used in investing activities was $935.6 million compared to $434.5 million for the same period in 2016. The change was predominantly attributable to the following:

A  $141.7 million increase in operational expenditures due to the transition from a two-rig to a three-rig program in January 2017 and from a three-rig to a four-rig program in July 2017; and
A $333.6 million increase attributable to acquisition activity. See Note 2 in the Footnotes to the Financial Statements for additional information on the Company’s acquisitions.

Our investing activities, on a cash basis, include the following for the periods indicated (in millions):
 
 
Nine Months Ended September 30,
 
 
2017
 
2016
 
$ Change
Operational expenditures
 
$
232.2

 
$
90.5

 
$
141.7

Seismic, leasehold and other
 
11.4

 
10.0

 
1.4

Capitalized general and administrative costs
 
11.9

 
9.0

 
2.9

Capitalized interest
 
11.7

 
13.2

 
(1.4
)
   Total capital expenditures(a)
 
267.2

 
122.7

 
144.5

 
 
 
 
 
 
 
Acquisitions
 
714.5

 
302.1

 
412.4

Acquisition deposits
 
(46.1
)
 
32.7

 
(78.8
)
Proceeds from the sale of mineral interest and equipment
 

 
(22.9
)
 
22.9

   Total investing activities
 
$
935.6

 
$
434.5

 
$
501.1


(a)
On an accrual (GAAP) basis, which is the methodology used for establishing our annual capital budget, operational expenditures for the nine months ended September 30, 2017 were $277.0 million. Inclusive of capitalized general and administrative and interest costs, total capital expenditures for the nine months ended September 30, 2017 were $326.5 million.

General and administrative expenses and capitalized interest are discussed below in Results of Operations. See Note 2 in the Footnotes to the Financial Statements for additional information on acquisitions.

Financing activities. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our Credit Facility, term debt and equity offerings. For the nine months ended September 30, 2017, net cash provided by financing activities was $194.5 million compared to $674.4 million for the same period of 2016. The change was predominantly attributable to the following:

A $201.7 million increase in borrowings on fixed-rate debt, resulting from the issuance of $200 million of 6.125% senior unsecured notes due 2024, including a premium issue price of 104.125% and net of payments of deferred financing costs
We had no issuance of common stock during the nine months ended September 30, 2017, a change of $722.7 million compared to the same period of 2016 


20

Callon Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results


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

Nine Months Ended September 30, 2017

2017
 
2016
 
$ Change
Net borrowings on senior secured revolving credit facility
$

 
$
(40.0
)
 
$
40.0

Issuance of 6.125% senior unsecured notes due 2024
200.0

 

 
200.0

Premium on the issuance of 6.125% senior unsecured notes due 2024
8.3

 

 
8.3

Issuance of common stock

 
722.7

 
(722.7
)
Payment of preferred stock dividends
(5.5
)
 
(5.5
)
 

Payment of deferred financing costs
(7.2
)
 
(0.6
)
 
(6.6
)
Tax withholdings related to restricted stock units
(1.1
)
 
(2.2
)
 
1.1

Net cash provided by financing activities
$
194.5

 
$
674.4

 
$
(479.9
)

See Notes 4 and 9 in the Footnotes to the Financial Statements for additional information on our debt and equity offerings.

Capital Plan and Year to Date 2017 Summary

Our operational capital budget for 2017 was established at $350 million on an accrual, or GAAP, basis, inclusive of a transition from a three-rig program that commenced in January 2017 to a four-rig program in July 2017 that includes horizontal development activity at our recent Delaware Basin acquisition (see Note 2 in the Footnotes to the Financial Statements for information on this acquisition).

In addition to the operational capital budget, which includes well costs, facilities and infrastructure capital, and surface land purchases, we budgeted an estimated $40 to $45 million for capitalized general and administrative expenses and capitalized interest expenses, both on an accrual, or GAAP, basis.

Operational capital expenditures on an accrual basis were $277.0 million for the nine months ended September 30, 2017. In addition to the operational capital expenditures, $14.0 million of capitalized general and administrative and $24.1 million of capitalized interest expenses were accrued in the nine months ended September 30, 2017. Based on current activity levels and service cost expectations, for full-year 2017 we estimate operational capital expenditures of approximately $375 million, net of the monetization of certain infrastructure assets, including natural gas gathering lines and saltwater disposal facilities.

