10-Q 1 cpe-20140331x10q.htm CPE - 10Q - FIRST QUARTER 2014 331cfd601d994b0

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

 

 

 

 

 

FORM 10-Q

 

 

 

 

 

QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For The Quarterly Period Ended March 31, 2014

OR

TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934

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)

 

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

 

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  

 

As of May 2, 2014,  40,449,884  shares of the Registrant’s common stock, par value $0.01 per share, were outstanding.

 

 

 


 

 

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 

16

 

 

Item 3.  Quantitative and Qualitative Disclosures about Market Risk 

24

 

 

Item 4.  Controls and Procedures 

25

 

 

Part II.  Other Information

 

 

 

Item 1.  Legal Proceedings 

26

 

 

Item 1A.  Risk Factors 

26

 

 

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

26

 

 

Item 3.  Defaults Upon Senior Securities 

26

 

 

Item 4.  Mine Safety Disclosures 

26

 

 

Item 5.  Other Information 

26

 

 

Item 6.  Exhibits 

27

 

 

 

2


 

 

DEFINITIONS

 

All defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily 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.

·

Bcf:  billion cubic feet.

·

BOE:  barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas.  The ratio of one barrel of oil or NGL to six Mcf of natural gas is commonly used in the industry and represents the approximate energy equivalence of oil or NGLs to natural gas, and does not represent the economic equivalency of oil and NGLs to natural gas. The sales price of a barrel of oil or NGLs is considerably higher than the sales price of six Mcf of natural gas.

·

BOE/d:  BOE per day.

·

Btu:  a British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.

·

LIBOR:  London Interbank Offered Rate.

·

LOE:  lease operating expense.

·

MBbls:  thousand barrels of oil.

·

MBOE:  thousand boe.

·

MBOE/d:  Mboe per day.

·

Mcf:  thousand cubic feet of natural gas.

·

Mcfe:  thousand cubic feet of natural gas equivalents.

·

Mcf/d:  Mcf per day.

·

MMBbls:  million barrels of oil.

·

MMBOE:  million BOE.

·

MMBtu:  million Btu.

·

MMcf:  million cubic feet of natural gas.

·

MMcf/d:  MMcf per day.

·

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


 

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, 2014

 

December 31, 2013

ASSETS

 

Unaudited

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

$

1,742 

 

$

3,012 

Accounts receivable

 

23,237 

 

 

20,586 

Fair market value of derivatives

 

 

 

60 

Deferred tax asset, current

 

6,320 

 

 

3,843 

Other current assets

 

1,356 

 

 

2,063 

Total current assets

 

32,655 

 

 

29,564 

Oil and natural gas properties, full-cost accounting method:

 

 

 

 

 

Evaluated properties

 

1,783,598 

 

 

1,701,577 

Less accumulated depreciation, depletion and amortization

 

(1,432,213)

 

 

(1,420,612)

Net oil and natural gas properties

 

351,385 

 

 

280,965 

Unevaluated properties excluded from amortization

 

36,772 

 

 

43,222 

Total oil and natural gas properties

 

388,157 

 

 

324,187 

Other property and equipment, net

 

7,413 

 

 

7,255 

Restricted investments

 

3,806 

 

 

3,806 

Deferred tax asset

 

54,047 

 

 

57,765 

Other assets, net

 

3,168 

 

 

1,376 

Total assets

$

489,246 

 

$

423,953 

LIABILITIES AND STOCKHOLDERS' EQUITY

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accounts payable and accrued liabilities

$

71,293 

 

$

57,637 

Asset retirement obligations

 

4,483 

 

 

4,120 

Fair market value of derivatives

 

2,645 

 

 

1,036 

Total current liabilities

 

78,421 

 

 

62,793 

13% Senior Notes:

 

 

 

 

 

  Principal outstanding

 

48,481 

 

 

48,481 

  Deferred credit, net of accumulated amortization of $26,673 and $26,239, respectively

 

4,834 

 

 

5,267 

Total 13% Senior Notes

 

53,315 

 

 

53,748 

Senior secured revolving credit facility

 

68,000 

 

 

22,000 

Asset retirement obligations

 

2,767 

 

 

2,612 

Other long-term liabilities

 

6,163 

 

 

3,706 

Total liabilities

 

208,666 

 

 

144,859 

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 and 60,000,000 shares authorized; 40,365,710 and 40,345,456 shares outstanding, respectively

 

405 

 

 

404 

Capital in excess of par value

 

403,136 

 

 

401,540 

Accumulated deficit

 

(122,977)

 

 

(122,866)

Total stockholders' equity

 

280,580 

 

 

279,094 

Total liabilities and stockholders' equity

$

489,246 

 

