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, 2012
 
or
 
¨
Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
 
For the transition period from:
____________ to _____________
Commission File Number 001-14039
CALLON PETROLEUM COMPANY
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction
of incorporation or organization)
64-0844345
(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 ¨

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 ¨

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 ¨
Accelerated filer x
 
 
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 x

As of November 1, 2012 there were outstanding 39,799,583 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





Part I. Financial Information
Item I. Financial Statements
Callon Petroleum Company
Consolidated Balance Sheets
(in thousands, except par value per share data)
 
September 30, 2012
 
December 31, 2011
ASSETS
Unaudited
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
1,485

 
$
43,795

Accounts receivable
16,643

 
15,181

Fair market value of derivatives
2,013

 
2,499

Other current assets
1,359

 
1,601

Total current assets
21,500

 
63,076

Oil and natural gas properties, full-cost accounting method:
 
 
 
Evaluated properties
1,490,862

 
1,421,640

Less accumulated depreciation, depletion and amortization
(1,244,329
)
 
(1,208,331
)
Net oil and natural gas properties
246,533

 
213,309

Unevaluated properties excluded from amortization
45,672

 
2,603

Total oil and natural gas properties
292,205

 
215,912

 
 
 
 
Other property and equipment, net
12,374

 
10,512

Restricted investments
3,796

 
3,790

Investment in Medusa Spar LLC
8,809

 
9,956

Deferred tax asset
64,911

 
65,743

Other assets, net
2,004

 
718

Total assets
$
405,599

 
$
369,707

 
 
 
 
LIABILITIES AND STOCKHOLDERS' EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued liabilities
$
30,988

 
$
26,057

Asset retirement obligations
2,340

 
1,260

Fair market value of derivatives
224

 

Total current liabilities
33,552

 
27,317

13% Senior Notes:
 
 
 
Principal outstanding
96,961

 
106,961

Deferred credit, net of accumulated amortization of $17,018 and $13,123, respectively
14,489

 
18,384

Total 13% Senior Notes
111,450

 
125,345

 
 
 
 
Senior secured revolving credit facility
40,000

 

Asset retirement obligations
11,664

 
12,678

Other long-term liabilities
3,471

 
3,165

Total liabilities
200,137

 
168,505

Stockholders' equity:
 
 
 
Preferred Stock, $0.01 par value, 2,500 shares authorized;

 

Common stock, $0.01 par value, 60,000 shares authorized; 39,780 and 39,398 shares outstanding at September 30, 2012 and December 31, 2011, respectively
398

 
394

Capital in excess of par value
326,892

 
324,474

Other comprehensive income
279

 
1,624

Retained deficit
(122,107
)
 
(125,290
)
Total stockholders' equity
205,462

 
201,202

Total liabilities and stockholders' equity
$
405,599

 
$
369,707


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

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

 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2012
 
2011
 
2012
 
2011
Operating revenues:
 
 
 
 
 
 
 
 
Crude oil revenues
 
$
24,061

 
$
26,537

 
$
71,883

 
$
74,428

Natural gas revenues
 
3,341

 
7,013

 
10,174

 
21,404

Total oil and natural gas revenues
 
27,402

 
33,550

 
82,057

 
95,832

 
 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
 
Lease operating expenses
 
5,859

 
5,980

 
20,465

 
16,324

Depreciation, depletion and amortization
 
11,965

 
13,013

 
35,998

 
35,741

General and administrative
 
6,441

 
3,464

 
15,846

 
11,487

Accretion expense
 
574

 
569

 
1,709

 
1,767

Total operating expenses
 
24,839

 
23,026

 
74,018

 
65,319

 
 
 
 
 
 
 
 
 
Income from operations
 
2,563

 
10,524

 
8,039

 
30,513

 
 
 
 
 
 
 
 
 
Other (income) expenses:
 
 
 
 
 
 
 
 
Interest expense
 
2,135

 
2,722

 
7,096

 
8,912

Gain on early extinguishment of debt
 

 

 
(1,366
)
 
(1,942
)
Gain on acquired assets
 

 
(46
)
 

 
(5,025
)
Unrealized loss (gain) on mark-to-market derivative instruments, net
 
1,598

 

 
(1,977
)
 

Other (income) expense
 
237

 
(347
)
 
(224
)
 
(599
)
Total other (income) expenses
 
3,970

 
2,329

 
3,529

 
1,346

 
 
 
 
 
 
 
 
 
Income (loss) before income taxes
 
(1,407
)
 
8,195

 
4,510

 
29,167

Income tax expense (benefit)
 
(246
)
 

 
1,508

 
(2,681
)
Income (loss) before equity in earnings of Medusa Spar LLC
 
(1,161
)
 
8,195

 
3,002

 
31,848

Equity in earnings of Medusa Spar LLC
 
56

 
211

 
180

 
597

Net income (loss) available to common shares
 
$
(1,105
)
 
$
8,406

 
$
3,182

 
$
32,445

 
 
 
 
 
 
 
 
 
Net income (loss) per common share:
 
 
 
 
 
 
 
 
Basic
 
$
(0.03
)
 
$
0.21

 
$
0.08

 
$
0.87

Diluted
 
$
(0.03
)
 
$
0.21

 
$
0.08

 
$
0.85

 
 
 
 
 
 
 
 
 
Shares used in computing net income (loss) per common share:
 
 
 
 
 
 
 
 
Basic
 
39,575

 
39,322

 
39,441

 
37,431

Diluted
 
39,575

 
39,976

 
40,243

 
38,120



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

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


 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2012
 
2011
 
2012
 
2011
Net income (loss)
 
$
(1,105
)
 
$
8,406

 
$
3,182

 
$
32,445

Other comprehensive (loss) income:
 
 
 
 
 
 
 
 
     Change in fair value of derivatives designated as hedges, net of tax
 
(1,268
)
 
8,337

 
(1,345
)
 
11,587

Total comprehensive income (loss)
 
$
(2,373
)
 
$
16,743

 
$
1,837

 
$
44,032


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

Callon Petroleum Company
Consolidated Statements of Cash Flows
(Unaudited; in thousands)
 
 
Nine Months Ended September 30,
 
 
2012
 
2011
Cash flows from operating activities:
 
 
 
