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 March 31, 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  201,061,366  shares of common stock outstanding as of April 28, 2017.



 


 

 

Table of Contents





 

Part I. Financial Information

 



 

Item 1. Financial Statements (Unaudited)

 



 

Consolidated Balance Sheets 

4



 

Consolidated Statements of Operations

5



 

Consolidated Statements of Cash Flows

6



 

Notes to Consolidated Financial Statements

7



 

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

18



 

Item 3.  Quantitative and Qualitative Disclosures about Market Risk

28



 

Item 4.  Controls and Procedures

29



 

Part II.  Other Information

 



 

Item 1.  Legal Proceedings

30



 

Item 1A.  Risk Factors

30



 

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

30



 

Item 3.  Defaults Upon Senior Securities

30



 

Item 4.  Mine Safety Disclosures

30



 

Item 5.  Other Information

30



 

Item 6.  Exhibits

31



 

 

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.

·

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.

·

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)



 

 

 

 

 

 

 

 

 

 

 

 

March 31, 2017

 

December 31, 2016

ASSETS

 

Unaudited

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

$

35,273 

 

$

652,993 

Accounts receivable

 

75,959 

 

 

69,783 

Fair value of derivatives

 

3,093 

 

 

103 

Other current assets

 

1,671 

 

 

2,247 

Total current assets

 

115,996 

 

 

725,126 

Oil and natural gas properties, full cost accounting method:

 

 

 

 

 

  Evaluated properties

 

3,009,059 

 

 

2,754,353 

  Less accumulated depreciation, depletion, amortization and impairment

 

(1,972,091)

 

 

(1,947,673)

  Net evaluated oil and natural gas properties

 

1,036,968 

 

 

806,680 

  Unevaluated properties

 

1,154,850 

 

 

668,721 

Total oil and natural gas properties

 

2,191,818 

 

 

1,475,401 

Other property and equipment, net

 

18,067 

 

 

14,114 

Restricted investments

 

3,339 

 

 

3,332 

Deferred financing costs related to the senior secured revolving credit facility

 

2,744 

 

 

3,092 

Fair value of derivatives

 

2,939 

 

 

Acquisition deposit

 

 

 

46,138 

Other assets, net

 

676 

 

 

384 

Total assets

$

2,335,579 

 

$

2,267,587 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accounts payable and accrued liabilities

$

131,252 

 

$

95,577 

Accrued interest

 

12,114 

 

 

6,057 

Cash-settleable restricted stock unit awards

 

4,025 

 

 

8,919 

Asset retirement obligations

 

1,588 

 

 

2,729 

Fair value of derivatives

 

6,430 

 

 

18,268 

Total current liabilities

 

155,409 

 

 

131,550 

Senior secured revolving credit facility

 

 

 

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

 

390,536 

 

 

390,219 

Asset retirement obligations

 

4,652 

 

 

3,932 

Cash-settleable restricted stock unit awards

 

4,108 

 

 

8,071 

Deferred tax liability

 

556 

 

 

90 

Fair value of derivatives

 

 

 

28 

Other long-term liabilities

 

285 

 

 

295 

Total liabilities

 

555,546 

 

 

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 and 1,458,948 shares outstanding, respectively

 

15 

 

 

15 

Common stock, $0.01 par value, 300,000,000 and 300,000,000 shares authorized; 201,054,884 and 201,041,320 shares outstanding, respectively

 

2,011 

 

 

2,010 

Capital in excess of par value

 

2,173,243 

 

 

2,171,514 

Accumulated deficit

 

(395,236)

 

 

(440,137)

Total stockholders’ equity

 

1,780,033 

 

 

1,733,402 

Total liabilities and stockholders’ equity

$

2,335,579 

 

$

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 March 31,

 

 

 

2017

 

 

2016

Operating revenues:

 

 

 

 

 

 

  Oil sales

 

$

72,008 

 

$

27,443 

  Natural gas sales

 

 

9,355 

 

 

3,255 

Total operating revenues

 

 

81,363 

 

 

30,698 

Operating expenses:

 

 

 

 

 

 

  Lease operating expenses

 

 

12,937 

 

 

6,957 

  Production taxes

 

 

5,904 

 

 

2,220 

  Depreciation, depletion and amortization

 

 

24,433 

 

 