$

423,953 

 

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

 

4


 

Callon Petroleum Company

Consolidated Statements of Operations

(Unaudited; in thousands, except per share data)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended March 31,

 

 

 

2014

 

 

2013

Operating revenues:

 

 

 

 

 

 

  Oil sales

 

$

30,909 

 

$

19,540 

  Natural gas sales

 

 

2,376 

 

 

3,001 

Total operating revenues

 

 

33,285 

 

 

22,541 

  Operating expenses:

 

 

 

 

 

 

  Lease operating expenses

 

 

4,230 

 

 

5,576 

  Production taxes

 

 

1,917 

 

 

721 

  Depreciation, depletion and amortization

 

 

10,538 

 

 

11,042 

  General and administrative

 

 

10,807 

 

 

3,739 

  Accretion expense

 

 

228 

 

 

565 

  Gain on sale of other property and equipment

 

 

(1,080)

 

 

  Total operating expenses

 

 

26,640 

 

 

21,643 

  Income from operations

 

 

6,645 

 

 

898 

  Other (income) expenses:

 

 

 

 

 

 

  Interest expense

 

 

977 

 

 

1,515 

  Loss on derivative contracts

 

 

2,513 

 

 

418 

  Other (income) expense

 

 

(49)

 

 

(45)

  Total other expenses

 

 

3,441 

 

 

1,888 

  Income (loss) before income taxes

 

 

3,204 

 

 

(990)

     Income tax expense (benefit)

 

 

1,341 

 

 

(169)

     Income (loss) before equity in earnings of Medusa Spar  LLC

 

 

1,863 

 

 

(821)

  Equity in earnings of Medusa Spar LLC

 

 

 

 

21 

     Net income (loss)

 

 

1,863 

 

 

(800)

     Preferred stock dividends

 

 

(1,974)

 

 

 Loss available to common stockholders

 

$

(111)

 

$

(800)

 Loss per common share:

 

 

 

 

 

 

  Basic

 

$

(0.00)

 

$

(0.02)

  Diluted

 

$

(0.00)

 

$

(0.02)

  Shares used in computing loss per common share:

 

 

 

 

 

 

  Basic

 

 

40,328 

 

 

39,793 

  Diluted

 

 

40,328 

 

 

39,793 

 

 

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

 

5


 

Callon Petroleum Company

Consolidated Statements of Cash Flows

(Unaudited; in thousands)

 

 

 

 

 

 

 

 

 

 

Three Months Ended March 31

 

 

 

2014

 

 

2013

Cash flows from operating activities:

 

 

 

 

 

 

Net income

 

$

1,863 

 

$

(800)

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

 

 

 

 

 

 

  Depreciation, depletion and amortization

 

 

10,598 

 

 

11,393 

  Accretion expense

 

 

228 

 

 

565 

  Amortization of non-cash debt related items

 

 

119 

 

 

111 

  Amortization of deferred credit

 

 

(433)

 

 

(799)

  Equity in earnings of Medusa Spar LLC

 

 

 

 

(21)

  Deferred income tax expense

 

 

1,341 

 

 

(169)

  Net loss (gain) on derivatives, net of settlements

 

 

1,639 

 

 

1,039 

  Gain on sale of other property and equipment

 

 

(1,080)

 

 

  Non-cash expense related to equity share-based awards

 

 

996 

 

 

580 

  Change in the fair value of liability share-based awards

 

 

3,483 

 

 

(195)

  Payments to settle asset retirement obligations

 

 

(26)

 

 

(396)

  Changes in current assets and liabilities:

 

 

 

 

 

 

     Accounts receivable

 

 

(2,928)

 

 

1,333 

     Other current assets

 

 

707 

 

 

857 

     Current liabilities

 

 

5,155 

 

 

158 

  Payments to settle vested liability share-based awards

 

 

(1,669)

 

 

  Change in other long-term liabilities

 

 

 

 

(206)

  Change in other assets, net

 

 

(26)

 

 

(575)

     Net cash provided by operating activities

 

 

19,967 

 

 

12,875 

Cash flows from investing activities:

 

 

 

 

 

 

Capital expenditures

 

 

(65,760)

 

 

(30,089)

Proceeds from sales of mineral interest and equipment

 

 

2,226 

 

 

114 

Distribution from Medusa Spar LLC

 

 

 

 

340 

    Net cash used in investing activities

 

 

(63,534)

 

 

(29,635)

Cash flows from financing activities:

 

 

 

 

 

 

Borrowings on credit facility

 

 

46,000 

 

 

17,000 

Payment of deferred financing costs

 

 

(1,729)

 

 

Payment of preferred stock dividends

 

 

(1,974)

 

 

     Net cash provided by financing activities

 

 

42,297 

 

 

17,000 

Net change in cash and cash equivalents

 

 

(1,270)

 

 

240 

  Balance, beginning of period

 

 

3,012 

 

 

1,139 

  Balance, end of period

 

$

1,742 

 

$

1,379 

 

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

 

6


 

Callon Petroleum Company

Notes to the Consolidated Financial Statements

(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)

 

INDEX TO THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

 

 

 

1. 