 
Net income
 
$
3,182

 
$
32,445

Adjustments to reconcile net income to
 
 
 
 
cash provided by operating activities:
 
 
 
 
Depreciation, depletion and amortization
 
37,005

 
36,501

Accretion expense
 
1,709

 
1,767

Non-cash gain on acquired assets
 

 
(4,979
)
Amortization of non-cash debt related items
 
293

 
338

Amortization of deferred credit
 
(2,304
)
 
(2,361
)
Non-cash gain on early extinguishment of debt
 
(1,366
)
 
(1,942
)
Equity in earnings of Medusa Spar LLC
 
(180
)
 
(597
)
Deferred income tax expense
 
1,508

 
11,987

Valuation allowance
 

 
(14,668
)
Non-cash derivative income due to hedge ineffectiveness
 
(40
)
 
(189
)
Non-cash unrealized gain on mark-to-market derivative instruments, net
 
(1,977
)
 

Non-cash charge related to compensation plans
 
1,901

 
1,122

Payments to settle asset retirement obligations
 
(1,136
)
 
(2,428
)
Changes in current assets and liabilities:
 
 
 
 
     Accounts receivable
 
(1,260
)
 
(5,280
)
     Other current assets
 
244

 
37

     Current liabilities
 
4,965

 
6,334

     Change in natural gas balancing receivable
 
(96
)
 
198

     Change in natural gas balancing payable
 
(152
)
 
(29
)
     Change in other long-term liabilities
 

 
100

     Change in other assets, net
 
(911
)
 
(427
)
Cash provided by operating activities
 
$
41,385

 
$
57,929

 
 
 
 
 
Cash flows from investing activities:
 
 
 
 
Capital expenditures
 
(115,401
)
 
(74,388
)
Investment in restricted assets for plugging and abandonment
 

 
(112
)
Proceeds from sale of mineral interest and equipment
 
526

 
7,559

Distribution from Medusa Spar LLC
 
1,423

 
1,107

Cash used in investing activities
 
$
(113,452
)
 
$
(65,834
)
 
 
 
 
 
Cash flows from financing activities:
 
 
 
 
Draw on senior secured credit facility
 
43,000

 

Payments on senior secured credit facility
 
(3,000
)
 

Redemption of 13% senior notes
 
(10,225
)
 
(35,062
)
Issuance of common stock
 

 
73,765

Equity issued related to employee stock plans
 
(18
)
 

Cash provided by financing activities
 
$
29,757

 
$
38,703

 
 
 
 
 
Net change in cash and cash equivalents
 
(42,310
)
 
30,798

Beginning of period cash and cash equivalents
 
43,795

 
17,436

End of period cash and cash equivalents
 
$
1,485

 
$
48,234


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

3



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 per-share, per-hedge, well and acreage data.)

INDEX TO THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.    Description of Business and Basis of Presentation
6.     Fair Value Measurements
2.    Property Acquisition and Operating Leases
7.     Income Taxes
3.    Earnings per Share
8.     Asset Retirement Obligations
4.    Borrowings
9. Global Settlement with Joint Interest Partner
5.    Derivative Instruments and Hedging Activities
10. Equity Transactions

Note 1 - Description of Business and Basis of Presentation

Description of Business

Callon Petroleum Company has been engaged in the exploration, development, acquisition and production of oil and natural gas properties since 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.

The Company’s properties and operations are geographically concentrated onshore in Texas and Louisiana and the offshore waters of the Gulf of Mexico.

Basis of Presentation

Unless otherwise indicated, all amounts included within the footnotes to the financial statements are presented in thousands, except for per-share, per-hedge, well and acreage 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. CPOC also includes its former wholly owned subsidiary, Callon Entrada Company (“Callon Entrada”), which as discussed in Note 9 was reconsolidated in the Company's financial statements effective April 29, 2011.

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, 2011. The balance sheet at December 31, 2011 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, 2012.

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 noted the items within this footnote.

Prior period correction of an immaterial error

During the second quarter of 2012, we determined that a prior reporting period had a misstatement caused by an error in adjusting the Company's deferred tax position at December 31, 2011. Management concluded that the impact of this error on the prior reporting period is immaterial. However, given that the adjustment to correct the error in 2012 would have a material impact on the 2012 financial statements, we have corrected the prior period financial statements in this current Form 10-Q in accordance with SEC guidance. The adjustment had no effect on the Company's cash flow, and the information included in this Form 10-Q sets forth the effects of this correction on the previously reported Balance Sheet and Income Statement as of December 31, 2011 as follows:
 
 
As Reported
 
Adjustment
 
As Adjusted
 
 
 
 
 
 
 
Balance Sheet:
 
 
 
 
 
 
Deferred tax asset
 
$
63,496

 
$
2,247

 
$
65,743

Total assets
 
367,460

 
2,247

 
369,707

Retained deficit
 
(127,537
)
 
2,247

 
(125,290
)
Total stockholders' equity
 
198,955

 
2,247

 
201,202

Total liabilities and stockholders' equity
 
367,460

 
2,247

 
369,707

 
 
 
 
 
 
 
Income Statement:
 
 
 
 
 
 
Income tax benefit
 
(67,036
)
 
(2,247
)
 
(69,283
)
Net income available to common shares
 
104,149

 
2,247

 
106,396

Net income per common share - Basic
 
2.75

 
0.06

 
2.81

Net income per common share - Diluted
 
2.70

 
0.06

 
2.76

 
Note 2 - Property Acquisitions and Operating Leases

In February 2012, we contracted a drilling rig for a term of two years to support our horizontal drilling program in the Permian Basin. The drilling rig was delivered in April 2012, and lease costs recorded during the three and nine months ended September 30, 2012 was $2,327 and $4,283, respectively. Lease payments will approximate $6,611 in 2012 (with $2,328 remaining at September 30, 2012), $9,234 in 2013 and $2,619 in 2014. The agreement includes 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 $4,434 in 2012 (with $1,689 remaining at September 30, 2012), $5,475 in 2013 and $1,350 in 2014.

