UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
x
Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
 
For the quarterly period ended:
September 30, 2013
 
or
 
o
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
(I.R.S. 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 the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes x
 
No o

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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes x
 
No o

Indicate by check mark whether the registrant is a larger accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company.  See definition of “accelerated filer”, “large accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer o
Accelerated filer x
 
 
Non-accelerated filer o
Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o
 
No x

As of November 1, 2013 there were outstanding 40,345,456 shares of the Registrant’s common stock, par value $0.01 per share.





Table of Contents
Part I. Financial Information
 
 
 
Item 1. Financial Statements (Unaudited)
 
 
 
Consolidated Balance Sheets  (Unaudited)
 
 
Consolidated Statements of Operations (Unaudited)
 
 
Consolidated Statements of Comprehensive Income (Loss) (Unaudited)
 
 
Consolidated Statements of Cash Flows (Unaudited)
 
 
Notes to Consolidated Financial Statements (Unaudited)
 
 
Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
 
Item 3.  Quantitative and Qualitative Disclosures about Market Risk
 
 
Item 4.  Controls and Procedures
 
 
Part II.  Other Information
 
 
 
Item 1.  Legal Proceedings
 
 
Item 1A.  Risk Factors
 
 
Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds
 
 
Item 3.  Defaults Upon Senior Securities
 
 
Item 4.  Mine Safety Disclosures
 
 
Item 5.  Other Information
 
 
Item 6.  Exhibits
 
 


2

Table of Contents



Part I. Financial Information
Item I. Financial Statements
Callon Petroleum Company
Consolidated Balance Sheets
(in thousands, except per share data)
 
September 30, 2013
 
December 31, 2012
ASSETS
Unaudited
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
869

 
$
1,139

Accounts receivable
20,072

 
15,608

Fair market value of derivatives

 
1,674

Deferred tax asset
3,323

 

Other current assets
1,738

 
1,502

Total current assets
26,002

 
19,923

Oil and natural gas properties, full-cost accounting method:
 
 
 
Evaluated properties
1,634,151

 
1,497,010

Less accumulated depreciation, depletion and amortization
(1,329,866
)
 
(1,296,265
)
Net oil and natural gas properties
304,285

 
200,745

Unevaluated properties excluded from amortization
50,540

 
68,776

Total oil and natural gas properties
354,825

 
269,521

 
 
 
 
Other property and equipment, net
10,635

 
10,058

Restricted investments
3,800

 
3,798

Investment in Medusa Spar LLC
7,776

 
8,568

Deferred tax asset
60,198

 
64,383

Other assets, net
4,205

 
1,922

Total assets
$
467,441

 
$
378,173

 
 
 
 
LIABILITIES AND STOCKHOLDERS' EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued liabilities
$
49,384

 
$
36,016

Asset retirement obligations
6,002

 
2,336

Fair market value of derivatives
1,139

 
125

Total current liabilities
56,525

 
38,477

13% Senior Notes:
 
 
 
Principal outstanding
96,961

 
96,961

Deferred credit, net of accumulated amortization of $20,248 and $17,800, respectively
11,259

 
13,707

Total 13% Senior Notes
108,220

 
110,668

 
 
 
 
Senior secured revolving credit facility
17,000

 
10,000

Asset retirement obligations
5,505

 
10,965

Other long-term liabilities
3,579

 
2,092

Total liabilities
190,829

 
172,202

Stockholders' equity:
 
 
 
Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500 shares authorized: 1,579 and 0 shares outstanding, respectively
16

 

Common stock, $0.01 par value, 60,000 shares authorized; 40,328 and 39,801 shares outstanding, respectively
405

 
398

Capital in excess of par value
400,348

 
328,116

Retained deficit
(124,157
)
 
(122,543
)
Total stockholders' equity
276,612

 
205,971

Total liabilities and stockholders' equity
$
467,441

 
$
378,173


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

3

Table of Contents


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

 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2013
 
2012
 
2013
 
2012
Operating revenues:
 
 
 
 
 
 
 
 
Crude oil sales
 
$
27,014

 
$
24,061

 
$
65,615

 
$
71,883

Natural gas sales
 
3,783

 
3,341

 
10,483

 
10,174

Total operating revenues
 
30,797

 
27,402

 
76,098

 
82,057

 
 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
 
Lease operating expenses
 
5,270

 
5,203

 
16,412

 
18,687

Production taxes
 
991

 
656

 
2,217

 
1,778

Depreciation, depletion and amortization
 
11,907

 
11,965

 
33,603

 
35,998

General and administrative
 
5,826

 
6,441

 
14,110

 
15,846

Accretion expense
 
458

 
574

 
1,556

 
1,709

Total operating expenses
 
24,452

 
24,839

 
67,898

 
74,018

 
 
 
 
 
 
 
 
 
Income from operations
 
6,345

 
2,563

 
8,200

 
8,039

 
 
 
 
 
 
 
 
 
Other (income) expenses:
 
 
 
 
 
 
 
 
Interest expense
 
1,417

 
2,135

 
4,469

 
7,096

Gain on early extinguishment of debt
 

 

 

 
(1,366
)
Loss (gain) on derivative contracts
 
3,686

 
1,598

 
2,123

 
(1,977
)
Other (income) expense, net
 
(279
)
 
237

 
(368
)
 
(224
)
Total other (income) expenses, net
 
4,824

 
3,970

 
6,224

 
3,529

 
 
 
 
 
 
 
 
 
Income (loss) before income taxes
 
1,521

 
(1,407
)
 
1,976

 
4,510

Income tax expense (benefit)
 
456

 
(246
)
 
950

 
1,508

Income (loss) before equity in earnings of Medusa Spar LLC
 
1,065

 
(1,161
)
 
1,026

 
3,002

Equity in earnings of Medusa Spar LLC
 
17

 
56

 
14

 
180

Net income (loss)
 
1,082

 
(1,105
)
 
1,040

 
3,182

Preferred stock dividends
 
(1,974
)
 

 
(2,654
)
 

Net income (loss) available to common shareholders
 
$
(892
)
 
$
(1,105
)
 
$
(1,614
)
 
$
3,182

 
 
 
 
 
 
 
 
 
Net income (loss) per common share:
 
 
 
 
 
 
 
 
Basic
 
$
(0.02
)
 
$
(0.03
)
 
$
(0.04
)
 
$
0.08

Diluted
 
$
(0.02
)
 
$
(0.03
)
 
$
(0.04
)
 
$
0.08

 
 
 
 
 
 
 
 
 
Shares used in computing net income (loss) per common share:
 
 
 
 
 
 
 
 
Basic
 
40,321

 
39,575

 
40,064

 
39,441

Diluted
 
40,321

 
39,575

 
40,064

 
40,243


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

4

Table of Contents

Callon Petroleum Company
Consolidated Statements of Comprehensive Income (Loss)
(Unaudited; in thousands)

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2013
 
2012
 
2013
 
2012
Net income (loss)
$
1,082

 
$
(1,105
)
 
$
1,040

 
$
3,182

Other comprehensive (loss) income:
 
 
 
 
 
 
 
     Change in fair value of derivatives designated as hedges,

 
(1,268
)
 