Description of Business and Basis of Presentation

6.

Fair Value Measurements

2. 

Oil and Natural Gas Properties

7.

Income Taxes

3. 

Earnings Per Share

8.

Asset Retirement Obligations

4. 

Borrowings

9.

Preferred Stock

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 oil and natural gas reserves in the Permian Basin in West Texas. In late 2013, with the sale of its remaining offshore assets in the Gulf of Mexico, the Company completed the onshore strategic repositioning it initiated in 2009. 

 

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) accounting principles generally accepted in the United States (“US GAAP”), (2) the Securities and Exchange Commission’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, 2013. The balance sheet at December 31, 2013 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, 2014.

 

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. When necessary to ensure consistent presentation, certain prior year amounts may be reclassified. Certain prior year amounts have been reclassified to conform to current year presentation.

 

 

 

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

 

Note 2 – Oil and Natural Gas Properties

 

Acquisitions

 

In the first quarter of 2014, the Company acquired 1,527 net acres in Upton and Reagan Counties, Texas, which are located in the southern portion of the Midland Basin near our existing core development fields, for an aggregate cash purchase price of $8,200. The properties bear a working interest of 100% and an average net revenue interest of 78%.

 

Acreage Expiration

 

During the first quarter of 2014, the Company transferred $9,855 from unevaluated properties to the full cost pool related to 5,924 net acres in the Northern Midland Basin  that expired or are scheduled to expire in the near future and are no longer included in the Company’s exploration and development plans. The Company continues to narrow its focus acreage for continued exploration and delineation efforts, which remains focused on horizontal development drilling in the Southern and Central portions of the Midland Basin. As of March 31, 2014, Callon has a remaining net acreage position in the Northern Midland Basin of 11,857 acres for which the Company is still evaluating potential future exploration activities.

 

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,

 

 

 

2014

 

 

2013

Net income (loss)

 

$

1,863 

 

$

(800)

Preferred stock dividends

 

 

(1,974)

 

 

Loss available to common stockholders

 

$

(111)

 

$

(800)

 

 

 

 

 

 

 

Weighted average shares outstanding

 

 

40,328 

 

 

39,793 

Weighted average shares outstanding for diluted net loss per share

 

 

40,328 

 

 

39,793 

 

 

 

 

 

 

 

Basic loss per share

 

$

(0.00)

 

$

(0.02)

Diluted loss per share

 

$

(0.00)

 

$

(0.02)

 

 

 

 

 

 

 

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

Stock options

 

 

40 

 

 

67 

Restricted stock

 

 

 

 

40 

 

 

 

Note 4 – Borrowings

 

The Company’s borrowings consisted of the following at:

 

 

 

 

 

 

 

 

 

 

March 31, 2014

 

December 31, 2013

Principal components:

 

 

 

 

 

 

Credit Facility

 

$

68,000 

 

$

22,000 

13% Senior Notes, principal

 

 

48,481 

 

 

48,481 

Total principal outstanding

 

 

116,481 

 

 

70,481 

13% Senior Notes unamortized deferred credit

 

 

4,834 

 

 

5,267 

Total carrying value of borrowings

 

$

121,315 

 

$

75,748 

 

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. The total amount available under the Credit Facility is $500,000,  with an initial associated borrowing base of $95,000 and a maturity 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. Amounts borrowed under the Credit Facility may not exceed the borrowing base, which is

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

 

generally reviewed on a semi-annual basis. The first redetermination is scheduled with an effective date of May 30, 2014, with subsequent redeterminations occurring every six months beginning on September 1, 2014. The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties.

 

As of March 31, 2014, the balance outstanding on the Credit Facility was $68,000 with a weighted interest rate of 2.41%, calculated as the London Interbank Offered Rate (“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.

 

Second Lien Term Loan Facility (the “Second Lien Facility”)

 

The Company also entered into the Second Lien Facility in an aggregate amount of up to $125,000,  including initial commitments of $100,000 and additional availability of $25,000 subject to the consent of two-thirds of the lenders and compliance with financial covenants after giving effect to such increase. The Second Lien Facility, matures on September 11, 2019, and is not subject to mandatory prepayments unless new debt is issued. The Second Lien Facility may be prepaid at our option if we pay a prepayment premium. The prepayment premium is (i) 102% if the prepayment event occurs prior to March 11, 2015, and (ii) 101% if the prepayment event occurs on or after March 15, 2015 but before March 15, 2016, and (iii) 100% for prepayments made on or after March 15, 2016. The Second Lien Facility is secured by junior liens on properties mortgaged under the Credit Facility, subject to an intercreditor agreement.