During February 2012, the Company acquired approximately 16,020 gross (14,470 net) acres in Borden County, which is located in the northern portion of the Midland Basin. The northern portion of the Midland Basin has had limited drilling activity compared with the southern portion of the Basin (where our current production is located), increasing the risk of success for these drilling activities. The purchase price of $15,000 was funded from existing cash balances.

On June 8, 2012, the Company signed a purchase and sale agreement to acquire 2,319 gross (1,762 net) acres in southern Reagan County, Texas for a total purchase price of $12,000, which was financed with a draw on the Company's Senior Secured Credit Facility. The transaction had an effective date of May 1, 2012 and closed on July 5, 2012.

During the third quarter of 2012, we acquired an additional 8,375 gross acres (5,940, net) in the northern portion of the Midland Basin for a total consideration of $4,133. Subsequent to September 30, 2012, we acquired an additional 1,024 net acres in this area of the Midland Basin for $717.

In addition to the consideration paid for each of the above referenced leasehold additions, the Company's unevaluated property balance of $45,672 at September 30, 2012 includes the development and facility costs incurred in 2012 on these properties.


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,
 
 
2012
 
2011
 
2012
 
2011
(a) Net income (loss)
 
$
(1,105
)
 
$
8,406

 
$
3,182

 
$
32,445

 
 
 
 
 
 
 
 
 
(b) Weighted average shares outstanding
 
39,575

 
39,322

 
39,441

 
37,431

Dilutive impact of stock options
 

 
16

 
10

 
22

Dilutive impact of restricted stock
 

 
638

 
792

 
667

(c) Weighted average shares outstanding for diluted net income (loss) per share
 
39,575

 
39,976

 
40,243

 
38,120

 
 
 
 
 
 
 
 
 
Basic net income (loss) per share (a¸b)
 
$
(0.03
)
 
$
0.21

 
$
0.08

 
$
0.87

Diluted net income (loss) per share (a¸c)
 
$
(0.03
)
 
$
0.21

 
$
0.08

 
$
0.85

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

 
67

 
52

 
82

     Restricted stock
 
105

 
766

 
105

 
766


Note 4 – Borrowings

The Company’s borrowings consisted of the following at:
 
 
September 30, 2012
 
December 31, 2011
Principal components:
 
 
 
 
Credit Facility
 
$
40,000

 
$

13% Senior Notes due 2016, principal
 
96,961

 
106,961

Total principal outstanding
 
136,961

 
106,961

Non-cash components:
 
 

 
 

13% Senior Notes due 2016 unamortized deferred credit
 
14,489

 
18,384

Total carrying value of borrowings
 
$
151,450

 
$
125,345


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

On June 20, 2012, Regions Bank increased the Company's Credit Facility to $200,000 with an associated borrowing base under the Credit Facility of $60,000 and a maturity of July 31, 2014. In October 2012, the Credit Facility was amended to increase the borrowing base to $80,000, extend the maturity to March 15, 2016 and add Citibank, NA, IberiaBank, Whitney Bank and OneWest Bank, FSB as participating lenders. Regions Bank continues to serve as Administrative Agent for the facility. 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 borrowing base and scheduled maturity at year-end 2011 were $45,000 and September 25, 2012, respectively. The Credit Facility is secured by mortgages covering the Company's major producing fields.

As of September 30, 2012, the balance outstanding on the Credit Facility was $40,000 with an interest rate on the facility of 2.97%, 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. As of November 7, 2012, the balance outstanding on the Credit Facility was $44,000 as the Company drew an additional $4,000 in support of the Company's ongoing capital development program.

4

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


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

The Senior Notes’ 13% interest coupon 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
 
9/30/2012
 
9/30/2012
 
Interest Expense
 
 Current Year
$31,507
 
$17,018
 
$14,489
 
$2,304
 
$782

In June 2012, the Company redeemed $10,000 of its Senior Notes, which resulted in a $1,366 net gain on the early extinguishment of debt. The Notes had a carrying value of $11,591, including $1,591 of the Notes’ deferred credit. To redeem the Notes, the Company paid $10,225, comprised of the $10,000 principal of the notes and $225 of redemption expenses. The accumulated amortization reflected in the table above at September 30, 2012 includes the previously mentioned $1,591 deferred credit component, which recorded as a component of the gain on early extinguishment of debt is excluded from the amount reflected above as amortization recorded during the current year as a reduction of interest expense.

Restrictive Covenants

The indenture governing our Senior Notes and the Company’s Credit Facility contains 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, 2012.

Note 5 - Derivative Instruments and Hedging Activities

Objectives and Strategies for Using Derivative Instruments

The Company is exposed to fluctuations in crude oil and natural gas prices on 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 utilizes primarily collar, 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

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.  The Company monitors counterparty creditworthiness on an ongoing basis; however, 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.

5

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


Derivative positions and settlements
In the second quarter of 2012, the Company entered into fixed price natural gas swaps at $3.52 for the period October 2012 through December 2013 for 1,371 MMBtu over the 15-month period. To finance the uplift in the natural gas swap price for the period hedged, the Company sold natural gas put options at $3.00 for 1,095 MMbtu for fiscal year 2013 and sold natural gas call options at $4.75 for 456 MMbtu for fiscal year 2014.

Listed in the table below are the outstanding oil and natural gas derivative contracts as of September 30, 2012:
Commodity
 
Instrument
 
Average Notional Volumes per Month
 
Quantity Type
 
Average Floor Price per Instrument
 
Average Ceiling Price per Instrument
 
Period
 
Designation under ASC 815
Crude oil
 
Collar (1)
 
25
 
Bbls
 
$
90.00

 
$
122.00

 
Oct12 - Dec12
 
Designated
Crude oil
 
Collar (1)
 
25
 
Bbls
 
$
95.00

 
$
125.00

 
Oct12 - Dec12
 
Designated
Crude oil
 
Collar (1)
 
40
 
Bbls
 
$
90.00

 
$
116.00

 
Jan13 - Dec13
 
Not Designated
Natural gas
 
Swap (2)
 
91
 
MMbtu
 
$
3.52

 
$
3.52

 
Oct12 - Dec13
 
Not Designated
Natural gas
 
Put Option (2)
 
91
 
MMbtu
 
$
3.00

 
n/a

 
Jan13-Dec13
 
Not Designated
Natural gas
 
Call Option (2)
 
38
 
MMbtu
 
n/a

 
$
4.75

 
Jan14-Dec14
 
Not Designated

(1) A collar is a combination of a sold call option (ceiling) and a purchased put option (floor).