 
(1,345
)
     net of tax (See Note 5)
 
 
 
 
 
 
 
Comprehensive income (loss)
1,082

 
(2,373
)
 
1,040

 
1,837

Preferred stock dividends
(1,974
)
 

 
(2,654
)
 

Comprehensive income (loss) available to common shareholders
$
(892
)
 
$
(2,373
)
 
$
(1,614
)
 
$
1,837


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


5

Table of Contents

Callon Petroleum Company
Consolidated Statements of Cash Flows
(Unaudited; in thousands)

 
Nine Months Ended September 30,
 
2013
 
2012
Cash flows from operating activities:
 
 
 
Net income
$
1,040

 
$
3,182

Adjustments to reconcile net income to cash provided by operating activities:
 
 
 
Depreciation, depletion and amortization
34,668

 
37,005

Accretion expense
1,556

 
1,709

Amortization of non-cash debt related items
348

 
293

Amortization of deferred credit
(2,448
)
 
(2,304
)
Non-cash gain on early extinguishment of debt

 
(1,366
)
Equity in earnings of Medusa Spar LLC
(14
)
 
(180
)
Deferred income tax expense
950

 
1,508

Unrealized loss (gain) on derivative contracts
2,929

 
(2,017
)
Non-cash expense related to equity share-based awards
1,335

 
752

Change in the fair value of liability share-based awards
1,076

 
2,611

Payments to settle asset retirement obligations
(701
)
 
(1,136
)
Changes in current assets and liabilities:
 
 
 
     Accounts receivable
(3,455
)
 
(1,260
)
     Other current assets
(236
)
 
244

     Current liabilities
1,969

 
4,965

     Payments to settle vested liability share-based awards
(239
)
 
(1,462
)
     Change in natural gas balancing receivable
(206
)
 
(96
)
     Change in natural gas balancing payable
(52
)
 
(152
)
     Change in other long-term liabilities
(206
)
 

     Change in other assets, net
(3,100
)
 
(911
)
Cash provided by operating activities
$
35,214

 
$
41,385

 
 
 
 
Cash flows from investing activities:
 
 
 
Capital expenditures
(101,067
)
 
(115,401
)
Acquisition
(11,000
)
 

Proceeds from sale of mineral interest and equipment
1,389

 
526

Distribution from Medusa Spar LLC
813

 
1,423

Cash used in investing activities
$
(109,865
)
 
$
(113,452
)
 
 
 
 
Cash flows from financing activities:
 
 
 
Borrowings on senior secured revolving credit facility
48,000

 
43,000

Payments on senior secured revolving credit facility
(41,000
)
 
(3,000
)
Redemption of 13% senior notes

 
(10,225
)
Issuance of preferred stock
70,035

 

Payment of preferred stock dividends
(2,654
)
 

Taxes paid related to exercise of employee stock options

 
(18
)
Cash provided by financing activities
$
74,381

 
$
29,757

 
 
 
 
Net change in cash and cash equivalents
(270
)
 
(42,310
)
Beginning of period cash and cash equivalents
1,139

 
43,795

End of period cash and cash equivalents
$
869

 
$
1,485


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

6

Table of Contents

Callon Petroleum Company
Notes to the Consolidated Financial Statements
(Unless otherwise indicated, amounts included in the footnotes to the financial statements are presented in thousands,
except for share, well, acreage and per-derivative instrument data.)

INDEX TO THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Description of Business and Basis of Presentation
Fair Value Measurements
Property Disclosures and Operating Leases
Income Taxes
Earnings Per Share
Asset Retirement Obligations
Borrowings
Equity Transaction
Derivative Instruments and Hedging Activities
 
 

Note 1 - Description of Business and Basis of Presentation

Description of business

Callon Petroleum Company is an independent crude oil and natural gas company established in 1950, which has been focused on building reserves and production both onshore and offshore through efficient operations and low finding and development costs. In 2009, we began to shift our operational focus from exploration in the Gulf of Mexico to building an onshore asset portfolio in order to provide a multi-year, low-risk drilling program in both crude oil and natural gas basins. A significant portion of this onshore transition has been funded by reinvesting the cash flows from the Company’s Gulf of Mexico properties. In the fourth quarter of 2012, we monetized our interest in the deepwater Habanero field in order to accelerate development of our onshore properties. In October 2013, we entered into an agreement to sell our interest in our remaining deepwater property, the Medusa field, the Company’s interest in the Medusa Spar facility and substantially all remaining offshore shelf properties. This transaction will complete our long-term goal of becoming an onshore operator upon closing with an asset base concentrated in the Permian Basin.

Basis of presentation

Unless otherwise indicated, all amounts included within the footnotes to the financial statements are presented in thousands, except for share, well, acreage and per-derivative instrument 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, 2012. The balance sheet at December 31, 2012 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, 2013.

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. To the extent the amounts reclassified are material, we have either footnoted them within the Company’s disclosures or have discussed the reclassifications within this footnote.

New accounting standard

In February 2013, the Financial Accounting Standards Board issued an Accounting Standards Update (ASU) that clarified the reclassification requirements from accumulated other comprehensive income to net income. This ASU requires disclosure of amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present either on the face of the financial statements or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income, but only if the amount is reclassified in its entirety to net income in the same

7

 
Footnotes to the Financial Statements
Unless otherwise indicated, amounts included in the footnotes to the financial statements are presented in thousands, except for share, well, acreage and per-derivative instrument data.

reporting period. For amounts not reclassified in their entirety to net income, an entity is required to cross-reference to the related note on the face of the financial statements for additional information. Callon adopted this guidance effective January 1, 2013, which did not have a material impact on its financial statements.
 
Note 2 - Property Disclosures and Operating Leases

In April 2012, the Company took delivery of a drilling rig for a two-year term to support its horizontal drilling program in the Permian Basin. On August 1, 2013, the Company contracted an additional horizontal drilling rig for a one-year term. Lease cost recorded during the three and nine months ended September 30, 2013 was $3,874 and $8,425, respectively. Lease payments will approximate $12,601 in 2013 (with $4,176 remaining at September 30, 2013) and $6,941 in 2014. The agreements include early termination provisions that would reduce the minimum rentals under the agreement, assuming the lessor is unable to re-charter the rig and staffing personnel to another lessee, to $2,760 in 2013 and $4,530 in 2014.

On June 1, 2013, the Company acquired approximately 2,468 gross (2,186 net) acres in Reagan and Upton Counties, Texas, which is located in the southern portion of the Midland Basin and which is prospective for both horizontal and vertical drilling. The acquisition also included seven gross vertical wells and 1,051 barrels of oil equivalent proved reserves. The purchase price of $11,000 was funded using a portion of the proceeds from the preferred stock offering (discussed in Note 9).