 

There were no outstanding balances on the Second Lien Facility as of March 31, 2014. The initial draw amount of $62,500 was made on April 10, 2014 with an original issue discount of 1.0%. Subsequent draws, allowable during the first year, are subject to the same 1.0% original issue discount on the drawn amount, applied on the date such draw is funded. Beginning on April 10, 2014, the interest rate is 8.75%, calculated at a rate of LIBOR (subject to a floor rate of 1.0%) plus 7.75% per annum. In addition, the Second Lien Facility carries a commitment fee of 0.5% per annum, payable quarterly, on the unused portion of the initial commitment amount until March 11, 2015.

 

13% Senior Notes due 2016 (“Senior Notes”) and Deferred Credit

 

On April 11, 2014, the Company completed a full redemption of the remaining $48,481 principal amount of outstanding Senior Notes using proceeds from the Second Lien Facility. The redemption, which will be accounted for in the quarter ending June 30, 2014, will result in a net $3,204 gain on the early extinguishment of debt (including $4,780 of accelerated deferred credit amortization). The gain represents the difference between the $50,047 paid for the redemption of the Senior Notes ($1,576 of redemption costs, primarily the call premium) and the carrying value of the remaining Senior Notes of $53,261 (inclusive of $4,780 of deferred credit). The Company also paid  $193 for accrued interest through the redemption date. Upon the redemption, the indenture governing the Senior Notes was discharged in accordance with its terms.

 

Interest on the Senior Notes was payable on the last day of each quarter. Certain of the Company’s subsidiaries guaranteed the Company’s obligations under the Senior Notes. The subsidiary guarantors were 100% owned, all of the guarantees were full and unconditional and joint and several, the parent company had no independent assets or operations, and any subsidiaries of the parent company other than the subsidiary guarantors were minor. Upon issuing the Senior Notes in November 2009, the Company recorded as a deferred credit the $31,507 difference between the adjusted carrying amount of the previous Senior Notes that were exchanged and the principal of the new Senior Notes. This deferred credit was being amortized as a reduction of interest expense over the life of the Senior Notes at an 8.5% effective interest rate.

 

As of March 31, 2014,  the deferred credit balance was $4,834, net of $26,673 of amortization through that date. Amortization recorded as a reduction of interest expense for the quarter ended March 31, 2014 was $433.

 

Restrictive Covenants

 

The indentures governing the Senior Notes, Credit Facility and Second Lien Facility contain various covenants including restrictions on additional indebtedness and payment of cash dividends. In addition, the Credit Facility and Second Lien Facility contain covenants for maintenance of certain financial ratios. The Company was in compliance with these covenants at March 31, 2014.

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

 

 

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 collar, swap, put, call 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 transactions 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 a derivative instruments’ fair value; see Note 6 for additional information regarding fair value.

 

The Company executes commodity derivative transactions under master agreements that have netting provisions that provide for offsetting payables against receivables. 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 New York Mercantile Exchange (“NYMEX”) price. To determine the fair value of the Company’s derivative instruments, depending on the type of instrument, the Company utilizes present value methods or standard option valuation models 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 has elected not to designate its derivative contracts as accounting hedges under Accounting Standards Codification 815. Consequently, the Company records its derivative contracts at their fair values on the balance sheet and marks-to-market these contracts at the end of each period. The Company records changes in fair values as a gain or loss on the statement of operations as a component of gain (loss) on derivative contracts. The gain (loss) on derivative contracts in the statement of operations includes the mark-to-market adjustments on outstanding contracts and the impact of cash settlements.

 

The following table reflects the fair values 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

 

03/31/2014

 

12/31/2013

 

03/31/2014

 

12/31/2013

 

03/31/2014

 

12/31/2013

Natural gas

 

Current

 

Fair market value of derivatives

 

$

 

$

60 

 

$

(160)

 

$

 

$

(160)

 

$

60 

Natural gas

 

Non-current

 

Other long-term liabilities

 

 

 

 

 

 

(41)

 

 

(72)

 

 

(41)

 

 

(72)

Oil

 

Current

 

Fair market value of derivatives

 

 

 

 

 

 

(2,485)

 

 

(1,036)

 

 

(2,485)

 

 

(1,036)

 

 

Totals

 

 

 

$

 

$

60 

 

$

(2,686)

 

$

(1,108)