(2) The natural gas swap, put and call option were executed contemporaneously. The "above market" swap price the Company received was offset by the value of the two options sold by the Company. The short natural gas put option, when combined with the swap, creates the potential for a reduction in the effective swap price if NYMEX natural gas prices are below $3.00/MMbtu in 2013. The short natural gas call option, when combined with the Company's long production position, represents a "covered call," and creates a $4.75/MMbtu ceiling during the covered period.

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:
 
 
Balance Sheet Presentation
 
Asset Fair Value
 
Liability Fair Value
 
Net Derivative Fair Value
Commodity
 
Classification
 
Line Description
 
09/30/12
 
12/31/11
 
09/30/12
 
12/31/11
 
09/30/12
 
12/31/11
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Derivatives designated as Hedging Instruments under ASC 815
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas
 
Current
 
Fair market value of derivatives
 
$

 
$

 
$

 
$

 
$

 
$

Natural gas
 
Non-current
 
Other long-term assets
 

 

 

 

 

 

Crude oil
 
Current
 
Fair market value of derivatives
 
469

 
2,499

 

 

 
469

 
2,499

Crude oil
 
Non-current
 
Other long-term liabilities
 

 

 

 

 

 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Subtotals
 
 
 
$
469

 
$
2,499

 
$

 
$

 
$
469

 
$
2,499

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Derivatives not designated as Hedging Instruments under ASC 815
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas
 
Current
 
Fair market value of derivatives
 
$

 
$

 
$
(224
)
 
$

 
$
(224
)
 
$

Natural gas
 
Non-current
 
Other long-term liabilities
 

 

 
(312
)
 

 
(312
)
 

Crude oil
 
Current
 
Fair market value of derivatives
 
1,544

 

 

 

 
1,544

 

Crude oil
 
Non-current
 
Other long-term assets
 
969

 

 

 

 
969

 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Subtotals
 
 
 
$
2,513

 
$

 
$
(536
)
 
$

 
$
1,977

 
$

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Totals
 
 
 
$
2,982

 
$
2,499

 
$
(536
)
 
$

 
$
2,446

 
$
2,499



6

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


Derivatives designated as hedging instruments

Certain of the Company’s crude oil derivative contracts in effect during 2012 are designated as cash flow hedges, and are 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 are recorded as an increase or decrease in crude oil revenues.  Both changes in fair value and cash settlements of ineffective derivative contracts are recognized as derivative expense (income).

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,
 
 
2012
 
2011
 
2012
 
2011
Amount of gain (loss) reclassified from OCI into income (effective portion)
 
$
260

 
$
88

 
$
772

 
$
(361
)
Amount of gain (loss) recognized in income (ineffective portion and amount excluded from effectiveness testing)
 
(282
)
 
159

 
40

 
177


Derivatives not designated as hedging instruments

As discussed in the Company's Form 10-K for the year ended December 31, 2011, the Company elected not to designate any of its derivative contracts entered into subsequent to December 31, 2011 as an accounting hedge under FASB ASC 815, nor does it expect to designate future derivative contracts. Consequently, any derivative contract not designated as an accounting hedge is carried at its fair value on the balance sheet with both realized and unrealized (mark-to-market) gains or losses on these derivatives 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,
 
 
2012
 
2011
 
2012
 
2011
Natural gas derivatives
 
 
 
 
 
 
 
 
     Realized gain (loss), net
 
$

 
$

 
$

 
$

     Unrealized gain (loss), net
 
(205
)
 

 
(536
)
 

          Sub-total gain (loss), net
 
$
(205
)
 
$

 
$
(536
)
 
$

 
 
 
 
 
 
 
 
 
Crude oil derivatives
 
 
 
 
 
 
 
 
     Realized gain (loss), net
 
$

 
$

 
$

 
$

     Unrealized gain (loss), net
 
(1,393
)
 

 
2,513

 

          Sub-total gain (loss), net
 
$
(1,393
)
 
$

 
$
2,513

 
$

 
 
 
 
 
 
 
 
 
Total gain (loss) on derivative instruments, net
 
$
(1,598
)
 
$

 
$
1,977

 
$


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, Short-Term Investments. The carrying amounts for these instruments approximate fair value due to the short-term nature or maturity of the instruments.
 

7

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


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, 2012
 
December 31, 2011
 
 
Carrying Value
 
Fair Value
 
Carrying Value
 
Fair Value
13% Senior Notes due 2016 (1)
 
$
111,450

 
$
100,839

 
$
125,345

 
$
110,571


(1) Fair value is calculated only in relation to the $96,961 and $106,961 principal outstanding of the Senior Notes at the dates indicated above, respectively.  The remaining $14,489 and $18,384, 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: The Company's derivative instruments consist of financially settled commodity swap and option contracts with certain counterparties. The Company determines the value of its derivative contracts based on an income approach using a discounted cash flow model for swaps and a standard option pricing model for options. The inputs used in these models are readily available in the markets.

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. A credit valuation adjustment ("CVA") is made that is based on the default probabilities by year as indicated by market quotes for the Company's or counterparties' credit default swap rates, as appropriate. If credit default rates for the Company or its counterparties are not available, market quotes of credit default rates for similar companies are used. These default probabilities have been applied to the unadjusted fair values of derivative instruments to arrive at the CVA.

The Company has consistently applied these valuation techniques in all periods presented, and believes that these inputs primarily 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.

The following tables present the Company’s liabilities measured at fair value on a recurring basis for each hierarchy level:
As of 9/30/2012
 
Balance Sheet Presentation
 
Level 1
 
Level 2
 
Level 3
 
Total
Assets
 
 
 
 
 
 
 
 
 
 
Derivative financial instruments - current
 
Fair market value of derivatives
 
$

 
$
2,013

 
$

 
$
2,013

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

 
969

 

 
969

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

 
$
224

 
$

 
$
224

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

 
312

 

 
312

Total
 
 
 
$

 
$
2,446

 
$

 
$
2,446

 
 
 
 
 
 
 
 
 
 
 
As of 12/31/2011
 
Balance Sheet Presentation
 
Level 1
 
Level 2
 
Level 3
 
Total
Assets
 
 
 
 

 
 

 
 

 
 

Derivative financial instruments - current
 
Fair market value of derivatives
 
$

 
$
2,499

 
$

 
$
2,499

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

 

 

 

Total
 
 
 
$

 
$
2,499

 
$

 
$
2,499



8

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


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 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, 2012, including upward revisions of $0, were Level 3 fair value measurements. See Note 8, Asset Retirement Obligations, which provides a summary of changes in the ARO liability.