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


21

Callon Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results


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 September 30,
 
 
2017
 
2016
 
Change
 
% Change
Net production:
 
 
 
 
 
 
 
 
Oil (MBbls)
 
1,591

 
1,153

 
438

 
38
 %
Natural gas (MMcf)
 
2,900

 
2,244

 
656

 
29
 %
   Total (MBOE)
 
2,074

 
1,527

 
547

 
36
 %
Average daily production (BOE/d)
 
22,543

 
16,598

 
5,945

 
36
 %
   % oil (BOE basis)
 
77
%
 
76
%
 
  
 
  
Average realized sales price:
 
 
 
  
 
  
 
  
   Oil (Bbl) (excluding impact of cash settled derivatives)
 
$
46.10

 
$
42.58

 
$
3.52

 
8
 %
   Oil (Bbl) (including impact of cash settled derivatives)
 
45.24

 
46.27

 
(1.03
)
 
(2
)%
   Natural gas (Mcf) (excluding impact of cash settled derivatives)
 
$
3.88

 
$
3.04

 
$
0.84

 
28
 %
   Natural gas (Mcf) (including impact of cash settled derivatives)
 
3.94

 
2.97

 
0.97

 
33
 %
   Total (BOE) (excluding impact of cash settled derivatives)
 
$
40.80

 
$
36.63

 
$
4.17

 
11
 %
   Total (BOE) (including impact of cash settled derivatives)
 
40.21

 
39.30

 
0.91

 
2
 %
Oil and natural gas revenues (in thousands):
 
  
 
  
 
  
 
  
   Oil revenue
 
$
73,349

 
$
49,095

 
$
24,254

 
49
 %
   Natural gas revenue
 
11,265

 
6,832

 
4,433

 
65
 %
      Total
 
$
84,614

 
$
55,927

 
$
28,687

 
51
 %
Additional per BOE data:
 
  
 
 
 
  
 
  
   Sales price (excluding impact of cash settled derivatives)
 
$
40.80

 
$
36.63

 
$
4.17

 
11
 %
      Lease operating expense (excluding gathering and treating expense)
 
5.08

 
6.16

 
(1.08
)
 
(18
)%
      Gathering and treating expense
 
0.52

 
0.36

 
0.16

 
44
 %
      Production taxes
 
2.62

 
2.28

 
0.34

 
15
 %
   Operating margin
 
$
32.58

 
$
27.83

 
$
4.75

 
17
 %

 
 
Nine Months Ended September 30,
 
 
2017
 
2016
 
Change
 
% Change
Net production:
 
 
 
 
 
 
 
 
Oil (MBbls)
 
4,621

 
2,993

 
1,628

 
54
 %
Natural gas (MMcf)
 
7,878

 
5,345

 
2,533

 
47
 %
   Total (MBOE)
 
5,934

 
3,884

 
2,050

 
53
 %
Average daily production (BOE/d)
 
21,736

 
14,175

 
7,561

 
53
 %
   % oil (BOE basis)
 
78
%
 
77
%
 
  
 
  
Average realized sales price:
 
 
 
  
 
  
 
  
   Oil (Bbl) (excluding impact of cash settled derivatives)
 
$
47.23

 
$
39.12

 
$
8.11

 
21
 %
   Oil (Bbl) (including impact of cash settled derivatives)
 
46.32

 
44.29

 
2.03

 
5
 %
   Natural gas (Mcf) (excluding impact of cash settled derivatives)
 
$
3.81

 
$
2.75

 
$
1.06

 
39
 %
   Natural gas (Mcf) (including impact of cash settled derivatives)
 
3.84

 
2.81

 
1.03

 
37
 %
   Total (BOE) (excluding impact of cash settled derivatives)
 
$
41.84

 
$
33.93

 
$
7.91

 
23
 %
   Total (BOE) (including impact of cash settled derivatives)
 
41.17

 
38.00

 
3.17

 
8
 %
Oil and natural gas revenues (in thousands):
 
  
 
  
 
  
 
  
   Oil revenue
 
$
218,242

 
$
117,093

 
$
101,149

 
86
 %
   Natural gas revenue
 
30,019

 
14,677

 
15,342

 
105
 %
      Total
 
$
248,261

 
$
131,770

 
$
116,491

 
88
 %
Additional per BOE data:
 
  
 
 
 
  
 
  
   Sales price (excluding impact of cash settled derivatives)
 
$
41.84

 
$
33.93

 
$
7.91

 
23
 %
      Lease operating expense (excluding gathering and treating expense)
 
5.72

 
5.96

 
(0.24
)
 
(4
)%
      Gathering and treating expense
 
0.47

 
0.28

 
0.19

 
68
 %
      Production taxes
 
2.72

 
2.10

 
0.62

 
30
 %
   Operating margin
 
$
32.93

 
$
25.59

 
$
7.34

 
29
 %


22

Callon Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results


Revenues

The following table reconciles the change in oil, natural gas and total revenue for the respective periods presented by reflecting the effect of changes in volume and in the underlying commodity prices.
(in thousands)
 
Oil
 
Natural Gas
 
Total
Revenues for the three months ended September 30, 2016
 
$
49,095

 
$
6,832

 
$
55,927

Volume increase
 
18,650

 
1,994

 
20,644

Price increase
 
5,604

 
2,439

 
8,043

Net increase
 
24,254

 
4,433

 
28,687

Revenues for the three months ended September 30, 2017
 
$
73,349

 
$
11,265

 
$
84,614

 
 