15,722 

  General and administrative

 

 

5,206 

 

 

5,562 

  Accretion expense

 

 

184 

 

 

180 

  Write-down of oil and natural gas properties

 

 

 

 

34,776 

  Acquisition expense

 

 

450 

 

 

48 

Total operating expenses

 

 

49,114 

 

 

65,465 

  Income (loss) from operations

 

 

32,249 

 

 

(34,767)

Other (income) expenses:

 

 

 

 

 

 

  Interest expense, net of capitalized amounts

 

 

665 

 

 

5,491 

  (Gain) loss on derivative contracts

 

 

(15,303)

 

 

932 

  Other income

 

 

(708)

 

 

(81)

Total other (income) expense

 

 

(15,346)

 

 

6,342 

  Income (loss) before income taxes

 

 

47,595 

 

 

(41,109)

     Income tax expense

 

 

466 

 

 

     Net income (loss)

 

 

47,129 

 

 

(41,109)

     Preferred stock dividends

 

 

(1,824)

 

 

(1,824)

 Income (loss) available to common stockholders

 

$

45,305 

 

$

(42,933)

 Income (loss) per common share:

 

 

 

 

 

 

  Basic

 

$

0.23 

 

$

(0.51)

  Diluted

 

$

0.22 

 

$

(0.51)

  Shares used in computing income (loss) per common share:

 

 

 

 

 

 

  Basic

 

 

201,054 

 

 

83,582 

  Diluted

 

 

201,740 

 

 

83,582 



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)





 

 

 

 

 

 

 

 

Three Months Ended March 31,

 

 

 

2017

 

 

2016

Cash flows from operating activities:

 

 

 

 

 

 

Net income (loss)

 

$

47,129 

 

$

(41,109)

Adjustments to reconcile net income to cash provided by operating activities:

 

 

 

 

 

 

  Depreciation, depletion and amortization

 

 

24,932 

 

 

16,129 

  Write-down of oil and natural gas properties

 

 

 

 

34,776 

  Accretion expense

 

 

184 

 

 

180 

  Amortization of non-cash debt related items

 

 

665 

 

 

781 

  Deferred income tax expense

 

 

466 

 

 

  Net (gain) loss on derivatives, net of settlements

 

 

(17,794)

 

 

8,648 

  Non-cash expense related to equity share-based awards

 

 

930 

 

 

516 

  Change in the fair value of liability share-based awards

 

 

(291)

 

 

709 

  Payments to settle asset retirement obligations

 

 

(765)

 

 

(161)

  Changes in current assets and liabilities:

 

 

 

 

 

 

     Accounts receivable

 

 

(4,066)

 

 

5,941 

     Other current assets

 

 

576 

 

 

580 

     Current liabilities

 

 

9,903 

 

 

(717)

     Change in other long-term liabilities

 

 

 

 

11 

     Change in other assets, net

 

 

(523)

 

 

(233)

  Payments to settle vested liability share-based awards

 

 

(8,662)

 

 

(9,807)

     Net cash provided by operating activities

 

 

52,684 

 

 

16,244 

Cash flows from investing activities:

 

 

 

 

 

 

Capital expenditures

 

 

(66,154)

 

 

(50,775)

Acquisitions

 

 

(648,485)

 

 

(10,183)

Acquisition deposit

 

 

46,138 

 

 

    Net cash used in investing activities

 

 

(668,501)

 

 

(60,958)

Cash flows from financing activities:

 

 

 

 

 

 

Borrowings on senior secured revolving credit facility

 

 

 

 

45,000 

Payments on senior secured revolving credit facility

 

 

 

 

(85,000)

Issuance of common stock

 

 

 

 

94,949 

Payment of preferred stock dividends

 

 

(1,824)

 

 

(1,824)

Tax withholdings related to restricted stock units

 

 

(79)

 

 

(124)

     Net cash provided by (used in) financing activities

 

 

(1,903)

 

 

53,001 

Net change in cash and cash equivalents

 

 

(617,720)

 

 

8,287 

  Balance, beginning of period

 

 

652,993 

 

 

1,224 

  Balance, end of period

 

$

35,273 

 

$

9,511 



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)

Table of Contents

 

 

 

 

INDEX TO THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS





 

 

 

1.

Description of Business and Basis of Presentation

6.