 

$

(2,686)

 

$

(1,048)

 

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

 

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 based on the underlying commodity being hedged. The following presents the impact of this presentation to the Company’s recognized assets and liabilities at March 31, 2014:

 

 

 

 

 

 

 

 

 

 

 

 

Presented without

 

 

 

As Presented with

 

 

Effects of Netting

 

Effects of Netting

 

Effects of Netting

Current assets: Fair value of hedging contracts

 

$

59 

 

$

(59)

 

$

Current liabilities: Fair market value of derivatives

 

 

(2,704)

 

 

59 

 

 

(2,645)

Long-term liabilities: Fair market value of derivatives

 

 

(41)

 

 

 

 

(41)

 

For the periods indicated, the Company recorded the following related to its derivatives in the statement of operations as gain or loss on derivative contracts:

 

 

 

 

 

 

 

 

 

Three Months Ended March 31

 

 

 

2014

 

 

2013

Natural gas derivatives

 

 

 

 

 

 

Net gain (loss) on settlements

 

$

(102)

 

$

49 

Net gain (loss) on mark-to-market adjustments

 

 

(190)

 

 

(388)

Total loss

 

$

(292)

 

$

(339)

 

 

 

 

 

 

 

Oil derivatives

 

 

 

 

 

 

Net gain (loss) on settlements

 

$

(773)

 

$

573 

Net gain (loss) on mark-to-market adjustments

 

 

(1,448)

 

 

(652)

Total loss

 

$

(2,221)

 

$

(79)

 

 

 

 

 

 

 

Total loss on derivative instruments

 

$

(2,513)

 

$

(418)

 

Derivative positions

 

Listed in the table below are the outstanding oil and natural gas derivative contracts as of March 31, 2014 (volumes in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity

 

Instrument

 

Average Notional Volumes per Month (000s)

 

Quantity Type

 

Strike Price

 

Swap Price

 

Period

Natural gas

 

Swap

 

61

 

MMBtu

 

 

       n/a

 

$

4.25 

 

Apr14 - Dec14

Natural gas

 

Call Option (sold)

 

37

 

MMBtu

 

$

5.00 

 

 

          n/a

 

Jan15 - Dec15

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

Swap

 

30

 

Bbls

 

 

       n/a

 

$

93.35 

 

Apr14 - Dec14

Oil

 

Put Option (sold)

 

30

 

Bbls

 

$

70.00 

 

 

          n/a

 

Apr14 - Dec14

Oil

 

Swap

 

9

 

Bbls

 

 

       n/a

 

$

94.58 

 

Apr14 - Dec14

Oil

 

Swap

 

15

 

Bbls

 

 

       n/a

 

$

92.80 

 

Apr14 - Jun14

Oil

 

Swap

 

15

 

Bbls

 

 

       n/a

 

$

90.40 

 

Jul14 - Sep14

Oil

 

Swap

 

15

 

Bbls

 

 

       n/a

 

$

88.35 

 

Oct14 - Dec14

 

Excluded from the table above are offsetting natural gas long and short call options of 38,000 MMBtu per month for the period Apr14 – Dec14, each at a strike price of $4.75 per MMBtu.

 

The following derivative contracts were executed subsequent to March 31, 2014 (volumes in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity

 

Instrument

 

Average Notional Volumes per Month (000s)

 

Quantity Type

 

Strike Price

 

Swap Price

 

Period

Oil

 

Swap

 

31

 

Bbls

 

 

       n/a

 

$

99.87 

 

Jul14 - Sep14

Oil

 

Swap

 

21

 

Bbls

 

 

       n/a

 

$

96.92 

 

Oct14 - Dec14

 

 

 

 

 

 

 

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

 

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 on its Consolidated Balance Sheet. The fair value of Callon’s fixed-rate debt, which is valued using Level 2 inputs, is based upon estimates provided by an independent investment banking firm. The carrying amount of floating-rate debt approximates fair value because the interest rates are variable and reflective of market rates.

 

The following table summarizes the respective carrying and fair values at:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

`

 

 

 

 

 

March 31, 2014

 

December 31, 2013

 

 

Carrying Value

 

Fair Value

 

 

Carrying Value

 

Fair Value

Credit Facility

 

$

68,000 

 

$

68,000 

 

$

22,000 

 

$

22,000 

13% Senior Notes due 2016 (a)

 

 

53,315 

 

 

50,420 

 

 

53,748 

 

 

50,299 

Total

 

$

121,315 

 

$

118,420 

 

$

75,748 

 

$

72,299 

 

 (a) Fair value is calculated only in relation to the $48,481 and $48,481 principal outstanding of the Senior Notes at the dates indicated above, respectively. The remaining $4,834 and $5,267, respectively, which the Company has recorded as a deferred credit, is excluded from the fair value calculation, and will be recognized in earnings as a reduction of interest expense over the remaining amortization period. See Note 4 for additional information.

 

Assets and Liabilities Measured at Fair Value on a Recurring Basis

 

Certain assets and liabilities are reported at fair value on a recurring basis (unless otherwise noted below) in Callon’s consolidated balance sheet. The following methods and assumptions were used to estimate the fair values:

 

Commodity Derivative Instruments. The fair value of commodity derivative instruments is derived using a valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract, and the values are corroborated by quotes obtained from counterparties to the agreements. 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.

 

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

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

March 31, 2014

 

Balance Sheet Presentation

 

 

Level 1

 

 

Level 2

 

 

Level 3

 

 

Total

Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivative financial instruments (current)

 

Fair market value of derivatives

 

$

 

$

2,645 

 

$

 

$

2,645 

Derivative financial instruments (non-current)

 

Other long-term liabilities

 

 

 

 

41 

 

 

 

 

41 

Total net liability

 

 

 

$

 

$

(2,686)

 

$

 

$

(2,686)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2013

 

Balance Sheet Presentation

 

 

Level 1

 

 

Level 2

 

 

Level 3

 

 

Total

Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivative financial instruments (current)

 

Fair market value of derivatives

 

$

 

$

60 

 

$

 

$

60 

    Sub-total assets

 

 

 

 

 

 

60 

 

 

 

 

60 

Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivative financial instruments (current)

 

Fair market value of derivatives

 

$

 

$

1,036 

 

$

 

$

1,036 

Derivative financial instruments (non-current)

 

Other long-term liabilities

 

 

 

 

72 

 

 

 

 

72 

    Sub-total liabilities

 

 

 

$

 

$

1,108 

 

$

 

$

1,108 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total net liability

 

 

 

$

 

$

(1,048)

 

$

 

$

(1,048)

 

The derivative fair values above are based on analysis of each contract. Derivative assets and liabilities with the same counterparty are presented here on a gross basis, even where the legal right of offset exists. See Note 5 for a discussion of net amounts recorded in the consolidated balance sheet at March 31, 2014.

 

Note 7 - Income Taxes 

 

The Company provides for income taxes at a statutory rate of 35% adjusted for permanent differences expected to be realized, which primarily relate to statutory depletion, non-deductible executive compensation expenses and state income taxes. The effective tax rate for the three months ended March 31, 2014 and 2013  was 42% and  17%, respectively.

 

Note 8 - Asset Retirement Obligations 

 

The table below summarizes the Company’s asset retirement obligations activity for the three months ended March 31, 2014: 

 

 

 

 

 

 

 

 

Asset retirement obligations at January 1, 2014

 

$

6,732 

Accretion expense

 

 

228 

Liabilities incurred

 

 

272 

Revisions to estimate

 

 

18 

Asset retirement obligations at end of period

 

 

7,250 

Less: Current asset retirement obligations

 

 

4,483 

Long-term asset retirement obligations at March 31, 2014

 

$

2,767 

 

Certain of the Company’s operating agreements require that assets be restricted for abandonment obligations. Amounts recorded on the consolidated balance sheets as restricted investments were $3,806 at March 31, 2014 and December 31, 2013. These investments include primarily U.S. Government securities, and are held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s oil and natural gas properties.

 

 

Note 9Preferred 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. For the quarter ended March 31, 2014, the Board declared a dividend of $1.25 per share, or a total of $1,974, on the Company’s Preferred Stock.

 

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

 

As defined in a provision of the Preferred Stock prospectus, the common shares reserved for issuance vary based on the number of authorized common shares. In January 2014, following a majority shareholder vote, the number of authorized shares of common stock was increased from 60,000,000 to 110,000,000 with a corresponding increase in the number of common shares reserved for a potential conversion to a maximum of 42,200,000 shares. Based on the Company’s closing common stock price of $8.37 per share on March 31, 2014, the Company reserved 9,432,186  shares to satisfy the potential conversion.

 

Note 10 – Other

 

Operating Leases

 

In April 2012, the Company contracted a drilling rig (the “Cactus 1 Rig”) for a term of two years, which it subsequently renewed in March 2014 for an additional two year term ending April 2016. In April 2014, the Company contracted an additional horizontal drilling rig (the “Cactus 2 Rig”) for a term of two years ending April 2016. The Cactus 2 Rig replaced a previously contracted horizontal drilling rig, which was cancelled in March 2014. The Cactus 1 and Cactus 2 Rig lease agreements include early termination provisions that would reduce the minimum rentals under the agreement, and also include early termination payments that would be reduced assuming the lessor is able to re-charter the rig and staffing personnel to another lessee. Lease payments in 2014,  2015 and 2016 are expected to approximate $18,015 (with $13,758 remaining at March 31, 2014), $18,250 and $4,795, respectively.  