Subsequent Event - Offshore Asset Sale

On October 17, 2013, the Company executed a purchase and sale agreement with W&T Offshore, Inc. (“W&T”), an unrelated third-party, pursuant to which W&T agreed to acquire our 15.0% working interest in the Medusa field (Mississippi Canyon blocks 582 and 538), our 10.0% membership interest in Medusa Spar LLC, and substantially all of our remaining Gulf of Mexico shelf properties for net cash consideration of approximately $100,000 before customary purchase price adjustments. W&T paid a deposit of $2,000, which will be applied to the purchase price. On November 5, 2013, the parties closed on a portion of the transaction for which the Company received $76,400 in proceeds. The remainder of the transaction is expected to close with adjusted proceeds of approximately $11,500 on or before November 30, 2013. The final closing of the transaction is subject to satisfaction of customary closing conditions and delivery of the total purchase price subject to adjustment for an acquisition effective date of July 1, 2013.

Also in October of 2013, Callon entered into an agreement to sell its 69% interest in the Swan Lake field for $2,000. This field includes 429 net acres and produced approximately 173 Mcf per day during the three months ended September 30, 2013. This is the Company’s only field in the Haynesville shale.



8

 
Footnotes to the Financial Statements
Unless otherwise indicated, amounts included in the footnotes to the financial statements are presented in thousands, except for share, well, acreage and per-derivative instrument data.

Note 3 - Earnings Per Share

The following table sets forth the computation of basic and diluted earnings per share:
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2013
 
2012
 
2013
 
2012
Net income (loss)
 
$
1,082

 
$
(1,105
)
 
$
1,040

 
$
3,182

Preferred stock dividends
 
(1,974
)
 

 
(2,654
)
 

(a) Net income (loss) available to common shareholders
 
(892
)
 
(1,105
)
 
(1,614
)
 
3,182

 
 
 
 
 
 
 
 
 
(b) Weighted average shares outstanding
 
40,321

 
39,575

 
40,064

 
39,441

Dilutive impact of stock options
 

 

 

 
10

Dilutive impact of restricted stock
 

 

 

 
792

(c) Weighted average shares outstanding for diluted net income (loss) per share
 
40,321

 
39,575

 
40,064

 
40,243

 
 
 
 
 
 
 
 
 
Basic net income (loss) per share (a/b)
 
$
(0.02
)
 
$
(0.03
)
 
$
(0.04
)
 
$
0.08

Diluted net income (loss) per share (a/c)
 
$
(0.02
)
 
$
(0.03
)
 
$
(0.04
)
 
$
0.08

 
 
 
 
 
 
 
 
 
The following were excluded from the diluted EPS calculation because their effect would be anti-dilutive:
Stock options
 
52

 
52

 
52

 
52

Restricted stock
 
239

 
105

 
239

 
105


Note 4Borrowings

The Company’s borrowings consisted of the following at:
 
 
September 30, 2013
 
December 31, 2012
Principal components:
 
 
 
 
Credit Facility
 
$
17,000

 
$
10,000

13% Senior Notes due 2016, principal
 
96,961

 
96,961

Total principal outstanding
 
113,961

 
106,961

Non-cash components:
 
 

 
 

13% Senior Notes due 2016 unamortized deferred credit
 
11,259

 
13,707

Total carrying value of borrowings
 
$
125,220

 
$
120,668


Senior Secured Revolving Credit Facility (the “Credit Facility”)

As of September 30, 2013, the Company’s $200,000 Credit Facility had an associated borrowing base of $75,000 with a maturity date of March 15, 2016. In November 2013, the Credit Facility’s borrowing base was increased to $83,000 following a review of the Company’s reserve base, pro forma for the sale of the Gulf of Mexico properties discussed in Note 2, and is contingent upon the repayment of 50% of the outstanding principal of the Senior Notes. To the extent the Company elects not to redeem the 13% Senior Notes before December 20, 2013, the borrowing base would be reduced by an amount equal to 25% of the aggregate principal balance of the Senior Notes outstanding on December 20, 2013 in excess of $48,000. Regions Bank serves as the administrative agent for the Credit Facility, which also includes Citibank, NA, IberiaBank, Whitney Bank and OneWest Bank, FSB as participating lenders. Amounts borrowed under the Credit Facility may not exceed a borrowing base, which is generally reviewed on a semi-annual basis and is then eligible for re-determination. The Credit Facility is secured by mortgages covering the Company’s major producing fields.

On May 10, 2013, the Company entered into the second amendment to our Fourth Amended and Restated Credit Agreement that allows the Company to pay quarterly Senior Unsecured Debt and Preferred Equity dividends of up to $5,500 per quarter, so long

9

 
Footnotes to the Financial Statements
Unless otherwise indicated, amounts included in the footnotes to the financial statements are presented in thousands, except for share, well, acreage and per-derivative instrument data.

as the Company is not in default under the Credit Facility. The amendment became effective with the receipt of the cash proceeds from the preferred equity offering discussed in Note 9.

As of September 30, 2013, the balance outstanding on the Credit Facility was $17,000 with an interest rate of 2.7%, calculated as the London Interbank Offered Rate (“LIBOR”) plus a tiered rate ranging from 2.5% to 3.0%, which is determined by utilization of the facility. In addition, the Credit Facility carries a commitment fee of 0.5% per annum on the unused portion of the borrowing base, which is payable quarterly.

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

Interest on the Senior Notes is payable on the last day of each quarter. Certain of the Company’s subsidiaries guarantee the Company’s obligations under the unsecured Senior Notes. The subsidiary guarantors are 100% owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations, and any subsidiaries of the parent company other than the subsidiary guarantors are 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 Senior Notes that were exchanged and the principal of the Senior Notes. This deferred credit is being amortized as a reduction of interest expense over the life of the Senior Notes at an 8.5% effective interest rate. The following table summarizes the Company’s deferred credit balance:
Gross Carrying
 
Accumulated Amortization at
 
Carrying Value at
 
Amortization Recorded during Current Year as a Reduction of
 
Estimated Amortization to be Recorded during the Remainder of the
 Amount
 
9/30/2013
 
9/30/2013
 
Interest Expense
 
 Current Year
$31,507
 
$20,248
 
$11,259
 
$2,448
 
$851

Restrictive Covenants

The indentures governing our Senior Notes and the Company’s Credit Facility contain various covenants including restrictions on additional indebtedness and payment of cash dividends. In addition, Callon’s Credit Facility contains covenants for maintenance of certain financial ratios. The Company was in compliance with these covenants at September 30, 2013.

Note 5 - Derivative Instruments and Hedging Activities

Objectives and strategies for using derivative instruments

The Company is exposed to fluctuations in realized crude oil and natural gas prices for its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its crude oil and natural gas production. The Company primarily utilizes collars, put and call options and swap derivative financial instruments to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for speculative 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. To manage this risk, the Company’s established counterparties for commodity derivative instruments include a large, well-known financial institution and a large, well-known oil and gas company. 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. Counterparty credit risk is considered when determining a derivative instruments’ fair value; See Note 6 for additional information.
     
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.

10

 
Footnotes to the Financial Statements
Unless otherwise indicated, amounts included in the footnotes to the financial statements are presented in thousands, except for share, well, acreage and per-derivative instrument data.

Financial statement presentation and settlements
In the first quarter of 2013, the Company monetized the remaining portion (covering the period Feb13-Dec13) of its 2013 crude oil collar positions of 40 Bbls per month. The proceeds from this transaction, combined with the proceeds from the sale of the below listed put for 30 Bbls per month, were used to finance the uplift in the crude oil swap for the period Feb13-Dec13.

