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, 2015

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, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer,” and “smaller reporting 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

 

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’s had  65,871,037  shares of common stock outstanding as of April 30, 2015.

 

 


 

 

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 

1

 

 

Item 3.  Quantitative and Qualitative Disclosures about Market Risk 

23

 

 

Item 4.  Controls and Procedures 

24

 

 

Part II.  Other Information

 

 

 

Item 1.  Legal Proceedings 

25

 

 

Item 1A.  Risk Factors 

25

 

 

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

25

 

 

Item 3.  Defaults Upon Senior Securities 

25

 

 

Item 4.  Mine Safety Disclosures 

25

 

 

Item 5.  Other Information 

25

 

 

Item 6.  Exhibits 

26

 

 

 

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.

·

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.

·

LIBOR:  London Interbank Offered Rate.

·

LOE:  lease operating expense.

·

MBbls:  thousand barrels of oil.

·

MBOE:  thousand BOE.

·

Mcf:  thousand cubic feet of natural gas.

·

MMBtu:  million Btu.

·

MMcf:  million cubic feet of natural gas.

·

NGL or NGLs:  natural gas liquids, such as ethane, propane, butanes and natural gasoline that are extracted from natural gas production streams.

·

NYMEX:  New York Mercantile Exchange.

·

Oil: includes crude oil and condensate.

·

SEC:  United States Securities and Exchange Commission.

·

GAAP: Generally Accepted Accounting Principles in the United States.

 

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, 2015

 

December 31, 2014

ASSETS

 

Unaudited

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

$

2,144 

 

$

968 

Accounts receivable

 

31,930 

 

 

30,198 

Fair value of derivatives

 

19,160 

 

 

27,850 

Other current assets

 

989 

 

 

1,441 

Total current assets

 

54,223 

 

 

60,457 

Oil and natural gas properties, full cost accounting method:

 

 

 

 

 

  Evaluated properties

 

2,140,937 

 

 

2,077,985 

  Less accumulated depreciation, depletion and amortization

 

(1,496,454)

 

 

(1,478,355)

  Net oil and natural gas properties

 

644,483 

 

 

599,630 

  Unevaluated properties

 

142,867 

 

 

142,525 

Total oil and natural gas properties

 

787,350 

 

 

742,155 

Other property and equipment, net

 

8,046 

 

 

7,118 

Restricted investments

 

3,292 

 

 

3,810 

Deferred tax asset

 

47,238 

 

 

44,688 

Deferred financing costs

 

17,432 

 

 

18,200 

Other assets, net

 

456 

 

 

342 

Total assets

$

918,037 

 

$

876,770 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accounts payable and accrued liabilities

$

68,271 

 

$

76,753 

Accrued interest

 

5,853 

 

 

5,993 

Cash-settled restricted stock unit awards

 

6,473 

 

 

3,856 

Asset retirement obligations

 

5,047 

 

 

4,747 

Deferred tax liability

 

3,687 

 

 

6,214 

Fair value of derivatives

 

473 

 

 

1,249 

Total current liabilities

 

89,804 

 

 

98,812 

Senior secured revolving credit facility

 

37,000 

 

 

35,000 

Secured second lien term loan

 

300,000 

 

 

300,000 

Asset retirement obligations

 

1,262 

 

 

1,927 

Cash-settled restricted stock unit awards

 

2,300 

 

 

7,175 

Other long-term liabilities

 

120 

 

 

121 

Total liabilities

 

430,486 

 

 

443,035 

Stockholders’ equity:

 

 

 

 

 

Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized: 1,578,948 and 1,578,948 shares outstanding, respectively

 

16 

 

 

16 

Common stock, $0.01 par value, 110,000,000 shares authorized; 65,860,729 and 55,225,288 shares outstanding, respectively

 

659 

 

 

552 

Capital in excess of par value

 

592,042 

 

 

526,162 

Accumulated deficit

 

(105,166)

 

 

(92,995)

Total stockholders’ equity

 

487,551 

 

 

433,735 

Total liabilities and stockholders’ equity

$

918,037 

 

$

876,770 

 

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,

 

 

 

2015

 

 

2014

Operating revenues:

 

 

 

 

 

 

  Oil sales

 

$

27,909 

 

$

30,909 

  Natural gas sales

 

 

2,482 

 

 

2,376 

Total operating revenues

 

 

30,391 

 

 

33,285 

Operating expenses:

 

 

 

 

 

 

  Lease operating expenses

 

 

6,959 

 

 

4,230 

  Production taxes

 

 