 

Other Property and Equipment

 

As disclosed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2013, the Company made a decision to abandon certain specialized deep water property and equipment received as part of a prior settlement agreement related to various disputes with a previous joint interest partner as a result of the unsuccessful marketing of such assets.  Accordingly, the Company recognized an impairment charge of $1,707 related to such property and equipment in the year ended December 31, 2013.  Subsequent to the filing of the Annual Report on Form 10-K, the Company entered into an agreement to sell the property and equipment to a third party.  While the third party had previously performed some initial inspection and evaluation of the equipment, based on the amount of time the equipment had been unsuccessfully marketed and the feedback from potential buyers, management concluded the likelihood of completing a sale of the equipment was low, resulting in the decision to abandon the equipment and recognize an impairment charge in 2013. As a result of the subsequent sale of the property and equipment, the Company recognized a gain of $1,080 in the first quarter 2014.

 

 

 

14


 

Special Note Regarding Forward Looking Statements

 

All statements, other than historical fact or present financial information, 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 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 Securities and Exchange Commission.

 

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, 2013 (the 2013 Annual Report on Form 10-K”), and all quarterly reports on Form 10-Q filed subsequently thereto (“Form 10-Qs”).

 

Should one or more of the risks or uncertainties described above or in our 2013 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 (continued)

 

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 2013 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 are 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 85% oil and 15%  natural gas for the three months ended March 31, 2014.  On March 31, 2014, our net acreage position in the Permian Basin was approximately 25,481 net acres. 

 

Recent Developments

 

·

Acquired 1,527 net acres in Upton and Reagan Counties, in close proximity to our existing East Bloxom and Garrison Draw fields for a combined purchase price of $8.2 million

·

Established production from two Wolfcamp B horizontal wells in the Carpe Diem field, increasing our core horizontal development areas to four fields

·

Closed a $500 million revolving credit facility with a present borrowing base of $95 million and a $125 million second lien term loan facility with initial availability of $100 million

·

Completed the full redemption of our Senior Notes due 2016 in April 2014

 

Operational Highlights

 

Following the sale of our remaining offshore and Haynesville properties in the fourth quarter of 2013, all of our producing properties are located in the Permian Basin. Our Permian production grew 176% in the first quarter of 2014 compared to the same period of 2013, increasing to 392 MBOE from 142 MBOE, respectively.

 

 

 

 

 

 

 

 

 

 

 

 

Net Production (MBOE)

 

 

Three Months Ended March 31

 

 

2014

 

2013

 

Change

 

% Change

Onshore:

 

 

 

 

 

 

 

 

Southern Midland Basin

 

315 

 

93 

 

222 

 

239% 

Central Midland Basin

 

71 

 

49 

 

22 

 

46% 

Northern Midland Basin

 

 

 

 

Total Permian

 

392 

 

142 

 

250 

 

176% 

 

 

 

 

 

 

 

 

 

Offshore and other (a)

 

 

195 

 

(186)

 

(95)%

 

 

 

 

 

 

 

 

 

Total

 

392 

 

328 

 

64 

 

20% 

 

(a)

In late 2013, we sold the remaining interest in our offshore fields and Haynesville shale.

16


 

Table of Contents

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

 

The following table sets forth productive wells as of March 31, 2014:

 

 

 

 

 

 

 

 

 

 

 

 

Oil Wells

 

Natural Gas Wells

 

 

Gross

 

Net

 

Gross

 

Net

Working interest

 

133 

 

112.4 

 

 

Royalty interest

 

 

0.0 

 

 

Total

 

136 

 

112.4 

 

 

 

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 Mcfe basis. However, most of our wells produce both oil and natural gas.

 

The following table summarizes the Company’s drilling progress in the Permian Basin for the three months ended March 31, 2014:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Drilled

 

Completed (a)

 

Awaiting Completion

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

Southern Midland Basin

 

 

 

 

 

 

 

 

 

 

 

 

Vertical wells

 

 

1.0 

 

 

1.0 

 

 

Horizontal wells

 

 

7.3 

 

 

5.0 

 

 

2.3 

Total

 

 

8.3 

 

 

6.0 

 

 

2.3 

 

 

 

 

 

 

 

 

 

 

 

 

 

Central Midland Basin

 

 

 

 

 

 

 

 

 

 

 

 

Vertical wells

 

 

0.4 

 

 

 

 

0.4 

Horizontal wells

 

 

0.8 

 

 

1.7 

 

 

0.8 

Total

 

 

1.3 

 

 

1.7 

 

 

1.3 

 

 

 

 

 

 

 

 

 

 

 

 

 

Northern Midland Basin

 

 

 

 

 

 

 

 

 

 

 

 

Vertical wells

 

 

1.5 

 

 

0.8 

 

 

Total

 

 

1.5 

 

 

0.8 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total vertical wells

 

 

2.9 

 

 

1.8 

 

 

0.4 

Total horizontal wells

 

 

8.1 

 

 

6.7 

 

 

3.1 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

13 

 

11.0 

 

 

8.4 

 

 

3.5 

(a)

Completions include wells drilled prior to 2014.