Listed in the table below are the outstanding crude oil and natural gas derivative contracts as of September 30, 2013:
Commodity
 
Instrument
 
Average Notional Volumes per Month
 
Quantity Type
 
Put/Call Price
 
Fixed-Price Swap
 
Period
 
Designation under ASC 815
Natural gas
 
Swap
 
91
 
MMbtu
 
n/a

 
$
3.52

 
Oct13 - Dec13
 
Not Designated
Natural gas
 
Put Option
 
91
 
MMbtu
 
$
3.00

 
n/a

 
Oct13 - Dec13
 
Not Designated
Crude oil
 
Swap
 
40
 
Bbls
 
n/a

 
$
101.30

 
Oct13 - Dec13
 
Not Designated
Natural gas
 
Call Option
 
38
 
MMbtu
 
$
4.75

 
n/a

 
Jan14 - Dec14
 
Not Designated
Crude oil
 
Swap
 
30
 
Bbls
 
n/a

 
$
93.35

 
Jan14 - Dec14
 
Not Designated
Crude oil
 
Put Option
 
30
 
Bbls
 
$
70.00

 
n/a

 
Jan14 - Dec14
 
Not Designated
Crude oil
 
Swap
 
18
 
Bbls
 
n/a

 
$
102.08

 
Oct13 - Dec13
 
Not Designated
Crude oil
 
Swap
 
9
 
Bbls
 
n/a

 
$
94.58

 
Jan14 - Dec14
 
Not Designated

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 New York Mercantile Exchange (“NYMEX”) price. The fair value of the Company’s derivative instruments, depending on the type of instruments, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. See Note 6 for additional information regarding fair value.

The following table reflects the fair values of the Company’s derivative instruments for the periods presented (none of which were designated as hedging instruments under ASC 815):
 
 
Balance Sheet Presentation
 
Asset Fair Value
 
Liability Fair Value
 
Net Derivative Fair Value
Commodity
 
Classification
 
Line Description
 
09/30/13
 
12/31/12
 
09/30/13
 
12/31/12
 
09/30/13
 
12/31/12
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas
 
Current
 
Fair market value of derivatives
 
$

 
$

 
$
(45
)
 
$
(125
)
 
$
(45
)
 
$
(125
)
Natural gas
 
Non-current
 
Other long-term liabilities
 

 

 
(18
)
 
(116
)
 
(18
)
 
(116
)
Crude oil
 
Current
 
Fair market value of derivatives
 

 
1,674

 
(1,094
)


 
(1,094
)

1,674

Crude oil
 
Non-current
 
Other long-term assets
 
36

 
250

 

 

 
36

 
250

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Totals
 
 
 
$
36

 
$
1,924

 
$
(1,157
)

$
(241
)
 
$
(1,121
)
 
$
1,683


The Company’s derivative contracts are subject to netting arrangements and, being representative of the way in which the contracts settle, are presented in the balance sheet at their fair values 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 September 30, 2013:
 
 
Presented without
 
 
 
As Presented with
 
 
Effects of Netting
 
Effects of Netting
 
Effects of Netting
Current assets: Fair value of hedging contracts
 
$
96

 
$
(96
)
 
$

Long-term assets: Fair value of hedging contracts
 
155

 
(119
)
 
36

Current liabilities: Fair value of hedging contracts
 
(1,235
)
 
96

 
(1,139
)
Long-term liabilities: Fair value of hedging contracts
 
(137
)
 
119

 
(18
)


11

 
Footnotes to the Financial Statements
Unless otherwise indicated, amounts included in the footnotes to the financial statements are presented in thousands, except for share, well, acreage and per-derivative instrument data.

Derivatives not designated as hedging instruments

As discussed in the Company’s Form 10-K for the year ended December 31, 2012, the Company elected not to designate as an accounting hedge under FASB ASC 815 any of its derivative contracts executed subsequent to December 31, 2011, nor does it expect to designate future derivative contracts. Derivative contracts not designated as accounting hedges are carried at fair value on the balance sheet with both realized and unrealized (i.e. mark-to-market) gains or losses recorded on the statement of operations as a component of the Company’s other income and expenses.

For the periods indicated, the Company recorded the following related to its derivative instruments that were not designated as accounting hedges:
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2013
 
2012
 
2013
 
2012
Natural gas derivatives
 
 
 
 
 
 
 
 
     Realized gain (loss), net
 
$
(16
)
 
$

 
$
(123
)
 
$

     Unrealized gain (loss), net
 
81

 
(205
)
 
178

 
(536
)
          Sub-total gain (loss), net
 
$
65

 
$
(205
)
 
$
55

 
$
(536
)
 
 
 
 
 
 
 
 
 
Crude oil derivatives
 
 
 
 
 
 
 
 
     Realized gain (loss), net
 
$
(618
)
 
$

 
$
804

 


     Unrealized gain (loss), net
 
(3,133
)
 
(1,393
)
 
(2,982
)
 
2,513

          Sub-total gain (loss), net
 
$
(3,751
)
 
$
(1,393
)
 
$
(2,178
)
 
$
2,513

 
 
 
 
 
 
 
 
 
Total gain (loss) on derivative instruments, net
 
$
(3,686
)
 
$
(1,598
)
 
$
(2,123
)
 
$
1,977


Derivatives designated as hedging instruments

As previously discussed, the Company elected to discontinue hedge accounting at the start of 2012, though certain of the Company’s crude oil derivative contracts designated as cash flow hedges were executed in prior periods and were in effect during 2012. Consequently, these designated contracts were recorded at fair market value with the effective portion of the changes in fair value recorded net of tax through other comprehensive income (loss) (“OCI”) in stockholders’ equity. The cash settlements on contracts for future production were recorded as an increase or decrease in crude oil revenues. Both changes in fair value and cash settlements of ineffective derivative contracts were recognized as derivative expense (income). All contracts previously designated as hedging instruments expired during 2012.

The tables below present the effect of the Company’s derivative financial instruments on the consolidated statements of operations as an increase (decrease) to crude oil revenues for the effective portion and as an increase (decrease) to other (income) expense for the ineffective portion and amounts excluded from effectiveness testing:
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2013
 
2012
 
2013
 
2012
Amount of gain reclassified from OCI into income (effective portion)
 
$

 
$
260

 
$

 
$
772

Amount of gain (loss) recognized in income (ineffective portion and amount excluded from effectiveness testing)
 

 
(282
)
 

 
40


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.


12

 
Footnotes to the Financial Statements
Unless otherwise indicated, amounts included in the footnotes to the financial statements are presented in thousands, except for share, well, acreage and per-derivative instrument data.