Fair Value Measurements

2.

Acquisitions

7.

Income Taxes

3.

Earnings Per Share

8.

Asset Retirement Obligations

4.

Borrowings

9.

Equity Transactions

5.

Derivative Instruments and Hedging Activities

10.

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 partially owned by a member of current management. 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 in West Texas. The Company’s operations to date have been predominantly focused on horizontal drilling of several prospective intervals, including multiple levels of the Wolfcamp formation and, more recently, the Lower Spraberry shale in the Midland Basin. 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, 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 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. As of March 31, 2017, the Company adopted this ASU, which did not have a material impact on its financial statements. The Company has elected to no longer estimate forfeitures.





7


 

 

 

 

Callon Petroleum Company

Notes to the Consolidated Financial Statements

(All dollar amounts in thousands, except per share and per unit data)

Table of Contents

 

 

 

 

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 $632,947, 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 acquired 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

 

$

134,315 

Unevaluated oil and natural gas properties

 

 

498,800 

Asset retirement obligations

 

 

(168)

  Net assets acquired

 

$

632,947 



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.



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 acquired 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.



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 March 31,



 

2017 (a)

 

2016 (a)

Revenues

 

$

84,416 

 

$

42,615 

Income (loss) from operations

 

 

34,907 

 

 

(35,451)

Income (loss) available to common stockholders

 

 

47,963 

 

 

(38,908)



 

 

 

 

 

 

Net income (loss) per common share:

 

 

 

 

 

 

Basic

 

$

0.24 

 

$

(0.31)

Diluted

 

$

0.24 

 

$

(0.31)



(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.

8


 

 

 

 

Callon Petroleum Company

Notes to the Consolidated Financial Statements

(All dollar amounts in thousands, except per share and per unit data)

Table of Contents

 

 

 

 



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 comingled with our existing properties and it is impractical to provide the stand-alone operational results related to these properties.



Subsequent event



In April 2017, the Company entered into an agreement to acquire 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 plans to fund the cash purchase price with its available cash and borrowings on our senior secured revolving credit facility.







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 March 31,

 

 

 

2017

 

 

2016

Net income (loss)

 

$

47,129 

 

$

(41,109)

Preferred stock dividends

 

 

(1,824)

 

 

(1,824)

Income (loss) available to common stockholders

 

$

45,305 

 

$

(42,933)



 

 

 

 

 

 

Weighted average shares outstanding

 

 

201,054 

 

 

83,582 

Dilutive impact of restricted stock

 

 

686 

 

 

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

 

 

201,740 

 

 

83,582 



 

 

 

 

 

 

Basic income (loss) per share

 

$

0.23 

 

$

(0.51)

Diluted income (loss) per share

 

$

0.22 

 

$

(0.51)



 

 

 

 

 

 

Stock options (a)

 

 

15 

 

 

15 

Restricted stock (a)

 

 

 

 

25 



(a)

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







 

Note 4 - Borrowings



The Company’s borrowings consisted of the following at:





 

 

 

 

 

 

 

 

March 31, 2017

 

December 31, 2016

Principal components:

 

 

 

 

 

 

Senior secured revolving credit facility

 

$

 

$

6.125% senior unsecured notes due 2024

 

 

400,000 

 

 

400,000 

  Total principal outstanding

 

 

400,000 

 

 

400,000 

6.125% senior unsecured notes due 2024, unamortized deferred financing costs

 

 

(9,464)

 

 

(9,781)

  Total carrying value of borrowings

 

$

390,536 

 

$

390,219 



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



On March 11, 2014, the Company entered into the Fifth Amended and Restated Credit Agreement to the Credit Facility with a maturity date of March 11, 2019.  JPMorgan Chase Bank, N.A. is Administrative Agent, and participants include several institutional lenders. The total notional amount available under the Credit Facility is $500,000. 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. Effective November 21, 2016, the Company achieved an indication to increase the Credit Facility’s borrowing base to $500,000, but elected to maintain the borrowing base at $385,000. As of March 31, 2017, the Company continued to maintain the Credit Facility’s borrowing base at $385,000.