 

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.

 

Based upon current commodity price expectations for 2014, we believe that our cash flow from operations and borrowings under our Credit Facility and Second Lien Facility will be sufficient to fund our operations for 2014, including any deficiencies in the Company’s current net working capital. However, future cash flows are subject to a number of variables, including forecasted production volumes and commodity prices. Our 2014 capital program is 100% operated and, as a result, the amount and timing of a large portion of our planned capital expenditures are largely discretionary in the event we needed to curtail drilling and completion operations due to capital constraints.

 

We recently entered into an amended Credit Facility and Second Lien Facility to support the funding of our ongoing operations and acquisition initiatives, which are discussed in greater detail in Note 4 to the Consolidated Financial Statements. In addition, we regularly evaluate other sources of capital, including debt and equity securities, to complement our cash flow from operations and other sources of capital as we pursue our long-term growth plans in the Permian Basin.

 

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

 

Cash and cash equivalents decreased $1.3 million in the first quarter of 2014 to $1.7 million compared to $3.0 million at December 31, 2013. At March 31, 2014, our available liquidity, inclusive of undrawn amounts on our Credit Facility ($27.0 million) and Second Lien Facility ($100.0 million), increased to $128.7 million,  a $64.7 million increase over year-end 2013.

 

Liquidity and Cash Flow

 

 

 

 

 

 

 

 

 

For the Quarter Ended March 31

 

 

2014

 

2013

Net cash provided by operating activities

 

$

20.0 

 

$

12.9 

Net cash used in investing activities

 

 

(63.5)

 

 

(29.6)

Net cash provided by (used in) financing activities

 

 

42.3 

 

 

17.0 

Net change in cash

 

$

(1.3)

 

$

0.2 

 

Operating Activities.  For the three months ended March 31, 2014, net cash provided by operating activities was $20.0 million, compared to $12.9 million for the same period in 2013.  The increase was primarily due to an increase in oil sales and a reduction in lease operating expense, partially offset by losses on derivatives, settled and an increase in production taxes. Production and realized prices are discussed below in Results of Operations. See Notes 5 and 6 for 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, 2014, net cash used in investing activities was $63.5 million as compared to $29.6 million for the same period in 2013.  The $36.1 million increase in cash used in investing activities was primarily attributable to a $25.0 million increase in drilling and completion activities in the Permian Basin driven by the addition of a second horizontal drilling rig in August 2013. In addition, the Company completed $8.2 million of acquisitions in the first three months of 2014, with no acquisition completed in the comparable 2013 period.

 

Capital expenditures for the three months ended March 31, 2014 include the following (in millions):

 

 

 

 

 

Southern Midland Basin

 

$

37 

Central Midland Basin

 

 

14 

Northern Midland Basin

 

 

Total operational expenditures

 

 

53 

 

 

 

 

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

 

 

Capitalized interest

 

 

Total capitalized expenses

 

 

 

 

 

 

Total operational expenditures inclusive of capitalized amounts

 

 

58 

 

 

 

 

Acquisitions

 

 

Total capital expenditures

 

$

66 

 

Financing Activities.  For the three months ended March 31, 2014, net cash provided by financing activities was $42.3 million compared to cash provided by financing activities of $17.0 million during the same period of 2013. Net cash provided by financing activities during the three months ended March 31, 2014 included a net $46 million of borrowings on our Credit Facility offset by approximately $2.0 million in preferred stock dividends.

 

2014 Capital Expenditures 

 

Our 2014 operational capital budget approximates $185 million, excluding $8 million of acquisitions completed in 2014 (see Note 2). This budgeted amount includes plans to drill up to 27 horizontal and nine vertical wells, while completing 26 horizontal and eight vertical wells. In the first quarter of 2014, we began testing larger horizontal well completion designs in an effort to improve production rates and the amount of recoverable resources. Based on satisfactory drilling, completion and well performance to date, we believe that these enhanced completion designs create the potential for increased total returns on

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

 

capital after adjusting for incremental costs of approximately $0.5 million to $0