Fair value of financial instruments

Cash, cash equivalents, short-term 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: 
 
 
September 30, 2013
 
December 31, 2012
 
 
Carrying Value
 
Fair Value
 
Carrying Value
 
Fair Value
Credit Facility
 
$
17,000

 
$
17,000

 
$
10,000

 
$
10,000

13% Senior Notes due 2016 (1)
 
108,220

 
100,718

 
110,668

 
100,112

     Total
 
$
125,220

 
$
117,718

 
$
120,668

 
$
110,112


(1) Fair value is calculated only in relation to the $96,961 principal outstanding of the Senior Notes at each of the dates indicated above, respectively. The remaining $11,259 and $13,707, 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 the Company’s Consolidated Balance Sheet. The following methods and assumptions were used to estimate the fair values:

Commodity derivative instruments: Callon’s derivative policy allows for commodity derivative instruments to consist of natural gas and crude oil collars, basis swaps, puts, calls and similar commodity instrument structures. The fair value of these derivatives 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, based on analysis of each contract, also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities. The Company believes that the majority of the inputs used to calculate the commodity derivative instruments fall within Level 2 of the fair-value hierarchy based on the wide availability of quoted market prices for similar commodity derivative contracts. See Note 5 for additional information regarding the Company’s derivative instruments.


13

 
Footnotes to the Financial Statements
Unless otherwise indicated, amounts included in the footnotes to the financial statements are presented in thousands, except for share, well, acreage and per-derivative instrument data.

The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis for each hierarchy level:
As of 9/30/2013
 
Balance Sheet Presentation
 
Level 1
 
Level 2
 
Level 3
 
Total
Assets
 
 
 
 
 
 
 
 
 
 
Derivative financial instruments - current
 
Fair market value of derivatives
 
$

 
$

 
$

 
$

Derivative financial instruments - non-current
 
Other long-term assets
 

 
36

 

 
36

     Sub-total assets
 
 
 

 
36

 

 
36

 
 
 
 
 
 
 
 
 
 
 
Liabilities
 
 
 
 
 
 
 
 
 
 
Derivative financial instruments - current
 
Fair market value of derivatives
 
$

 
$
1,139

 
$

 
$
1,139

Derivative financial instruments - non-current
 
Other long-term liabilities
 

 
18

 

 
18

     Sub-total liabilities
 
Other long-term liabilities
 

 
1,157

 

 
1,157

 
 
 
 
 
 
 
 
 
 
 
Total
 
 
 
$

 
$
(1,121
)
 
$

 
$
(1,121
)
 
 
 
 
 
 
 
 
 
 
 
As of 12/31/2012
 
Balance Sheet Presentation
 
Level 1
 
Level 2
 
Level 3
 
Total
Assets
 
 
 
 
 
 
 
 
 
 
Derivative financial instruments - current
 
Fair market value of derivatives
 
$

 
$
1,674

 
$

 
$
1,674

Derivative financial instruments - non-current
 
Other long-term assets
 

 
250

 

 
250

     Sub-total assets
 
 
 

 
1,924

 

 
1,924

 
 
 
 
 
 
 
 
 
 
 
Liabilities
 
 
 
 
 
 
 
 
 
 
Derivative financial instruments - current
 
Fair market value of derivatives
 
$

 
$
125

 
$

 
$
125

Derivative financial instruments - non-current
 
Other long-term liabilities
 

 
116

 

 
116

     Sub-total liabilities
 
 
 

 
241

 

 
241

 
 
 
 
 
 
 
 
 
 
 
Total
 
 
 
$

 
$
1,683

 
$

 
$
1,683


Assets and liabilities measured at fair value on a nonrecurring basis

Certain assets and liabilities are reported at fair value on a nonrecurring basis in Callon’s Consolidated Balance Sheet. The following methods and assumptions were used to estimate the fair values:

Asset retirement obligations (“ARO”) incurred in current period. Callon estimates the fair value of AROs based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as (1) the existence of a legal obligation for an ARO, (2) amounts and timing of settlements, (3) the credit-adjusted risk-free rate to be used and (4) inflation rates. AROs incurred during the nine months ended September 30, 2013, including no upward revisions, were Level 3 fair value measurements. See Note 8, Asset Retirement Obligations, which provides a summary of changes in the ARO liability.

Acquisition. In accordance with the acquisition method of accounting, the purchase price of the Company’s acquisition during the period has been allocated to the assets acquired and liabilities assumed based on their estimated fair values on the acquisition date. In valuing the acquired assets and liabilities assumed, fair values were based on expected future cash flows based on estimated reserve quantities; costs to produce and develop reserves; and oil and gas forward prices. The fair value measurements were based on significant inputs not observable in the market and thus represent a level 3 measurement.

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 and non-deductible executive compensation expenses. The effective tax rate for the nine months ended September 30, 2013 and 2012 was 48% and 33%, respectively. The 48% effective tax rate for the nine months ended September 30, 2013 is primarily a result of the permanent differences previously noted, as well as certain discrete items occurring in the second quarter of 2013, including shortfalls associated with the Company’s restricted stock awards vesting during the period. We have no liability for uncertain tax positions or any accrued interest or penalties as of September 30, 2013.

14

 
Footnotes to the Financial Statements
Unless otherwise indicated, amounts included in the footnotes to the financial statements are presented in thousands, except for share, well, acreage and per-derivative instrument data.

Note 8 - Asset Retirement Obligations

The table below summarizes the Company’s asset retirement obligations activity for the nine months ended September 30, 2013:
Asset retirement obligations at January 1, 2013
 
$
13,301

Accretion expense
 
1,556

Liabilities incurred
 
624

Liabilities settled
 
(497
)
Revisions to estimate
 
(3,477
)
Asset retirement obligations at end of period
 
11,507

Less: Current asset retirement obligations
 
6,002

Long-term asset retirement obligations at September 30, 2013
 
$
5,505

Certain of the Company’s operating agreements require that assets be restricted for future abandonment obligations. Amounts recorded on the Consolidated Balance Sheets as restricted investments were $3,800 at September 30, 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 crude oil and natural gas properties.

On October 17, 2013, the Company announced entrance into an agreement to sell its interest in the Medusa field, Medusa Spar LLC, and substantially all of its Gulf of Mexico shelf properties to W&T. Under the agreement, which is expected to close on or before November 30, 2013, W&T will assume an estimated $4,500 of the ARO related to these offshore assets. See Note 2 for additional information.

Note 9 - Equity Transaction

On May 30, 2013, the Company issued $75,000 of 10.0% Series A Cumulative Preferred Stock (the “Preferred Stock”) and received $70,000 net proceeds after deducting the underwriting commissions and offering expenses. The sale consisted of 1.6 million shares of Preferred Stock, par value $0.01 per share, public offering price of $47.50 per share and liquidation preference of $50.00 per share in an underwritten public offering. The Preferred Stock ranks senior to the Company’s common stock with respect to the payment of dividends and distribution of assets upon liquidation or dissolution. The Preferred Stock has no stated maturity and is not subject to mandatory redemption or any sinking fund. The Preferred Stock will remain outstanding indefinitely unless repurchased by the Company or converted into Callon common stock in connection with certain changes in control as defined in the Preferred Stock prospectus.

Holders of the Preferred Stock are entitled to receive, when, as and if declared by our Board of Directors (the “Board”), 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. The first dividend date for the Preferred Stock was June 30, 2013, and these dividends were paid on June 28, 2013 (as June 30 fell on a weekend) in the amount of $0.43 per share or $680 for the stub period beginning with the issuance on May 30, 2013 through the dividend date on June 30, 2013. On September 3, 2013, the Board of Directors declared a dividend of $1.25 per share, or a total of $1,974, on the Company’s Preferred Stock to stockholders of record at the close of business on September 13, 2013, and the dividends were paid on September 30, 2013. To date in 2013, the Company has recognized dividend expense of $2,654.