2,265 

 

 

1,917 

  Depreciation, depletion and amortization

 

 

18,104 

 

 

10,538 

  General and administrative

 

 

12,102 

 

 

10,807 

  Accretion expense

 

 

209 

 

 

228 

  Rig termination fee

 

 

3,641 

 

 

  Gain on sale of other property and equipment

 

 

 

 

(1,080)

Total operating expenses

 

 

43,280 

 

 

26,640 

  Income (loss) from operations

 

 

(12,889)

 

 

6,645 

Other (income) expenses:

 

 

 

 

 

 

  Interest expense

 

 

4,858 

 

 

977 

  (Gain) loss on derivative contracts

 

 

(2,429)

 

 

2,513 

  Other income

 

 

(44)

 

 

(49)

Total other expenses

 

 

2,385 

 

 

3,441 

  Income (loss) before income taxes

 

 

(15,274)

 

 

3,204 

     Income tax expense (benefit)

 

 

(5,077)

 

 

1,341 

     Net income (loss)

 

 

(10,197)

 

 

1,863 

     Preferred stock dividends

 

 

(1,974)

 

 

(1,974)

 Loss available to common stockholders

 

$

(12,171)

 

$

(111)

 Loss per common share:

 

 

 

 

 

 

  Basic

 

$

(0.21)

 

$

(0.00)

  Diluted

 

$

(0.21)

 

$

(0.00)

  Shares used in computing loss per common share:

 

 

 

 

 

 

  Basic

 

 

57,479 

 

 

40,328 

  Diluted

 

 

57,479 

 

 

40,328 

 

 

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,

 

 

 

2015

 

 

2014

Cash flows from operating activities:

 

 

 

 

 

 

Net income (loss)

 

$

(10,197)

 

$

1,863 

Adjustments to reconcile net income (loss) to cash provided by operating activities:

 

 

 

 

 

 

  Depreciation, depletion and amortization

 

 

18,546 

 

 

10,598 

  Accretion expense

 

 

209 

 

 

228 

  Amortization of non-cash debt related items

 

 

781 

 

 

119 

  Amortization of deferred credit

 

 

 

 

(433)

  Deferred income tax (benefit) expense

 

 

(5,077)

 

 

1,341 

  Net loss on derivatives, net of settlements

 

 

7,914 

 

 

1,639 

  Gain on sale of other property and equipment

 

 

 

 

(1,080)

  Non-cash expense related to equity share-based awards

 

 

86 

 

 

996 

  Change in the fair value of liability share-based awards

 

 

3,088 

 

 

3,483 

  Payments to settle asset retirement obligations

 

 

258 

 

 

(26)

  Changes in current assets and liabilities:

 

 

 

 

 

 

     Accounts receivable

 

 

(2,125)

 

 

(2,928)

     Other current assets

 

 

452 

 

 

707 

     Current liabilities

 

 

(355)

 

 

5,155 

  Payments to settle vested liability share-based awards related to early retirements

 

 

(3,538)

 

 

  Payments to settle vested liability share-based awards

 

 

(3,599)

 

 

(1,669)

  Change in other assets, net

 

 

(319)

 

 

(26)

     Net cash provided by operating activities

 

 

6,124 

 

 

19,967 

Cash flows from investing activities:

 

 

 

 

 

 

Capital expenditures

 

 

(70,780)

 

 

(65,760)

Proceeds from sales of mineral interest and equipment

 

 

272 

 

 

2,226 

    Net cash used in investing activities

 

 

(70,508)

 

 

(63,534)

Cash flows from financing activities:

 

 

 

 

 

 

Borrowings on credit facility

 

 

60,000 

 

 

46,000 

Payments on credit facility

 

 

(58,000)

 

 

Payment of deferred financing costs

 

 

(12)

 

 

(1,729)

Issuance of common stock

 

 

65,546 

 

 

Payment of preferred stock dividends

 

 

(1,974)

 

 

(1,974)

     Net cash provided by financing activities

 

 

65,560 

 

 

42,297 

Net change in cash and cash equivalents

 

 

1,176 

 

 

(1,270)

  Balance, beginning of period

 

 

968 

 

 

3,012 

  Balance, end of period

 

$

2,144 

 

$

1,742 

 

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 unit data)

 

INDEX TO THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

 

 

 

1. 

Description of Business and Basis of Presentation

6.

Fair Value Measurements

2. 

Acquisitions

7.

Asset Retirement Obligations

3. 

Earnings Per Share

8.

Equity Transactions

4. 

Borrowings

9.

Other

5. 

Derivative Instruments and Hedging Activities

 

 

 

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, and more specifically, the Midland Basin. The Company’s operations to date have been predominantly focused on horizontal drilling of several prospective intervals, including multiple levels of the Wolfcamp formation. 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 our existing acreage and acquisition of additional locations through 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 the 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, 2014. The balance sheet at December 31, 2014 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, 2015.

 

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.

 

7


 

 

 

 

 

Footnotes to the Financial Statements (continued)

(Unless otherwise indicated, dollar amounts included in the footnotes to the financial

statements are presented in thousands, except for per share and per unit data)

 

 

Table of Contents

 

Recently issued accounting policies

 

In April 2015, the Financial Accounting Standards Board issued accounting standards update (“ASU”) No. 2015-03, Interest – Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs. The standard requires that the costs for issuing debt should appear on the balance sheet as direct reduction from the debt’s value. The guidance in ASU No. 2015-03 is effective for public entities for annual reporting periods beginning after December 15, 2015, including interim periods therein. Early adoption is permitted. The Company is currently evaluating the method of adoption and impact this standard will have on its financial statements and related disclosures.

 

Note 2 – Acquisitions

 

On October 8, 2014, the Company completed the acquisition of certain undeveloped acreage and producing oil and gas properties located in Midland, Andrews, Ector and Martin Counties, Texas (the “Central Midland Basin Acquisition”) for an aggregate cash purchase price of $210,205. The Company assumed operatorship of the properties on November 1, 2014, and acquired a 62% working interest (46.5% net revenue interest) in the Central Midland Basin Acquisition. The aggregate cash purchase price was funded with a combination of the net proceeds from an equity offering of $122,450 and a portion of the proceeds from borrowings under a secured second lien term loan.

 

The Central Midland Basin Acquisition was accounted for under the acquisition method of accounting, which involves determining the fair value of the assets acquired and liabilities assumed. The following purchase price allocation is based on management’s estimates of the fair value of the assets acquired and liabilities assumed. The following table summarizes the acquisition date fair values of the net assets acquired:

 

 

 

 

 

Oil and natural gas properties

 

$

91,895 

Unevaluated oil and natural gas properties

 

 

118,450 

Asset retirement obligations

 

 

(140)

  Net assets acquired

 

$

210,205 

 

The following unaudited summary pro forma financial information for the three months ended March 31, 2014 has been presented for illustrative purposes only and does not purport to represent what the Company’s results of operations would have been if the Central Midland Basin Acquisition had occurred as presented, or to project the Company’s results of operations for any future periods. The pro forma financial information was prepared assuming the Central Midland Basin Acquisition occurred as of January 1, 2013. 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. 

 

 

 

 

 

 

Three Months Ended

 

 

March 31, 2014

Revenues

 

$

43,184 

Income from operations

 

 

12,357 

Income available to common stockholders

 

 

791 

 

 

 

 

Net income per common share:

 

 

 

Basic

 

$

0.01 

Diluted

 

$

0.01 

 

 

 

 

8


 

 

 

 

 

Footnotes to the Financial Statements (continued)

(Unless otherwise indicated, dollar amounts included in the footnotes to the financial

statements are presented in thousands, except for per share and per unit data)

 

 

Table of Contents

 

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,

 

 

 

2015

 

 

2014

Net income (loss)

 

$

(10,197)

 

$

1,863 

Preferred stock dividends

 

 

(1,974)

 

 

(1,974)

Loss available to common stockholders

 

$

(12,171)

 

$

(111)

 

 

 

 

 

 

 

Weighted average shares outstanding

 

 

57,479 

 

 

40,328 

Weighted average shares outstanding for diluted loss per share

 

 

57,479 

 

 

40,328 

 

 

 

 

 

 

 

Basic loss per share

 

$

(0.21)

 

$

(0.00)

Diluted loss per share

 

$

(0.21)

 

$

(0.00)

 

 

 

 

 

 

 

The following were excluded from the diluted earnings per share calculation because their effect would be anti-dilutive:

Stock options

 

 

30 

 

 

40 

Restricted stock

 

 

61 

 

 

 

 

 

Note 4 – Borrowings 

 

The Company’s borrowings consisted of the following at:

 

 

 

 

 

 

 

 

 

 

March 31, 2015

 

December 31, 2014

Principal components:

 

 

 

 

 

 

Senior secured revolving credit facility

 

$

37,000 

 

$

35,000 

Secured second lien term loan

 

 

300,000 

 

 

300,000 

Total carrying value of borrowings

 

$

337,000 

 

$

335,000 

 

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 participating lenders include Regions Bank, Citibank, N.A., Capital One, N.A., KeyBank, N.A., Whitney Bank, IberiaBank, N.A., OneWest Bank, N.A., SunTrust Bank and Royal Bank of Canada. 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. As of March 31, 2015 the Credit Facility’s borrowing base was $250,000. The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties.

 

As of March 31, 2015, the balance outstanding on the Credit Facility was $37,000 with a weighted-average interest rate of 1.98%, calculated as the LIBOR plus a tiered rate ranging from 1.75% to 2.75%, 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.

 

Secured second lien term loan (the “Term Loan”)

 

On October 8, 2014, the Company entered into the Term Loan with an aggregate amount of up to $300,000 and a maturity date of October 8, 2021. The Royal Bank of Canada is Administrative Agent, and participants include several institutional lenders. The Term Loan may be prepaid at the Company’s option, subject to a prepayment premium. The prepayment amount is (i) 102% if the prepayment event occurs prior to October 8, 2015, and (ii) 101% if the prepayment event occurs on or after October 8, 2015 but before October 8, 2016, and (iii) 100% for prepayments made on or after October 8, 2016. The Term Loan is secured by junior liens on properties mortgaged under the Credit Facility, subject to an intercreditor agreement. As of March 31, 2015, the balance outstanding on the Term Loan was $300,000 with an interest rate of 8.5%, calculated at a rate of LIBOR (subject to a floor rate of 1.0%) plus 7.5% 

9


 

 

 

 

 

Footnotes to the Financial Statements (continued)

(Unless otherwise indicated, dollar amounts included in the footnotes to the financial

statements are presented in thousands, except for per share and per unit data)

 

 

Table of Contents

 

per annum. The Company can elect a LIBOR rate based on various tenors, and is currently incurring interest based on an underlying three-month LIBOR rate, which was last elected in April 2015. 

 

Restrictive covenants

 

The Company’s Credit Facility and Term Loan 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, 2015.

 

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, puts, calls 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 that have 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 sheet and records changes in fair value as a gain or loss on derivative contracts in the consolidated statement of operations. Cash settlements are also recorded as gain or loss on derivative contracts in the consolidated statement of operations.

 

10


 

 

 

 

 

Footnotes to the Financial Statements (continued)

(Unless otherwise indicated, dollar amounts included in the footnotes to the financial

statements are presented in thousands, except for per share and per unit data)

 

 

Table of Contents

 

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

 

03/31/15

 

12/31/2014

 

03/31/2015

 

12/31/2014

 

03/31/2015

 

12/31/2014

Natural gas

 

Current

 

Fair value of derivatives

 

$

1,131 

 

$

1,262 

 

$

(1)

 

$

(7)

 

$

1,130 

 

$

1,255 

Oil

 

Current

 

Fair value of derivatives

 

 

18,029 

 

 

26,588 

 

 

(472)

 

 

(1,242)

 

 

17,557 

 

 

25,346 

 

 

Totals

 

 

 

$

19,160 

 

$

27,850 

 

$

(473)

 

$

(1,249)

 

$

18,687 

 

$

26,601 

 

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, 2015

 

 

Presented without

 

 

 

As Presented with

 

 

Effects of Netting

 

Effects of Netting

 

Effects of Netting

Current assets: Fair value of derivatives

 

$

20,506 

 

$

(1,346)

 

$

19,160 

Current liabilities: Fair value of derivatives

 

$

(1,819)

 

$

1,346 

 

$

(473)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2014

 

 

Presented without

 

 

 

As Presented with

 

 

Effects of Netting

 

Effects of Netting

 

Effects of Netting

Current assets: Fair value of derivatives

 

$

27,850 

 

$

 

$

27,850 

Current liabilities: Fair value of derivatives

 

$

(1,249)

 

$

 

$

(1,249)

 

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,

 

 

 

2015

 

 

2014

Natural gas derivatives

 

 

 

 

 

 

Net gain (loss) on settlements

 

$

391 

 

$

(102)

Net gain (loss) on fair value adjustments

 

 

(125)

 

 

(190)

  Total gain (loss)

 

$

266 

 

$

(292)

 

 

 

 

 

 

 

Oil derivatives

 

 

 

 

 

 

Net gain (loss) on settlements

 

$

9,952 

 

$

(773)

Net gain (loss) on fair value adjustments

 

 

(7,789)

 

 

(1,448)

  Total gain (loss)

 

$

2,163 

 

$

(2,221)

 

 

 

 

 

 

 

Total gain (loss) on derivative contracts

 

$

2,429 

 

$

(2,513)

 

11


 

 

 

 

 

Footnotes to the Financial Statements (continued)

(Unless otherwise indicated, dollar amounts included in the footnotes to the financial

statements are presented in thousands, except for 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, 2015:

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended

 

 

June 30,

 

September 30,

 

December 31,

Oil contracts

 

2015

 

2015

 

2015

Swap contracts (NYMEX):

 

 

 

 

 

 

 

 

 

  Total volume (MBbls)

 

 

409 

 

 

382 

 

 

327 

  Weighted average price per Bbl

 

$

70.79 

 

$

70.76 

 

$

67.12 

Swap contracts (Midland basis differential):

 

 

 

 

 

 

 

 

 

  Volume (MBbls)

 

 

400 

 

 

382 

 

 

327 

  Weighted average price per Bbl

 

$

(2.40)

 

$

(2.39)

 

$

(2.38)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended

 

 

June 30,

 

September 30,

 

December 31,

Natural gas contracts

 

2015

 

2015

 

2015

Collar contracts combined with short

 

 

 

 

 

 

 

 

 

puts (three-way collar):

 

 

 

 

 

 

 

 

 

  Volume (BBtu)

 

 

227 

 

 

207 

 

 

161 

   Weighted average price per MMBtu

 

 

 

 

 

 

 

 

 

     Ceiling (short call)

 

$

4.32 

 

$

4.32 

 

$

4.32 

     Floor (long put)

 

$

3.85 

 

$

3.85 

 

$

3.85 

     Short put

 

$

3.25 

 

$

3.25 

 

$

3.25 

Swap contracts:

 

 

 

 

 

 

 

 

 

  Total volume (BBtu)

 

 

237 

 

 

219 

 

 

228 

  Weighted average price per MMBtu

 

$

3.98 

 

$

3.98 

 

$

3.96 

Short call contracts:

 

 

 

 

 

 

 

 

 

  Short call volume (BBtu)

 

 

109 

 

 

110 

 

 

111 

  Short call price per MMBtu

 

$

5.00 

 

$

5.00 

 

$

5.00 

 

 

Subsequent Event

 

The following derivative contracts were executed subsequent to March 31, 2015:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Three Months Ended

 

 

September 30,

 

December 31,

 

March 31,

 

June 30,

 

September 30,

 

December 31,

Oil contracts

 

2015

 

2015

 

2016

 

2016

 

2016

 

2016

Swap contracts:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Total volume (MBbls)

 

 

138 

 

 

115 

 

 

91 

 

 

91 

 

 

92 

 

 

92 

  Weighted average price per Bbl

 

$

57.42 

 

$

58.70 

 

$

63.50 

 

$

63.50 

 

$

63.50 

 

$

63.50 

Collar contracts combined with

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

short puts (three-way collar):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Volume (MBbls)

 

 

 

 

 

 

91 

 

 

91 

 

 

92 

 

 

92 

   Weighted average price per Bbl

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

     Ceiling (short call)

 

$

 

$

 

$

70.00 

 

$

70.00 

 

$

70.00 

 

$

70.00 

     Floor (long put)

 

$

 

$

 

$

60.00 

 

$

60.00 

 

$

60.00 

 

$

60.00 

     Short put

 

$

 

$

 

$

45.00 

 

$

45.00 

 

$

45.00 

 

$

45.00 

 

 

 

 

 

 

 

 

 

 

12


 

 

 

 

 

Footnotes to the Financial Statements (continued)

(Unless otherwise indicated, dollar amounts included in the footnotes to the financial

statements are presented in thousands, except for per share and per unit data)

 

 

Table of Contents

 

Note 6 - Fair Value Measurements 

 

The fair value hierarchy outlined in the relevant accounting guidance 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, restricted investments. The carrying amounts for these instruments approximate fair value due to the short-term nature or maturity of the instruments.

 

Debt. The Company’s debt is recorded at the carrying amount in the consolidated balance sheet. The carrying amount of floating-rate debt approximated fair value because the interest rates were variable and reflective of market rates.

 

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:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance Sheet Presentation as of March 31, 2015

 

Classification

 

 

Level 1

 

 

Level 2

 

 

Level 3

 

 

Total

Fair value of derivatives

 

Current assets

 

$

 

$

19,160 

 

$

 

$

19,160 

Fair value of derivatives

 

Current liabilities

 

$

 

$

(473)

 

$

 

$

(473)

  Total net assets (liabilities)

 

 

 

$

 

$

18,687 

 

$

 

$

18,687 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance Sheet Presentation as of December 31, 2014

 

Classification

 

 

Level 1

 

 

Level 2

 

 

Level 3

 

 

Total

Fair value of derivatives

 

Current assets

 

$

 

$

27,850 

 

$

 

$

27,850 

Fair value of derivatives

 

Current liabilities

 

$

 

$

(1,249)

 

$

 

$

(1,249)

  Total net assets (liabilities)

 

 

 

$

 

$

26,601 

 

$

 

$

26,601 

 

 

Note 7 - Asset Retirement Obligations 

 

The table below summarizes the Company’s asset retirement obligations activity for the three months ended March 31, 2015:

 

 

 

 

Asset retirement obligations at January 1, 2015

 

$

6,674 

Accretion expense

 

 

209 

Liabilities incurred

 

 

87 

Liabilities settled

 

 

(178)

Revisions to estimate

 

 

(483)

Asset retirement obligations at end of period

 

 

6,309 

Less: Current asset retirement obligations

 

 

(5,047)

  Long-term asset retirement obligations at March 31, 2015

 

$

1,262 

 

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, 2015 as long-term restricted investments were $3,292. These assets, which primarily include

13


 

 

 

 

 

Footnotes to the Financial Statements (continued)

(Unless otherwise indicated, dollar amounts included in the footnotes to the financial

statements are presented in thousands, except for per share and per unit data)

 

 

Table of Contents

 

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 8 – 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 $1,974 for the three months ended March 31, 2015 and 2014.

 

The Preferred Stock has no stated maturity and is not be 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, 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 a 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, 2015, and the Company did not exercise its right to redeem the Preferred Stock, using the closing price of ($7.47) as the value of a share of common stock, each share of Preferred Stock would be convertible into approximately 6.7 shares of common stock. If the Company exercises its redemption rights relating to shares of Preferred Stock, the holders of Preferred Stock will not have the conversion right described above.

 

Common Stock

 

On March 13, 2015, the Company completed an underwritten public offering of 9,000,000 shares of its common stock at $6.55 per share, before underwriting discounts, and the exercise in full by the underwriters of their option to purchase 1,350,000 additional shares of common stock at $6.55 per share, before underwriting discounts. The Company received net proceeds of approximately $65,546, after the underwriting discounts and estimated offering costs.

 

Note 9 – Other

 

Operating leases

 

As of March 31, 2015, the Company had contracts for two horizontal drilling rigs (the “Cactus 1 Rig” and “Cactus 2 Rig”) and one vertical rig. The horizontal rigs were initially contracted for a term of two years in April 2012, the terms of which were subsequently renewed in March 2014. In March 2015, the Company extended the terms of its Cactus 1 Rig and Cactus 2 Rig to end in July 2018 and August 2018, respectively. The vertical drilling rig was initially contracted for a term of one year with an expiration of November 2015 to be used as part of our horizontal drilling program, drilling the vertical section of horizontal wells. The rig lease agreements include early termination provisions that obligate the Company to reduced minimum rentals pursuant to a “standby” dayrate for the 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. In March 2015, the Company decided to terminate its one-year contract for the vertical rig effective April 2015 and will be required to pay approximately $3,641 in reduced rental payments over the remainder of the lease term unless the lessor is able to re-charter the rig to another lessee. This amount was recognized as rig termination fee on the Consolidated Statements of Income for the three months ended March 31, 2015.

 

 

14


 

Table of Contents

Special Note Regarding Forward Looking Statements

 

All statements, other than statements of historical fact, may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements that address activities, outcomes and other matters that should or may occur in the future, including, without limitation, statements regarding the financial position, business strategy, production and reserve quantities, present value and growth and other plans and objectives for our future operations, are forward-looking statements. Although we believe the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance.

 

Forward-looking statements include the items identified in the preceding paragraph, information concerning possible or assumed future results of operations and other statements in this Form 10-Q identified by words such as “anticipate,” “project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target” or similar expressions.

 

You should not place undue reliance on forward-looking statements. They are subject to known and unknown risks, uncertainties and other factors that may affect our operations, markets, products, services and prices and 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 addition to any assumptions and other factors referred to specifically in connection with forward-looking statements, risks, uncertainties and factors that could cause our actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to: 

 

·

the timing and extent of changes in market conditions and prices for oil, natural gas and NGLs (including regional basis differentials),

·

our ability to transport our production to the most favorable markets or at all,

·

the timing and extent of our success in discovering, developing, producing and estimating reserves,

·

our ability to fund our planned capital investments,

·

the impact of government regulation, including regulation of endangered species, any increase in severance or similar taxes, legislation relating to hydraulic fracturing, the climate and over-the-counter derivatives,

·

the costs and availability of oilfield personnel services and drilling supplies, raw materials, and equipment and services,

·

our future property acquisition or divestiture activities,

·

the effects of weather,

·

increased competition,

·

the financial impact of accounting regulations and critical accounting policies,

·

the comparative cost of alternative fuels,

·

conditions in capital markets, changes in interest rates and the ability of our lenders to provide us with funds as agreed,

·

credit risk relating to the risk of loss as a result of non-performance by our counterparties, 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, 2014 (the  “2014 Annual Report on Form 10-K”), and all quarterly reports on Form 10-Q filed subsequently thereto.

 

Should one or more of the risks or uncertainties described above or in our 2014 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.

 

15


 

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  2014 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, and more specifically, the Midland Basin. Our operations to date have been predominantly focused on horizontal drilling of several prospective intervals, including multiple levels of the Wolfcamp formation. 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 acreage purchases, joint ventures and asset swaps. Our production was approximately 83% oil and 17% natural gas for the  three months ended March 31, 2015. On March 31, 2015, our net acreage position in the Permian Basin was approximately 25,854 net acres, including 7,496 net acres in the Northern Midland Basin that the Company plans to let expire in its entirety by 2016. As a result, no drilling or other capital expenditures are planned for the Northern Midland Basin in 2015.

 

Operational Highlights

 

Our production grew 97% for the three months ended March 31, 2015, compared to the same period of 2014, increasing to 771 MBOE from 392 MBOE.

 

 

 

 

 

 

 

 

 

 

 

 

Net Production (MBOE)

 

 

Three Months Ended March 31,

 

 

2015

 

2014

 

Change

 

% Change

Southern Midland Basin

 

445 

 

315 

 

130 

 

41% 

Central Midland Basin

 

325 

 

71 

 

254 

 

358% 

Northern Midland Basin

 

 

 

(5)

 

(83)%

  Total

 

771 

 

392 

 

379 

 

97% 

 

 

The following table sets forth productive wells as of March 31, 2015:

 

 

 

 

 

 

 

 

 

 

 

 

Oil Wells

 

Natural Gas Wells

 

 

Gross

 

Net

 

Gross

 

Net

Working interest

 

337 

 

249.5 

 

 

Royalty interest

 

 

0.1 

 

 

  Total

 

340 

 

249.6 

 

 

 

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.

 

16


 

Table of Contents

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

The following table summarizes the Company’s drilling activity in the Permian Basin for the three months ended March 31, 2015:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Drilled

 

Completed (a)

 

Awaiting Completion

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

Southern Midland Basin

 

 

 

 

 

 

 

 

 

 

 

 

Horizontal wells

 

 

5.8 

 

 

6.8 

 

 

2.0 

  Total

 

 

5.8 

 

 

6.8 

 

 

2.0 

Central Midland Basin

 

 

 

 

 

 

 

 

 

 

 

 

Vertical wells

 

 

 

 

0.4 

 

 

Horizontal wells

 

 

2.0 

 

 

1.3 

 

 

0.7 

  Total

 

 

2.0 

 

 

1.7 

 

 

0.7 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total vertical wells

 

 

 

 

0.4 

 

 

Total horizontal wells

 

10 

 

7.8 

 

10 

 

8.1 

 

 

2.7 

  Total

 

10 

 

7.8 

 

11 

 

8.5 

 

 

2.7 

 

(a)

Completions include wells drilled prior to 2015 

 

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 recently completed a common stock offering to raise additional capital, and we continue to evaluate other sources of capital to complement our cash flows from operations as we pursue our long-term growth plan in the Permian Basin.

 

Based upon current commodity price expectations for 2015, we believe that our cash flow from operations, proceeds from our March 2015 equity offering and borrowings under our Credit Facility and Term Loan will be sufficient to fund our operations for 2015, including any deficiencies in the Company’s current net working capital. However, future cash flows are subject to a number of variables, including forecast production volumes and commodity prices. We are the operator for 100% of our remaining 2015 capital program and, as a result, the amount and timing of a substantial portion of our planned capital expenditures is largely discretionary. Accordingly, we may determine it prudent to curtail drilling and completion operations due to capital constraints or reduced returns on investment as a result of commodity price weakness.

 

Cash and cash equivalents increased $1.2 million in the three months ended March 31, 2015 to $2.1 million compared to $1.0 million at December 31, 2014.  

 

Liquidity and cash flow

 

 

 

 

 

 

 

 

 

Three Months Ended March 31,

(dollars in millions)

 

2015

 

2014

Net cash provided by operating activities

 

$

6.1 

 

$

20.0 

Net cash used in investing activities

 

 

(70.5)

 

 

(63.5)

Net cash provided by financing activities

 

 

65.6 

 

 

42.3 

  Net change in cash

 

$

1.2 

 

$

(1.3)

 

Operating activities.  For the three months ended March 31, 2015, net cash provided by operating activities was $6.1 million compared to net cash provided by operating activities of $20.0 million for the same period in 2014.  The decrease was primarily due to decreases in oil sales, which were partially offset by gains on the settlement of derivative contracts. Also contributing to the decrease were increases in lease operating expenses, production taxes, interest expenses, the impact on nonrecurring early retirement expenses, and payments on cash-settleable RSU awards. Production, realized prices, and operating expenses are discussed below in Results of Operations. See Notes 5 and 6 in the Footnotes to the Financial Statements for a reconciliation of the components of the Company’s derivative contracts and disclosures related to derivative instruments including their composition and valuation.

 

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

Investing activities.  For the three months ended March 31, 2015, net cash used in investing activities was $70.5 million compared to $63.5 million for the same period in 2014. The $7.0 million increase in cash used in investing activities was primarily attributable to a $13.3  million increase in capital expenditures, which was driven by the addition of the vertical rig added to our drilling program in August 2014. The increase in capital expenditures was significantly offset by acquisition costs, which were $8.0 million for the three months ended March 31, 2014. Also offsetting the increase was a $2.0 million reduction of proceeds resulting from the sale of certain specialized deep water equipment during the three months ended March 31, 2014.

 

Capital expenditures for the three months ended March 31, 2015 include the following (in millions):

 

 

 

 

 

Southern Midland Basin

 

$

55.7 

Central Midland Basin

 

 

9.4 

  Total operational expenditures

 

 

65.1 

 

 

 

 

Capitalized general and administrative costs allocated directly to exploration and development projects

 

 

2.8 

Capitalized interest

 

 

2.9 

  Total capitalized general and administrative and interest costs

 

 

5.7 

  Total capital expenditures

 

$

70.8 

 

Financing activities.  For the three months ended March 31, 2015, net cash provided by financing activities was $65.6 million compared to cash provided by financing activities of $42.3 million during the same period of 2014. Net cash provided by financing activities during the three months ended March 31, 2015 included $65.5 million of net proceeds from the issuance of common stock and a net $2.0 million of borrowings on our Credit Facility. In addition, the Company paid approximately $2.0 million in preferred stock dividends. See Note 8 in the Footnotes to the Financial Statements for additional information about the Company’s equity offering.

 

2015 capital expenditures

 

In early February 2015, we announced an operational capital budget for 2015 in the range of $150 to $165 million, on an accrual basis. The Company has updated its operational capital guidance to $160 million to $165 million, which reflects a higher level of capital cost reductions realized to date, offset by greater than expected drilling efficiencies and the Company’s expected funding of non-consenting partners during the year. 

 

We expect our 2015 horizontal drilling program will be primarily focused on program development of established Upper and Lower Wolfcamp B zones and the Lower Spraberry zones, in both the Southern and Central Midland Basin with lateral lengths ranging from approximately 5,000 feet to 10,000 feet.

 

In addition to the operational capital expenditures above, we budgeted a total of $17.2 million for (i) capitalized general and administrative expenses and (ii) certain retained plugging and abandonment costs related to divested Gulf of Mexico shelf assets.

 

We are the operator for 100% of our remaining 2015 capital program and, as a result, the amount and timing of these capital expenditures are largely discretionary depending on commodity prices and other factors. We currently expect to fund our 2015 capital program through a combination of the net proceeds from the issuance of common stock discussed above, cash flow from operations and borrowings under our Credit Facility and Term Loan.

 

 

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

Results of Operations

 

The following table sets forth certain operating information with respect to the Company’s oil and natural gas operations for the periods indicated:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended March 31,

 

 

 

2015

 

 

2014

 

 

Change

 

% Change

Net production:

 

 

 

 

 

 

 

 

 

 

 

  Oil (MBbls)

 

 

638 

 

 

332 

 

 

306 

 

92% 

  Natural gas (MMcf)