 

9


 

 

 

 

Callon Petroleum Company

Notes to the Consolidated Financial Statements

(All dollar amounts in thousands, except per share and per unit data)

Table of Contents

 

 

 

 

As of March 31, 2017, there was no balance outstanding on the Credit Facility. For the quarter ended March 31, 2017, the Credit Facility had a weighted-average interest rate of 2.83%, 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 0.5% 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.



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; (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.



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 March 31, 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.



10


 

 

 

 

Callon Petroleum Company

Notes to the Consolidated Financial Statements

(All dollar amounts in thousands, except per share and per unit data)

Table of Contents

 

 

 

 

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

 

03/31/2017

 

12/31/2016

 

03/31/2017

 

12/31/2016

 

03/31/2017

 

12/31/2016

Natural gas

 

Current

 

Fair value of derivatives

 

$

 

$

 

$

(64)

 

$

(593)

 

$

(64)

 

$

(593)

Oil

 

Current

 

Fair value of derivatives

 

 

3,093 

 

 

103 

 

 

(6,366)

 

 

(17,675)

 

 

(3,273)

 

 

(17,572)

Oil

 

Non-current

 

Fair value of derivatives

 

 

2,939 

 

 

 

 

 

 

(28)

 

 

2,939 

 

 

(28)

 

 

Totals

 

 

 

$

6,032 

 

$

103 

 

$

(6,430)

 

$

(18,296)

 

$

(398)

 

$

(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:



 

 

 

 

 

 

 

 

 



 

 

March 31, 2017



 

Presented without

 

 

 

As Presented with



 

Effects of Netting

 

Effects of Netting

 

Effects of Netting

Current assets: Fair value of derivatives

 

$

5,055 

 

$

(1,962)

 

$

3,093 

Long-term assets: Fair value of derivatives

 

 

2,939 

 

 

 

 

2,939 



 

 

 

 

 

 

 

 

 

Current liabilities: Fair value of derivatives

 

$

(8,392)

 

$

1,962 

 

$

(6,430)





 

 

 

 

 

 

 

 

 



 

 

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 March 31,



 

 

2017

 

 

2016

Oil derivatives

 

 

 

 

 

 

Net gain (loss) on settlements

 

$

(2,524)

 

$

7,507 

Net gain (loss) on fair value adjustments

 

 

17,266 

 

 

(9,137)

  Total gain (loss) on oil derivatives

 

$

14,742 

 

$

(1,630)

Natural gas derivatives

 

 

 

 

 

 

Net gain on settlements

 

$

33 

 

$

209 

Net gain on fair value adjustments

 

 

528 

 

 

489 

  Total gain on natural gas derivatives

 

$

561 

 

$

698 



 

 

 

 

 

 

Total gain (loss) on oil & natural gas derivatives

 

$

15,303 

 

$

(932)



11


 

 

 

 

Callon Petroleum Company

Notes to the Consolidated Financial Statements

(All dollar amounts in thousands, except per share and per unit data)

Table of Contents

 

 

 

 

Derivative positions



Listed in the tables below are the outstanding oil and natural gas derivative contracts as of March 31, 2017:  





 

 

 

 

 

 



 

For the Remainder of

 

For the Full Year of

Oil contracts

 

2017

 

2018

Swap contracts combined with short puts (WTI, enhanced swaps)

 

 

 

 

 

 

  Total volume (MBbls)

 

 

550 

 

 

  Weighted average price per Bbl

 

 

 

 

 

 

     Swap

 

$

44.50 

 

$

     Short put option

 

$

30.00 

 

$

Deferred premium put option

 

 

 

 

 

 

  Total volume (MBbls)

 

 

250 

 

 

  Premium per Bbl

 

$

2.05 

 

$

  Weighted average price per Bbl

 

 

 

 

 

 

     Long put option

 

$

50.00 

 

$

Deferred premium put spread option

 

 

 

 

 

 

  Total volume (MBbls)

 

 

506 

 

 

  Premium per Bbl

 

$

2.45 

 

$

  Weighted average price per Bbl

 

 

 

 

 

 

     Long put option

 

$

50.00 

 

$

     Short put option

 

$

40.00 

 

$

Collar contracts (WTI, two-way collars)

 

 

 

 

 

 

  Total volume (MBbls)

 

 

1,018 

 

 

  Weighted average price per Bbl

 

 

 

 

 

 

     Ceiling (short call)

 

$

58.19 

 

$

     Floor (long put)