 
 
 
 
 
(in thousands)
 
Oil
 
Natural Gas
 
Total
Revenues for the nine months ended September 30, 2016
 
$
117,093

 
$
14,677

 
$
131,770

Volume increase
 
63,687

 
6,966

 
70,653

Price increase
 
37,462

 
8,376

 
45,838

Net increase
 
101,149

 
15,342

 
116,491

Revenues for the nine months ended September 30, 2017
 
$
218,242

 
$
30,019

 
$
248,261


Commodity prices

The prices for oil and natural gas can be 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.

For the three and nine months ended September 30, 2017, the average NYMEX price for a barrel of oil was $48.20 and $49.36 per Bbl compared to $44.94 and $41.47 per Bbl for the same periods of 2016, respectively. The NYMEX price for a barrel of oil for the three and nine months ended September 30, 2017 ranged from a low of $44.23 per Bbl to a high of $47.29 per Bbl and a low of $42.53 per Bbl to a high of $54.45 Bbl, respectively.

For the three and nine months ended September 30, 2017, the average NYMEX price for natural gas was $3.00 and $3.17 per MMBtu compared to $2.81 and $2.29 per MMBtu for the same periods of 2016. The NYMEX price for natural gas for the three and nine months ended September 30, 2017 ranged from a low of $2.77 per MMBtu to a high of $3.15 per MMBtu and a low of $2.56 per MMBtu to a high of $3.42 MMBtu, respectively.

໿
Oil revenue 

For the quarter ended September 30, 2017, oil revenues of $73.3 million increased $24.2 million, or 49%, compared to revenues of $49.1 million for the same period of 2016. The increase in oil revenue was primarily attributable to a 38% increase in production and an 8% increase in the average realized sales price, which rose to $46.10 per Bbl in the third quarter of 2017 from $42.58 per Bbl in the third quarter of 2016. The increase in production was attributable to 633 MBbls from wells placed on production as a result of our horizontal drilling program and 241 MBbls from producing wells added from our acquired properties. Offsetting these increases were normal and expected declines from our existing wells.  

For the nine months ended September 30, 2017, oil revenues of $218.2 million increased $101.1 million, or 86%, compared to revenues of $117.1 million for the same period of 2016. The increase in oil revenue was primarily attributable to a 54% increase in production and a 21% increase in the average realized sales price, which rose to $47.23 per Bbl for the nine months ended September 30, 2017 from $39.12 per Bbl for the same period of 2016. The increase in production was comprised of 1,612 MBbls attributable to wells placed on production as a result of our horizontal drilling program and 669 MBbls attributable to producing wells added from our acquired properties. Offsetting these increases were normal and expected declines from our existing wells.

See Note 2 in the Footnotes to the Financial Statements for additional information regarding the Company’s acquisitions.

23

Callon Petroleum Company
Management’s Discussion and Analysis of Financial Condition and Results



Natural gas revenue (including NGLs)

Natural gas revenues of $11.3 million increased $4.4 million, or 66%, during the three months ended September 30, 2017, compared to $6.8 million for the same period of 2016. The increase primarily relates to a 29% increase in natural gas volumes and a 28% increase in the average realized sales price, which rose to $3.88 per Mcf from $3.04 per Mcf, reflecting both natural gas and natural gas liquids prices. The increase in production was comprised of 735 MMcf attributable to wells placed on production as a result of our horizontal drilling program and 287 MMcf attributable to producing wells added from our acquired properties. Offsetting these increases were normal expected declines from our existing wells.

Natural gas revenues of $30.0 million increased $15.3 million, or 105%, during the nine months ended September 30, 2017, compared to $14.7 million for the same period of 2016. The increase primarily relates to a 47% increase in natural gas volumes and a 39% increase in the average realized sales price, which rose to $3.81 per Mcf from $2.75 per Mcf, reflecting both natural gas and natural gas liquids prices. The increase in production was comprised of 1,785 MMcf attributable to wells placed on production as a result of our horizontal drilling program and 806 MMcf attributable to producing wells added from our acquired properties. Offsetting these increases were normal expected declines from our existing wells.

See Note 2 in the Footnotes to the Financial Statements for additional information regarding the Company’s acquisitions.

Operating Expenses
(in thousands, except per unit amounts)
 
Three Months Ended September 30,
 
 
 
 
Per
 
 
 
Per
 
Total Change
 
BOE Change
 
 
2017
 
BOE
 
2016
 
BOE
 
$
 
%
 
$
 
%
Lease operating expenses
 
$
11,624

 
$
5.60

 
$
9,961

 
$
6.52

 
$
1,663

 
17