Note 7 - Income Taxes

The effective tax rate for the nine months ended September 30, 2012 and 2011 was 33% and 0%, respectively. The variance is attributable to the impact of the valuation allowance against the Company's net deferred tax asset throughout 2011 until it was reversed as of December 31, 2011. The most significant change from 2011 to 2012 other than the valuation allowance was an increase in the expected statutory depletion rate in 2012.

We have no liability for uncertain tax positions or any accrued interest or penalties as of September 30, 2012.

Note 8 - Asset Retirement Obligations

The following table summarizes the Company’s asset retirement obligations activity for the nine months ended September 30, 2012:
Asset retirement obligations at January 1, 2012
 
$
13,938

Accretion expense
 
1,709

Liabilities incurred
 
202

Liabilities settled
 
(660
)
Revisions to estimate
 
(1,185
)
Asset retirement obligations at end of period
 
14,004

Less: Current asset retirement obligations
 
2,340

Long-term asset retirement obligations at September 30, 2012
 
$
11,664


Liabilities settled primarily relate to properties located in the Gulf of Mexico that were plugged and abandoned during the period.

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 $3,796 at September 30, 2012. 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 9 - Global Settlement with Joint Interest Partner

During May 2011, the Company entered into a final project wind-down agreement (the “Agreement”) with CIECO.  As a result of this Agreement, which included both the assignment of the rights to the Entrada assets and the proceeds from the ultimate sale of such assets, the Company gained the power to direct the activities related to the sale of the remaining assets, and therefore became the primary beneficiary of Callon Entrada.  Therefore, Callon Entrada was consolidated in the Company's consolidated financial statements, effective April 29, 2011.  Upon consolidating Callon Entrada, the Company estimated the fair values of the assets acquired to be $11,349 and liabilities assumed, primarily deferred tax liabilities associated with the tax basis difference in the assets, of Callon Entrada to be $2,681 as a result of this Agreement. Also in connection with this Agreement, Callon Entrada agreed to pay to CIECO approximately $438, which represented the net balance of joint interest billings due to CIECO and which had been previously accrued. The agreement also included joint releases of each party from any further liabilities or obligations to the other party in connection with the Entrada project.  The adjusted fair market value of the net assets acquired of approximately $8,668 were recorded during 2011 as a $5,041 gain and $3,718 as an adjustment to the Company's full cost pool of oil and natural gas properties.

As of September 30, 2012, the remaining unsold assets had carrying values of $5,987, and are included in the Company's balance sheet as a component of Other property and equipment, net. The Company is actively marketing these assets.

Note 10 – Equity Transactions

During February 2011, the Company received $73,765 in net proceeds through the public offering of 10,100 shares of its common stock, which included the issuance of 1,100 shares pursuant to the underwriters’ over-allotment option. As discussed in Note 4, the Company used a portion of the proceeds to redeem $31,000 principal, or 22%, of its Senior Notes. The remaining proceeds were used for general corporate purposes including acreage acquisitions and the accelerated development of the Company’s Permian Basin and other onshore assets.

9




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 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,” "may," "will," 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; 
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 oil and natural gas. These risks include, but are not limited to, the risks described in Item 1A our Annual Report on Form 10-K for the year ended December 31, 2011 (the “2011 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 2011 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.


10

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 2011 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. When appropriate, the Company also updates its risk factors in Part II, Item 1A of this filing. 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 oil and natural gas properties since 1950. Prior to 2009, our operations were focused on exploration and production in the Gulf of Mexico.  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 oil and natural gas basins with a particular emphasis on properties with oil-weighted drilling locations.  The cash flows from our Gulf of Mexico properties have been reinvested into the Company's growing portfolio of onshore assets.

Overview and Outlook

For the three and nine months ended September 30, 2012, we reported net (loss) income and fully diluted (loss) earnings per share of $(1.1) million and $(0.03), and $3.2 million and $0.08, respectively, compared to net income and diluted earnings per share of $8.4 million and $0.21 and $32.4 million and $0.85, respectively for the same periods of 2011.  These results are discussed in greater detail within the “Results of Operations” section included below.  

Key accomplishments to date in 2012 include:

We significantly expanded our acreage position in the Permian Basin with the acquisition of 24,609 gross (21,434 net) acres in the Midland Basin, prospective for both vertical and horizontal drilling of multiple zones. The total consideration paid for this expanded leasehold position was approximately $20 million, or approximately $926 per net acre.

We commenced the horizontal development of our East Bloxom field in the southern portion of the Midland Basin, with the drilling of two horizontal wells targeting the Wolfcamp B shale. Both wells were drilled with lateral lengths of over 7,100 feet and are currently on production. The average initial (24-hour) production rate from these two wells was 804 Boe per day, with an oil composition of over 85%. The 30-day average production for these wells was 576 Boe per well per day. 

In the third quarter of 2012, we initiated the evaluation of our 14,470 contiguous net acre position in Borden County, Texas (average 90% working interest) located in the northern portion of the Midland Basin. Also in the third quarter, we began our drilling program with a vertical well followed by two horizontal wells. The first horizontal well was drilled in the Cline shale to a total measured depth of 14,300 feet, including a 6,769 foot lateral and was fracture stimulated in late October and into early November 2012. The second horizontal well is currently drilling in the Mississippian lime, and is scheduled to be fracture stimulated during the fourth quarter of 2012.

In October, the lending group for our $200 million Credit Facility was expanded to include Citibank, NA, IberiaBank, Whitney Bank and OneWest Bank, FSB as participating lenders. Concurrently, the borrowing base was increased to $80 million from the $45 million borrowing base at December 31, 2011. Additionally, the Credit Facility's maturity was extended to March 15, 2016 from September 25, 2012 at year-end 2011.

In June, we redeemed $10 million of our 13% Senior Notes due 2016 (the "Senior Notes") for $10.2 million. The repurchase reduced the Senior Notes balance to $97 million, and results in annualized cash interest savings of $1.3 million.

Highlights of our onshore and deepwater development program 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 38,331 gross (32,649 net) acres as of November 1, 2012. In order to advance our growth plans, we are directing a significant amount of our 2012 capital budget to horizontal drilling and new acreage acquisitions in the Permian Basin. Based

11

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

on completed and planned operational activity in 2012, we will drill five horizontal wells targeting three distinct intervals in the Wolfcamp B, Cline shales and the Mississippi lime.

Southern Portion: We currently own approximately 11,215 net acres in the southern portion of the Permian Basin, an increase of 18% since year-end 2011. Our current production in the southern portion of the Midland Basin (Crockett, Ector, Midland, and Upton Counties in Texas) is primarily from the Wolfberry play, which we believe to be an established, low-risk oil play that includes the Spraberry, Dean, and Wolfcamp formations. Certain of our properties also include the Atoka and Strawn formations.

During the nine months ended September 30, 2012, we drilled 15 gross vertical wells and fracture stimulated 19 gross vertical wells. We currently have four gross vertical wells awaiting fracture stimulation. In addition to our vertical drilling efforts, in the second quarter of 2012 we commenced a horizontal oil shale drilling program at our East Bloxom field in Upton County, initially targeting the Wolfcamp B formation. To date, we have drilled and completed two horizontal wells on our East Bloxom acreage in Upton County, Texas. Each well was drilled to a lateral length of over 7,100 feet, and the Company estimates it has the potential to drill a total of 24 horizontal wells at its East Bloxom field based on current assumptions of 160-acre spacing. As previously noted, the average initial (24-hour) production rate from these two wells was 804 Boe per day, with an oil composition of over 85%. The 30-day average production for these wells was 576 Boe per well per day. 

In order to increase our exposure to horizontal development of the Wolfcamp B shale, we acquired 2,319 gross (1,762 net) acres in southern Reagan County, Texas, which closed on July 5, 2012. We are scheduled to drill our initial horizontal well in November 2012, which is focused on the Wolfcamp B shale.

Northern Portion: We currently own approximately 21,434 net acres in the northern portion of the Midland Basin, which includes the 14,470 net acres in Borden County, Texas that were acquired in the first quarter of 2012 and an additional 6,964 net acres acquired in and since the second quarter of 2012. We paid total consideration of $20 million for these leasehold positions. We believe this acreage is prospective for both horizontal and vertical development. Although the area has experienced a recent increase in drilling activity, the northern portion of the Midland Basin has had limited drilling activity compared with the southern portion of the Basin (where our current production is located), which significantly increases the risk associated with successful drilling activities in this area.

After completing a 3-D seismic survey on our acreage position, we commenced the drilling of an exploratory vertical well in July 2012, subsequently followed by the drilling of two horizontal wells. The first horizontal well was drilled in the Cline shale, and we began fracture stimulating the well in late October 2012. The second horizontal well is currently drilling in the Mississippian lime zone and is scheduled to be completed late in the fourth quarter of 2012.

Onshore – Shale Gas (Haynesville Shale)

We own a 69% working interest in a 624 gross (430 net) acre unit in the Haynesville Shale play in Bossier Parish, Louisiana. Our one producing well in the Haynesville Shale was shut-in for a combined 112 days during the fourth quarter of 2011 and the first quarter of 2012 due to well interference from an offsetting well. Production was restored in mid-March 2012 following a successful remediation operation and, as of September 30, 2012, our Haynesville well was producing approximately 1,500 Mcf of natural gas per day. We currently have no drilling obligations related to this lease position.

Offshore - Deepwater Properties

Our deepwater properties continue to play a key role in our transition to onshore operations by providing strong cash flows used to fund the expansion and development of our onshore positions. Combined production from our two deepwater properties was approximately 445 MBoe during the nine months ended September 30, 2012, equal to approximately 38% of the Company's total production for the period. Production from these properties is approximately 85% crude oil, which in the present market offers favorable pricing in relation to natural gas. Crude oil prices for production from our two deepwater fields are adjusted based upon Mars WTI differential for Medusa production and Argus Bonito WTI differential for Habanero production. These positive differentials are reflected in the realized price reconciliation table provided below within the Results of Operations discussion.

The Medusa platform was shut-in for 28 days during the second quarter of 2012 for planned construction activities on the West Delta 143 oil pipeline through which Medusa's production is transported. Production from the platform was fully restored on June 13, 2012. Due to Hurricane Isaac, the platform was once again shut-in from August 27, 2012 to September 4, 2012. As of November 1, 2012, Medusa was producing approximately 1,350 Boe per day, net. Additionally, the Medusa partner group is currently in the process of evaluating new technical data as future development plans for the field are considered.


12

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

The Habanero Field was shut-in on July 17, 2012 for scheduled maintenance operations on the Auger platform, which processes Habanero production volumes. Production was restored August 24, 2012 but suspended again August 27, 2012 for Hurricane Issac. Habanero was brought back on-line on September 3, 2012 and, as of November 1, 2012, was producing approximately 435 Boe per day, net. In addition, the Habanero #2 well was shut-in on June 12, 2012 due to the mechanical failure of a subsea safety valve. We have received notification from the operator of the Habanero Field that the drilling of the #2 sidetrack well targeting up-dip PUDs will commence during the fourth quarter of 2012

Liquidity and Capital Resources

Historically, our primary sources of funding have been cash flows from operations, borrowings from financial institutions and the sale of debt and equity securities. Cash and cash equivalents decreased by $42.3 million during the first nine months of 2012 to $1.5 million as compared to $43.8 million at December 31, 2011. The decrease in our cash balance is primarily attributable to capital expenditures of $115.4 million during the first nine months of 2012, representing a $41.0 million or 55% increase over the amount spent during the same period in 2011. The capital expenditures for the nine months ended September 30, 2012 include the following (in millions):
Southern Midland Basin
 
$
57.9

Northern Midland Basin
 
11.1

Leasehold acquisitions
 
34.4

Gulf of Mexico
 
1.5

Capitalized general and administrative and interest expenses
 
10.5

    Total capital expenditures
 
$
115.4


The following table summarizes our wells drilled and completed by area during the first nine months of 2012:
 
 
Drilling
 
Completion
 
 
Gross
 
Net
 
Gross
 
Net
Southern Midland Basin vertical wells
 
15

 
10.7

 
19

 
14.8

Southern Midland Basin horizontal wells
 
2

 
2.0

 
2

 
2.0

     Total
 
17

 
12.7

 
21

 
16.8


 
 
Drilling
 
Completion
 
 
Gross
 
Net
 
Gross
 
Net
Northern Midland Basin vertical wells
 
1

 
0.8

 

 

Northern Midland Basin horizontal wells
 
1

 
1.0

 

 

     Total
 
2

 
1.8

 

 


On June 20, 2012, Regions Bank increased the Company's Credit Facility to $200 million with an associated borrowing base under the Credit Facility of $60 million and a maturity of July 31, 2014. In October 2012, the Credit Facility was amended to increase the borrowing base to $80 million, extend the maturity to March 15, 2016 and add Citibank, NA, IberiaBank, Whitney Bank and OneWest Bank, FSB as participating lenders. Regions Bank continues to serve as Administrative Agent for the facility. 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 borrowing base and scheduled maturity at year-end 2011 were $45 million and September 25, 2012, respectively. The Credit Facility is secured by mortgages covering the Company's major producing fields.

As of September 30, 2012, the balance outstanding under the Credit Facility was $40 million with an interest rate on the facility of 2.97%, 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. As of November 7, 2012, the balance outstanding on the Credit Facility was $44 million as the Company drew an additional $4 million in support of the Company's ongoing capital development program, leaving $36 million available for future draws.

At September 30, 2012, following a $10 million principal redemption in June 2012, we had approximately $97 million principal amount of 13% Senior Notes due 2016 outstanding with interest payable quarterly.

13

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


2012 Budget and Capital Expenditures.  For 2012, we designed a flexible capital spending program, which we plan to fund from cash on hand, cash flows from operations and utilization of our Credit Facility. We believe these resources will be adequate to meet our capital, interest payments, and operating requirements for 2012.  Depending on commodity prices or other economic conditions we experience in 2012, and/or changes we elect to make to our capital plan based on the evaluation of our new horizontal drilling initiatives or availability of acreage acquisitions, our capital budget may be adjusted up or down.

Our revised 2012 capital budget approximates $152 million, and represents a 53% increase over 2011 actual capital expenditures.  The increase in the 2012 capital budget over the previous estimate of $139 million primarily relates to the spending on additional infrastructure to support our new horizontal drilling initiatives and increased expenditures to acquire additional acreage. Of the $152 million, over 80% is allocated to onshore drilling, development and leasehold acquisition activity in the Permian Basin.  Major components of this portion of the budget include:

Drilling approximately 22 gross wells, including five horizontal wells, 16 vertical wells and one salt water disposal well
Establishing new infrastructure and facilities to support our new horizontal drilling efforts
Performing geologic and geophysical work in the Permian Basin
Acquiring acreage in both the northern and southern portions of the Midland Basin

The planned Habanero #2 sidetrack well accounts for approximately 7% of the capital budget with the remainder of the capital budget allocated to planned Gulf of Mexico projects and capitalized expenses.
 
In addition to current cash balances of $1.1 million at November 7, 2012, we have $36 million of borrowing capacity available under our Credit Facility.  We believe that this liquidity position, 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 2012.

Summary cash flow information is provided as follows:

Operating Activities.  For the nine months ended September 30, 2012, net cash provided by operating activities decreased $16.5 million to $41.4 million, from $57.9 million for the same period in 2011.  The decrease relates primarily to lower revenues due to both a 4% decrease in crude oil production, a 33% decrease in natural gas production and a 29% decrease in the average sales price realized for natural gas, all of which were partially offset by a 1% increase in the average sales price realized for crude oil. The production prices are discussed below within Results of Operations.

Investing Activities.  For the nine months ended September 30, 2012, net cash used in investing activities was $113.5 million as compared to $65.8 million for the same period in 2011. The $47.6 million increase in net cash used in investing activities is primarily attributable to a $41.0 million increase in capital expenditures, which includes the acquisition of additional acreage in Borden County located in the northern portion of the Permian Basin and costs associated with the horizontal drilling activity on our East Bloxom Permian Basin acreage.

Financing Activities.  For the nine months ended September 30, 2012, net cash provided by financing activities was $29.8 million compared to cash provided by financing activities of $38.7 million during the same period of 2011.  Of our net $40 million draw on our Credit Facility, $30 million was used to support our Permian acreage development and $10 million was used to redeem $10 million principal value of our Senior Notes outstanding. The 2011 net cash provided by financing activities included $73.8 million of net proceeds from an equity offering offset by approximately $35.1 million used to redeem a $31 million principal portion of our outstanding Senior Notes and to pay the $4.0 million call premium and other redemption expenses.

14

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

Results of Operations

The following table sets forth certain unaudited operating information with respect to the Company's oil and natural gas operations for the periods indicated:
 
 
Three Months Ended September 30,
 
 
 
2012
 
2011
 
Change
 
% Change
 
Net production:
 
 
 
 
 
 
 
 
 
Crude oil (MBbls)
 
251

 
270

 
(19
)
 
(7
)%
*
Natural gas (MMcf)
 
890

 
1,284

 
(394
)
 
(31
)%
*
Total production (MBoe)
 
399

 
484

 
(85
)
 
(18
)%
 
Average daily production (MBoe)
 
4.3

 
5.3

 
(1.0
)
 
(18
)%
 
 
 
 
 
 
 
 
 
 
 
Average realized sales price (a):
 
 

 
 

 
 

 
 

 
Crude oil (Bbl)
 
$
95.86

 
$
98.27

 
$
(2.41
)
 
(2
)%
 
Natural gas (Mcf)
 
$
3.76

 
$
5.46

 
$
(1.70
)
 
(31
)%
 
Total on an equivalent basis (Boe)
 
$
68.67

 
$
69.31

 
$
(0.64
)
 
(1
)%
 
 
 
 
 
 
 
 
 
 
 
Crude oil and natural gas revenues (in thousands):
 
 

 
 

 
 

 
 

 
Crude oil revenue
 
$
24,061

 
$
26,537

 
$
(2,476
)
 
(9
)%
 
Natural gas revenue
 
3,341

 
7,013

 
(3,672
)
 
(52
)%
 
Total
 
$
27,402

 
$
33,550

 
$
(6,148
)
 
(18
)%
 
 
 
 
 
 
 
 
 
 
 
Additional per Boe data:
 
 

 
 

 
 

 
 

 
Sales price
 
$
68.67

 
$
69.31

 
$
(0.64
)
 
(1
)%
 
Lease operating expense
 
14.69

 
12.35

 
2.34

 
19
 %
 
Operating margin
 
$
53.98

 
$
56.96

 
$
(2.98
)
 
(5
)%
 
 
 
 
 
 
 
 
 
 
 
Other expenses per Boe:
 
 

 
 

 
 

 
 

 
Depletion, depreciation and amortization
 
$
29.99

 
$
26.88

 
$
3.11

 
12
 %
 
General and administrative
 
16.14

 
7.16

 
8.98

 
125
 %
 
 
 
 
 
 
 
 
 
 
 
(a) Below is a reconciliation of the average NYMEX price to the average realized sales price:
 
 
 
 
 
 
 
 
 
 
 
Average NYMEX price per barrel of crude oil
 
$
92.22

 
$
89.78

 
$
2.44

 
3
 %
 
Basis differential and quality adjustments
 
3.28

 
9.10

 
(5.82
)
 
(64
)%
 
Transportation
 
(0.68
)
 
(0.94
)
 
0.26

 
(28
)%
 
Hedging
 
1.04

 
0.33

 
0.71

 
215
 %
 
Average realized price per barrel of crude oil
 
$
95.86

 
$
98.27

 
$
(2.41
)
 
(2
)%
 
 
 
 
 
 
 
 
 
 
 
Average NYMEX price per million British thermal units (“MMBtu”)
 
$
2.90

 
$
4.29

 
$
(1.39
)
 
(32
)%
 
Basis differential, quality and Btu adjustments
 
0.86

 
1.17

 
(0.31
)
 
(26
)%
 
Hedging
 

 

 

 
 %
 
Average realized price per Mcf of natural gas
 
$
3.76

 
$
5.46

 
$
(1.7
)
 
(31
)%
 
   
* Please refer to the Crude oil and Natural gas revenue discussions included below for an explanation of the production declines.

15

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

 
 
Nine Months Ended September 30,
 
 
 
2012
 
2011
 
Change
 
% Change
 
Net production:
 
 
 
 
 
 
 
 
 
Crude oil (MBbls)
 
716

 
746

 
(30
)
 
(4
)%
*
Natural gas (MMcf)
 
2,695

 
4,014

 
(1,319
)
 
(33
)%
*
Total production (MBoe)
 
1,165

 
1,415

 
(250
)
 
(18
)%
 
Average daily production (MBoe)
 
4.3

 
5.2

 
(0.9
)
 
(18
)%
 
 
 
 
 
 
 
 
 
 
 
Average realized sales price (a):
 
 

 
 

 
 

 
 

 
Crude oil (Bbl)
 
$
100.39

 
$
99.82

 
$
0.57

 
1
 %
 
Natural gas (Mcf)
 
$
3.77

 
$
5.33

 
$
(1.56
)
 
(29
)%
 
Total on an equivalent basis (Boe)
 
$
70.44

 
$
67.75

 
$
2.69

 
4
 %
 
 
 
 
 
 
 
 
 
 
 
Crude oil and natural gas revenues (in thousands):
 
 

 
 

 
 

 
 

 
Crude oil revenue
 
$
71,883

 
$
74,428

 
$
(2,545
)
 
(3
)%
 
Natural gas revenue
 
10,174

 
21,404

 
(11,230
)
 
(52
)%
 
Total
 
$
82,057

 
$
95,832

 
$
(13,775
)
 
(14
)%
 
 
 
 
 
 
 
 
 
 
 
Additional per Boe data:
 
 

 
 

 
 

 
 

 
Sales price
 
$
70.44

 
$
67.75

 
$
2.69

 
4
 %
 
Lease operating expense
 
17.57

 
11.54

 
6.03

 
52
 %
 
Operating margin
 
$
52.87

 
$
56.21

 
$
(3.34
)
 
(6
)%
 
 
 
 
 
 
 
 
 
 
 
Other expenses per Boe:
 
 

 
 

 
 

 
 

 
Depletion, depreciation and amortization
 
$
30.90

 
$
25.27

 
$
5.63

 
22
 %
 
General and administrative
 
13.60

 
8.12

 
5.48

 
67
 %
 
 
 
 
 
 
 
 
 
 
 
(a) Below is a reconciliation of the average NYMEX price to the average realized sales price:
 
 
 
 
 
 
 
 
 
 
 
Average NYMEX price per barrel of crude oil
 
$
96.21

 
$
95.48

 
$
0.73

 
1
 %
 
Basis differential and quality adjustments
 
3.84

 
5.84

 
(2.00
)
 
(34
)%
 
Transportation
 
(0.74
)
 
(1.02
)
 
0.28

 
(27
)%
 
Hedging
 
1.08

 
(0.48
)
 
1.56

 
(325
)%
 
Average realized price per barrel of crude oil
 
$
100.39

 
$
99.82

 
$
0.57

 
1
 %
 
 
 
 
 
 
 
 
 
 
 
Average NYMEX price per million British thermal units (“MMBtu”)
 
$
2.43

 
$
4.29

 
$
(1.86
)
 
(43
)%
 
Basis differential, quality and Btu adjustments
 
1.34

 
1.04

 
0.30

 
29
 %
 
Hedging
 

 

 

 
 %
 
Average realized price per Mcf of natural gas
 
$
3.77

 
$
5.33

 
$
(1.56
)
 
(29
)%
 

* Please refer to the Crude oil and Natural gas revenue discussions included below for an explanation of the production declines.


16