 

$

47.50 

 

$

Call option contracts (short position)

 

 

 

 

 

 

  Total volume (MBbls)

 

 

505 

 

 

  Weighted average price per Bbl

 

 

 

 

 

 

     Call strike price

 

$

50.00 

 

$

Swap contracts (Midland basis differential)

 

 

 

 

 

 

  Volume (MBbls)

 

 

1,650 

 

 

2,008 

  Weighted average price per Bbl

 

$

(0.52)

 

$

(1.02)

Collar contracts combined with short puts (WTI, three-way collars)

 

 

 

 

 

 

  Total volume (MBbls)

 

 

 

 

2,738 

  Weighted average price per Bbl

 

 

 

 

 

 

     Ceiling (short call option)

 

$

 

$

62.84 

     Floor (long put option)

 

$

 

$

50.00 

     Short put option

 

$

 

$

40.00 







 

 

 

 

 

 



 

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)

 

 

1,100 

 

 

  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)

 

 

1,100 

 

 

  Weighted average price per MMBtu

 

 

 

 

 

 

     Ceiling (short call option)

 

$

3.68 

 

$

     Floor (long put option)

 

$

3.00 

 

$



12


 

 

 

 

Callon Petroleum Company

Notes to the Consolidated Financial Statements

(All dollar amounts in thousands, except per share and per unit data)

Table of Contents

 

 

 

 

Subsequent event



The following derivative contracts  were executed subsequent to March 31, 2017:





 

 

 

 

 

 



 

For the Remainder of

 

For the Full Year of

Gas contracts

 

2017

 

2018

Collar contracts (Henry Hub, two-way collars)

 

 

 

 

 

 

  Total volume (BBtu)

 

 

488 

 

 

720 

  Weighted average price per MMBtu

 

 

 

 

 

 

     Ceiling (short call option)

 

$

3.84 

 

$

3.84 

     Floor (long put option)

 

$

3.40 

 

$

3.40 

Swap contracts

 

 

 

 

 

 

  Total volume (BBtu)

 

 

736 

 

 

  Weighted average price per MMBtu

 

$

3.39 

 

$











 

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.





 

 

 

 

 

 

 

 

 

 

 

 



 

March 31, 2017

 

December 31, 2016



 

Carrying Value

 

Fair Value

 

Carrying Value

 

Fair Value

Credit Facility (a)

 

$

 

$

 

$

 

$

6.125% Senior Notes (b)

 

 

390,536 

 

 

416,000 

 

 

390,219 

 

 

412,000 

  Total

 

$

390,536 

 

$

416,000 

 

$

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.



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.



13


 

 

 

 

Callon Petroleum Company

Notes to the Consolidated Financial Statements

(All dollar amounts in thousands, except per share and per unit data)

Table of Contents

 

 

 

 

The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis:





 

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31, 2017

 

Classification

 

 

Level 1

 

 

Level 2

 

 

Level 3

 

 

Total

Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivative financial instruments

 

Fair value of derivatives

 

$

 

$

6,032 

 

$

 

$

6,032 

Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivative financial instruments

 

Fair value of derivatives

 

 

 

 

(6,430)

 

 

 

 

(6,430)

  Total net liabilities

 

 

 

$

 

$

(398)

 

$

 

$

(398)



 

 

 

 

 

 

 

 

 

 

 

 

 

 

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 has 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 all of the deferred tax asset. The valuation allowance was $127,073 as of March 31, 2017. 



The Company 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.



Note 8 - Asset Retirement Obligations



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



 

 

 



 

For the Three Months Ended



 

March 31, 2017

Asset retirement obligations at January 1, 2017

 

$

6,661 

Accretion expense

 

 

184 

Liabilities incurred

 

 

195 

Liabilities settled

 

 

(88)

Revisions to estimate

 

 

(712)

Asset retirement obligations at end of period

 

 

6,240 

Less: Current asset retirement obligations

 

 

(1,588)

  Long-term asset retirement obligations at March 31, 2017

 

$

4,652 



Certain of the Company’s operating agreements require that assets be restricted for abandonment obligations. Amounts recorded in the Consolidated Balance Sheets at March 31, 2017 as long-term restricted investments were $3,339. 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.