Beginning on May 30, 2018, the Company may, solely at its option, redeem the Preferred Stock in whole at any time, or in part from time to time, for cash at a redemption price of $50.00 per share, plus accrued and unpaid dividends (whether or not declared) to the redemption date. The Company may redeem the Preferred Stock following certain changes of control as defined in the Preferred Stock prospectus, in whole or in part, within 120 days after the date on which the change of control has occurred, for cash at $50.00 per share, plus accrued and unpaid dividends (whether or not declared) to the redemption date. If the Company elects not to exercise this option, the holders of the Preferred Stock have the option to convert each share of Preferred Stock into a predefined number of Company common shares, subject to certain adjustments. 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. Based on the Company’s 60 million currently authorized shares, 16.8 million shares are reserved for a potential conversion.

The number of reserved common shares increases to a maximum of 42.2 million at such time as the Company’s authorized common shares increase. Except as required by law, holders of the Preferred Stock will have no voting rights unless dividends fall into arrears for six or more quarterly periods (whether or not consecutive). In that event and until such dividends in arrears are paid in full, the holders will be entitled to elect two directors to the Board, which will increase in size by that same number of directors.

15

Table of Contents


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. We have no obligation and make no undertaking to publicly update or revise any forward-looking statements, except as may be required by law.
 
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 commodities (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 respond to low natural gas prices,
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, including the pending sale of our Medusa property,
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 (“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 crude 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, 2012 (the “2012 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 elsewhere in our 2012 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.

16

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 2012 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 have been engaged in the exploration, development, acquisition and production of crude oil and natural gas properties since 1950. In 2009, we began to shift our operational focus from exploration in the Gulf of Mexico to building an onshore asset portfolio to provide a multi-year, low-risk drilling program in both crude oil and natural gas basins. A significant portion of this onshore transition has been funded by reinvesting the cash flows from our Gulf of Mexico properties. In the fourth quarter of 2012, we monetized our interest in the deepwater Habanero field in order to accelerate development of our onshore properties. In October 2013, we entered into an agreement to sell our interest in our remaining deepwater property, the Medusa field, the Company’s interest in the Medusa Spar facility and substantially all remaining offshore shelf properties. This transaction will complete our long-term goal of becoming an onshore operator upon closing with an asset base concentrated in the Permian Basin.

Recent key accomplishments and development progress:

In October, we signed a purchase and sale agreement with W&T Offshore, Inc., to sell our interest in the Medusa field, Medusa Spar LLC, and substantially all our remaining shelf properties for a net cash consideration of $100 million, accelerating our cash flows from these offshore properties, monetizing the value of additional undeveloped reserve potential, and completing our transition to onshore.

In August, we increased our capital budget by 36% to $170 million with approximately 87% of our budgeted operating expenditures (including drilling, completion, and infrastructure) allocated to our Midland Basin operations in an effort to accelerate the development of our fields in the southern and central portions of the Basin.

In August, we accepted delivery of an additional horizontal drilling rig under a one-year contract to support our expanded drilling program.

We continue the execution of our horizontal drilling program focused on the Wolfcamp B shale (gross production data provided):

East Bloxom: We currently have five Upper Wolfcamp B wells on production in the field, with a demonstrated average initial peak 24-hour rate (“24-hour rate”) of 1,108 Boe per day. Our most recent well placed on production, the Neal 322H is currently producing and two additional Upper Wolfcamp B wells continue to flow back. Based on our current drilling schedule, we expect to have a total of eight Wolfcamp B wells on production by year-end 2013.

Taylor Draw: We currently have four Upper Wolfcamp B wells on production in the field, with a demonstrated average 24-hour rate of 625 Boe per day. We also have one Lower Wolfcamp B well on production that produced at a 24-hour rate of 755 Boe per day. The average lateral length for these five wells is 4,700 feet. Three additional Lower Wolfcamp B wells, with an average lateral length of 8,250, are in the process of being fracture stimulated.

In addition, we have commenced horizontal development of the Wolfcamp B at both our Carpe Diem and Garrison Draw fields.

We also continue to delineate our acreage to expand our inventory of drilling opportunities:

We recently completed a vertical well targeting the Mississippian formation in Borden County as part of our Northern Midland evaluation program. The well produced at a rate of 326 Boe per day. We intend to drill an additional three vertical wells in the coming months before a decision is made to drill a horizontal well in 2014.

As part of our ongoing efforts to evaluate additional horizontal development zones, we recently tested the Wolfcamp A shale in the East Bloxom field. The well encountered mechanical problems and produced at a 24-

17

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

hour rate of 302 Boe per day. We currently plan to drill our next Wolfcamp A well in the field in the first quarter of 2014.

In our Pecan Acres field, our first vertical well to simultaneously complete multiple zones down to the Woodford shale produced at a gross peak initial (24-hour) production rate of 520 Boe per day. We will continue pursuing this program of completing vertical wells to deep zones in the field and seek to evaluate the concept on other acreage in the future.

Overview and Outlook

Production and highlights of our operations include:
 
 
Net Production (MBoe)
 
 
Three Months Ended September 30,
 
 
2013
 
2012
 
Change
 
% Change
Onshore - Permian Basin:
 
 
 
 
 
 
 
 
  Southern portion
 
181

 
116

 
65

 
56
 %
  Central portion
 
45

 
49

 
(4
)
 
(8
)%
    Total Permian
 
226

 
165

 
61

 
37
 %
 
 
 
 
 
 
 
 
 
Offshore - Deepwater Properties
 
 
 
 
 
 
 
 
  Medusa
 
94

 
117

 
(23
)
 
(20
)%
  Habanero
 

 
21

 
(21
)
 
(100
)%
    Total Deepwater
 
94

 
138

 
(44
)
 
(32
)%
 
 
 
 
 
 
 
 
 
Other:
 
 
 
 
 
 
 
 
  Haynesville Shale
 
3

 
12

 
(9
)
 
(75
)%
  Gulf of Mexico shelf
 
79

 
84

 
(5
)
 
(6
)%
    Total Other
 
82

 
96

 
(14
)
 
(15
)%
 
 
 
 
 
 
 
 
 
Total
 
402

 
399

 
3

 
1
 %

 
 
Net Production (MBoe)
 
 
Nine Months Ended September 30,
 
 
2013
 
2012
 
Change
 
% Change
Onshore - Permian Basin:
 
 
 
 
 
 
 
 
  Southern portion
 
397

 
278

 
119

 
43
 %
  Central portion
 
142

 
143

 
(1
)
 
(1
)%
    Total Permian
 
539

 
421

 
118

 
28
 %
 
 
 
 
 
 
 
 
 
Offshore - Deepwater Properties
 
 
 
 
 
 
 
 
  Medusa
 
271

 
343

 
(72
)
 
(21
)%
  Habanero
 
1

 
102

 
(101
)
 
(99
)%
    Total Deepwater
 
272

 
445

 
(173
)
 
(39
)%
 
 
 
 
 
 
 
 
 
Other:
 
 
 
 
 
 
 
 
  Haynesville Shale
 
17

 
35

 
(18
)
 
(51
)%
  Gulf of Mexico shelf
 
232

 
264

 
(32
)
 
(12
)%
    Total Other
 
249

 
299

 
(50
)
 
(17
)%
 
 
 
 
 
 
 
 
 
Total
 
1,060

 
1,165

 
(105
)
 
(9
)%


18

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 September 30, 2013:
 
 
Crude Oil Wells
 
Natural Gas Wells
 
 
Gross
 
Net
 
Gross
 
Net
Working interest
 
125

 
101.1

 
11

 
4.8

Royalty interest
 
3

 
0.10

 
2

 
0.08

   Total
 
128

 
101.2

 
13

 
4.88


Highlights of our onshore development program and offshore assets include:

Onshore – Permian Basin

We expect that our production and reserve growth initiatives will continue to focus primarily on the Permian Basin, in which we own approximately 40,275 gross (34,931 net) acres as of September 30, 2013. In order to advance our growth plans, we are directing a significant amount of our 2013 capital budget to horizontal drilling of the Wolfcamp shale formation in the Permian Basin, while continuing to support our ongoing vertical Wolfberry program. The following table summarizes the Company’s drilling progress in the Permian Basin for the nine months ended September 30, 2013:
 
 
Drilled
 
Completed (a)
 
 
Gross
 
Net
 
Gross
 
Net
Southern portion:
 
 
 
 
 
 
 
 
   Vertical wells
 
1

 
1

 

 

   Horizontal wells
 
13

 
11.75

 
9

 
8.23

     Total southern portion
 
14

 
12.75

 
9

 
8.23

 
 
 
 
 
 
 
 
 
Central portion:
 
 
 
 
 
 
 
 
   Vertical wells
 
4

 
2.58

 
6

 
3.97

   Horizontal wells
 

 

 

 

     Total central portion
 
4

 
2.58

 
6

 
3.97

 
 
 
 
 
 
 
 
 
Northern portion:
 
 
 
 
 
 
 
 
   Vertical wells
 
1

 
1

 
1

 
0.75

   Horizontal wells
 

 

 
1

 
0.75

     Total northern portion
 
1

 
1

 
2

 
1.50

 
 
 
 
 
 
 
 
 
   Total vertical wells
 
6

 
4.58

 
7

 
4.72

   Total horizontal wells
 
13

 
11.75

 
10

 
8.98

 
 
 
 
 
 
 
 
 
Total
 
19

 
16.33

 
17

 
13.70

(a)
Completions include wells drilled prior to 2013.

Southern portion: We currently own approximately 9,971 net acres in the southern portion of the Permian Basin. Our current production in the southern portion of the Midland Basin (Crockett, Reagan and Upton Counties in Texas) is derived from vertical drilling operations in the Wolfberry play and horizontal development of the Wolfcamp shale.

During the second quarter of 2013, we acquired 2,468 gross (2,186 net) acres and seven gross vertical wells in southern Reagan and Upton Counties, Texas, which constitutes our Garrison Draw field. During the third quarter, we drilled one gross vertical and one gross horizontal well in this field with plans to drill one additional gross horizontal well by year-end.

We recently increased our level of horizontal drilling activity in 2013 in this portion of the Basin with plans to drill a total of 18 horizontal wells in 2013. Given this level of sustained activity and our desire to maximize capital efficiency, we have implemented pad-drilling and have recently established the infrastructure to complete multiple wells simultaneously.

Central portion: We currently own approximately 3,343 net acres in the central portion of the Permian Basin. Our current production in the central portion of the Midland Basin (Ector, Glasscock, and Midland Counties in Texas) is primarily from the Wolfberry play, which has recently been modified in this area to include deeper target zones below the Atoka formation.

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


In late 2012, we modified our Wolfberry drilling program in the Pecan Acres field to target deeper intervals below the Atoka formation. Given initial results from this initiative, our future vertical drilling plans in both Pecan Acres and Carpe Diem fields will incorporate these deeper zones as part of the completion design.

We recently commenced drilling of our first two horizontal wells at our Carpe Diem field. These wells are targeting the Upper Wolfcamp B and are anticipated to be completed before year-end 2013.

Northern portion: We currently own approximately 21,617 net acres in the northern portion of the Permian Basin, which includes the 14,653 net acres in Borden County, Texas and 6,964 net acres in Lynn County, Texas. Although the area has experienced a recent increase in drilling activity, the northern Midland Basin has had limited drilling activity compared with the southern Basin (the location of our current production), which significantly increases the risk associated with successful drilling activities in this area.

Callon continues to progress its delineation efforts on its Borden County acreage. To date, two horizontal and two vertical wells have been drilled to evaluate multiple prospective zones. The most recent vertical well, the Lacey Newton 2801, produced at a peak 24-rate of 326 boepd (92% oil).

Offshore - Deepwater properties

As discussed in Note 2, on October 17, 2013, the Company entered into a purchase and sale agreement with W&T for a net cash consideration of approximately $100 million before customary purchase price adjustments. On November 5, 2013, the parties closed on a portion of the transaction for which the Company received $76.4 million in proceeds. The remainder of the transaction is expected to close with adjusted proceeds of approximately $11.5 million on or before November 30, 2013.

Our net interest in the Medusa field, our remaining deepwater property, produced an average of 993 Boe per day during the nine months ended September 30, 2013, approximately 88% being crude oil that receives pricing based on Mars benchmark crude.

Other – Haynesville shale

We own a 69% working interest in a 429 net acre unit in the Haynesville shale play in Bossier Parish, Louisiana. As of September 30, 2013, our Haynesville well was producing approximately 374 Mcf of natural gas per day. We currently have no drilling obligations related to this lease position. In October of 2013, we entered into an agreement to sell this property for $2 million.

Other – Gulf of Mexico shelf properties

As discussed in Note 2, these properties comprise part of the asset sale to W&T. During the nine months ended September 30, 2013, our shelf properties produced 233 MBoe, which accounted for 22% of our total production, of which 96% was natural gas. Production from the East Cameron Block 257 field, which had been shut-in since November 2011, recommenced on May 9, 2013, and contributed an average of 271 Boe per day of production for the third quarter. Following the completion of our recent asset sale, we will retain our interest in two non-producing fields, both of which are in various stages of plugging and abandonment.

Liquidity and Capital Resources

Historically, our primary sources of funding have been cash flows from operations, borrowings from financial institutions, the sale of debt and equity securities and divestitures, such as the sale of our interest in the deepwater Habanero field.

Cash and cash equivalents of $0.9 million decreased by $0.2 million at September 30, 2013 compared to $1.1 million at December 31, 2012. As of September 30, 2013, the Company’s liquidity position approximated $58.9 million inclusive of cash and cash equivalents and available borrowing capacity under our Credit Facility. Liquidity has subsequently been enhanced by the previously discussed increase in the Company’s borrowing base under the Credit Facility and will further be increased by the receipt of the $100 million proceeds (before closing adjustments) from the previously discussed asset sale (see Note 2).