14


 

 

 

 

Callon Petroleum Company

Notes to the Consolidated Financial Statements

(All dollar amounts in thousands, except per share and per unit data)

Table of Contents

 

 

 

 

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 for the three months ended March 31, 2017 and 2016.



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 March 31, 2017, and the Company did not exercise its right to redeem the Preferred Stock, using the closing price of $13.16 as the value of a share of common stock, each share of Preferred Stock would be convertible into approximately 3.8 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 March 31, 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 $634,917. 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. 



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 March 31, 2017, the Company had contracts for three horizontal drilling rigs (the “Cactus 1 Rig”, “Cactus 2 Rig” and “Cactus 3 Rig”). The contract terms, as amended through December 31, 2016, of the Cactus 1 Rig and Cactus 2 Rig will end in July 2018 and August 2018, respectively. The contract terms of the Cactus 3 Rig, that commenced drilling in mid-January 2017, will end in July 2017. 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.



15


 

 

 

 

Callon Petroleum Company

Notes to the Consolidated Financial Statements

(All dollar amounts in thousands, except per share and per unit data)

Table of Contents

 

 

 

 

Subsequent event



In April 2017 the Company entered into a contract for a fourth horizontal drilling rig. The contract term will begin July 2017 through July 2019 with a day rate of $18,000 per day.



 

16


 

 

 

 

Callon Petroleum Company

 

Table of Contents

 

 

 

 



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.



 

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Callon Petroleum Company

 

Table of Contents

 

 

 

 

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 in West Texas. 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, more recently, 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 three months ended March 31, 2017. On March 31, 2017, our net acreage position in the Permian Basin was approximately  56,299 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 62% for the three months ended March 31, 2017,  compared to the same period of 2016,  increasing to 1,838 MBOE from 1,132 MBOE.



For the three months ended March 31, 2017, we drilled nine  gross (7.8 net) horizontal wells and completed seven gross (4.9 net) horizontal wells. As of March 31, 2017, we had nine  gross (7.1 net) horizontal wells awaiting completion.



As of March 31, 2017,  we had 539 gross (429 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 March 31, 2017, there was no balance outstanding on the Credit Facility, which has a borrowing base of $385 million. For the three months ended March 31, 2017, cash and cash equivalents decreased $617.6 million to $35.3 million compared to $652.9 million at December 31, 2016.  



Liquidity and cash flow



 

 

 

 

 

 



 

For the Three Months Ended March 31,

(dollars in millions)

 

2017

 

2016

Net cash provided by operating activities

 

$

52.7 

 

$

16.2 

Net cash used in investing activities

 

 

(668.5)

 

 

(60.9)

Net cash provided by (used in) financing activities

 

 

(1.9)

 

 

53.0 

  Net change in cash

 

$

(617.7)

 

$

8.3 





 

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Callon Petroleum Company

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

Table of Contents

 

 

 

 

Operating activities. For the three months ended March 31, 2017, net cash provided by operating activities was $52.7 million compared to net cash provided by operating activities of $16.2 million for the same period in 2016. The change was predominantly attributable to the following:



·

An increase in revenue offset by a decrease on settlements of derivative contracts;

·

An increase in certain operating expenses related to acquired properties;  

·

A decrease in payments in cash-setttled 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 three months ended March 31, 2017, net cash used in investing activities was $668.5 million compared to $60.9 million for the same period in 2016. The change was predominantly attributable to the following:



·

A  $12.7 million increase in operational expenditures due to the transition from a two-rig to a three-rig program in January 2017; and

·

A $592.2 million increase in 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):





 

 

 

 

 

 

 

 

 



 

For the Three Months Ended March 31,



 

2017

 

2016

 

 

$ Change

Operational expenditures

 

$

55.5 

 

$

42.8 

 

$

12.7 

Seismic, leasehold and other

 

 

6.2 

 

 

2.3 

 

 

3.9 

Capitalized general and administrative costs

 

 

3.9 

 

 

3.3 

 

 

0.6 

Capitalized interest

 

 

0.5 

 

 

2.3 

 

 

(1.8)

  Total capital expenditures (a)

 

 

66.1 

 

 

50.7 

 

 

15.4 



 

 

 

 

 

 

 

 

 

Acquisitions

 

 

648.5 

 

 

10.2 

 

 

638.3 

Acquisition deposits