On May 30, 2013, we issued $75.0 million of 10.0% Series A Cumulative Preferred Stock (the “Preferred Stock”) and received $70 million net proceeds after deducting underwriting commissions and offering expenses. The Preferred Stock requires dividend payments of approximately $1.9 million per quarter.

As of September 30, 2013, our $200 million Credit Facility had an associated borrowing base of $75 million with a maturity date of March 15, 2016. Amounts borrowed under the Credit Facility may not exceed a borrowing base, which is generally

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

reviewed on a semi-annual basis and is then eligible for re-determination. The Credit Facility is secured by mortgages covering the Company’s major producing fields. In November 2013, the Credit Facility’s borrowing base was increased to $83 million following a review of the Company’s reserve base, pro forma for the sale of the Gulf of Mexico properties and the assumed repayment of 50% of the outstanding principal of the Senior Notes. However, to the extent the Company elects not to redeem the Senior Notes before December 20, 2013, the borrowing base would be reduced by $0.25 million for each $1 million of the Senior Notes outstanding in excess of $48 million.

As of September 30, 2013, the balance outstanding on the Credit Facility was $17 million with an interest rate of 2.7%, calculated as the London Interbank Offered Rate (“LIBOR”) plus a tiered rate ranging from 2.5% to 3.0%, which is based on utilization of the facility. In addition, the Credit Facility carries a commitment fee of 0.5% per annum on the unused portion of the borrowing base, which is payable quarterly. The Company plans to use a portion of the proceeds from the previously discussed asset sale, subsequent to closing, to pay down the outstanding balance on the Credit Facility.

At September 30, 2013, we had approximately $97 million principal amount of 13% Senior Notes due 2016 outstanding with interest payable quarterly. Following the completion of the previously discussed asset divestiture (See Note 2) and as it relates to the borrowing base discussion above, we may allocate a portion of the proceeds from the sale to redeem all or a portion of the Senior Notes outstanding and thereby reduce future interest expense. We also continue to monitor for acquisition opportunities we believe would be accretive to shareholder value.

2013 capital expenditures

Our revised 2013 capital budget (excluding acquisitions) approximates $170 million and represents a 36% increase over the previous 2013 capital development budget estimate of $125 million. The increase relates to expenditures for additional development activities on our Midland Basin acreage. Approximately 87% of our budgeted operational expenditures (including drilling, completion and infrastructure) are allocated to our Midland Basin operations. Our budget includes further exploration and development of our Permian Basin properties with plans to complete approximately 27 gross wells including 20 horizontal wells and seven vertical wells. Components of the 2013 capital budget include (in millions):
Midland Basin
 
$
148

Gulf of Mexico
 
4

Total budgeted capital expenditures
 
$
152

 
 
 
Capitalized general and administrative costs
 
14

Capitalized interest and other
 
4

Total budgeted capitalized expenses
 
$
18

 
 
 
Total operational budget
 
170

 
 
 
Acquisition - Southern Midland Basin
 
11

Total capital expenditures, including acquisition
 
$
181

 
We believe that our cash on hand and the availability under our Credit Facility, combined with our expected operating cash flow based on current commodity prices and forecasted production, will be adequate to meet our forecasted capital expenditures, interest payments, and operating requirements for the remainder of 2013. Depending on economic conditions or the Company’s operational results, our capital budget may be adjusted up or down as deemed appropriate.


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

The capital expenditures for the nine months ended September 30, 2013 include the following (in millions):
Southern Midland Basin
 
$
71

Central Midland Basin
 
12

Northern Midland Basin
 
5

Total capital expenditures
 
$
88

 
 
 
Capitalized general and administrative costs
 
10

Capitalized interest and other
 
3

Total capitalized expenses
 
$
13

 
 
 
Total operational expenditures
 
101

 
 
 
Acquisition - Southern Midland Basin
 
11

Total capital expenditures, including acquisition
 
$
112


Summary cash flow information is provided as follows:

Operating activities.  For the nine months ended September 30, 2013, net cash provided by operating activities decreased $6.2 million to $35.2 million, from $41.4 million for the same period in 2012 and relates primarily to a $6.0 million reduction in revenue stemming from a 9% decrease in equivalent production. These decreases were partially offset by a 2% increase in price per equivalent unit produced and lower operating expenses. Realized prices and production volumes are discussed below within Results of Operations.

Investing activities.  For the nine months ended September 30, 2013, net cash used in investing activities was $109.9 million as compared to $113.5 million for the same period in 2012. The $3.6 million decrease is primarily attributable to a reduction in property acquisition expenditures in the nine-month period of the current year as compared to the corresponding period of 2012.

Financing activities.  For the nine months ended September 30, 2013, net cash provided by financing activities was $74.4 million compared to cash provided by financing activities of $29.8 million during the same period of 2012. The $44.6 million increase relates primarily to the $70.0 million net proceeds from the previously discussed preferred stock offering, which was offset primarily by cash used to repay amounts outstanding on our Credit Facility.



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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 unaudited operating information with respect to the Company’s crude oil and natural gas operations for the periods indicated:
 
 
Three Months Ended September 30,
 
 
2013
 
2012
 
Change
 
% Change
Net production:
 
 
 
 
 
 
 
 
Crude oil (MBbls)
 
257

 
251

 
6

 
2
 %
Natural gas (MMcf)
 
864

 
890

 
(26
)
 
(3
)%
Total production (MBoe)
 
402

 
399

 
3

 
1
 %
Average daily production (MBoe)
 
4.4

 
4.3

 
0.1

 
2
 %
 
 
 
 
 
 
 
 
 
Average realized sales price (a):
 
 

 
 

 
 

 
 

Crude oil (Bbl)
 
$
105.11

 
$
95.86

 
$
9.25

 
10
 %
Natural gas (Mcf)
 
$
4.38

 
$
3.76

 
$
0.62

 
16
 %
Average realized sales price on an equivalent basis (Boe)
 
$
76.61

 
$
68.67

 
$
7.94

 
12
 %
 
 
 
 
 
 
 
 
 
Crude oil and natural gas revenues (in thousands):
 
 

 
 

 
 

 
 

Crude oil revenue
 
$
27,014

 
$
24,061

 
$
2,953

 
12
 %
Natural gas revenue
 
3,783

 
3,341

 
442

 
13
 %
Total
 
$
30,797

 
$
27,402

 
$
3,395

 
12
 %
 
 
 
 
 
 
 
 
 
Additional per Boe data:
 
 

 
 

 
 

 
 

Average realized sales price
 
$
76.61

 
$
68.67

 
$
7.94

 
12
 %
Lease operating expense
 
13.11

 
13.05

 
0.06

 
< 1%

Production taxes
 
2.47

 
1.64

 
0.83

 
51
 %
Operating margin
 
$
61.03

 
$
53.98

 
$
7.05

 
13
 %
 
 
 
 
 
 
 
 
 
Other expenses per Boe:
 
 

 
 

 
 

 
 

Depletion, depreciation and amortization
 
$
29.62

 
$
29.99

 
$
(0.37
)
 
(1
)%
General and administrative
 
14.49

 
16.14

 
(1.65
)
 
(10
)%
 
 
 
 
 
 
 
 
 
(a) Below is a reconciliation of the average NYMEX price to the average realized sales price: