Attached files
| file | filename |
|---|---|
| 8-K - 8-K - CALLON PETROLEUM COMPANY - EARNINGS AND GUIDANCE - Callon Petroleum Co | a2013-q3form8xkearningsgui.htm |
| EX-99.2 - CALLON PETROLEUM COMPANY GUIDANCE RELEASE - Callon Petroleum Co | a2013-q3xex992xguidancepre.htm |
| EX-99.3 - CALLON PETROLEUM COMPANY EARNINGS CALL ANNOUNCEMENT RELEASE - Callon Petroleum Co | a2013-q3xex993xearningscal.htm |
Exhibit 99.1
Callon Petroleum Company Reports Financial and Operational Results For The Third Quarter of 2013
Natchez, MS (November 6, 2013) - Callon Petroleum Company (NYSE: CPE) (“Callon” or the “Company”) today reported results of operations for the three-month period ended September 30, 2013.
The Company highlighted third quarter financial results and recent operational activity:
• | Average total quarterly production of 4,370 Boepd, a sequential increase of 21% |
• | Average Permian quarterly production of 2,456 Boepd, a sequential increase of 31% |
• | Discretionary cash flow, a non-GAAP financial measure, of $19.2 million, a sequential increase of 86% |
• | Net loss of $0.02 per diluted share, or net income of $0.03 per diluted share excluding the impact of unrealized mark-to-market derivative positions on a non-GAAP basis |
• | Continued delineation of Borden County with a vertical test of the Mississippian chat with a peak 24-rate of 326 boepd |
Fred Callon, Chairman and CEO said, “We continue to be encouraged by our progress in the Permian Basin. As a result, Callon added a second horizontal rig in the third quarter to accelerate the development of our inventory that continues to expand through ongoing delineation efforts and downspacing initiatives on our existing leases. Following the completion of the sale of our Gulf of Mexico assets, we will be entirely focused on our Midland Basin opportunity set and positioned to unlock the value of our assets with an improved cost of capital and steadily increasing knowledge base.”
Operations Update
Permian Basin. The Company’s net production in the Permian Basin averaged 2,456 barrels of oil per day (“boepd”) in the third quarter of 2013. During the third quarter, Callon drilled four gross horizontal wells and completed four gross horizontal wells, all of which were located in the southern Midland Basin. Additional details regarding the Company’s horizontal drilling program are highlighted below:
East Bloxom (Upton County)
Three Upper Wolfcamp B wells were recently completed in the third quarter with an average lateral length of 8,260’. Two of these wells, the Neal 323H and Neal 324H, are currently flowing back. A third well, the Neal 322H, was recently placed on production after being shut-in for completion of two wells drilled from the same pad. In addition, a two-well pad has commenced drilling on the lease as part of the Company’s ongoing program development of the Wolfcamp B shale. Following our review of over a year of horizontal production performance in the field, these wells are being downspaced to accommodate seven laterals across one section (or the equivalent of 137 acres per 7,500’ lateral).
The Company also completed a test of the Wolfcamp A shale in the third quarter. The well produced at a peak 24-hour rate of 302 boepd (92% oil) and a peak 30-day rate of 178 boepd (78% oil). This well, the Neal 341H, was planned to have 28 fracture stimulation stages, but the Company believes that only eight stages were properly stimulated due to a problem with mechanical plugs. The Company currently plans to drill its second Wolfcamp A well in the first quarter of 2014.
Taylor Draw (Reagan County)
The Company is in the process of completing a three-well pad at the Taylor Draw lease, which is expected to commence production in December 2013. These wells were drilled to an average lateral length of 8,250’ and are targeting the Lower Wolfcamp B. Callon’s first Lower Wolfcamp B well, the Weatherby #1H, produced at a peak 24-hour rate of 755 boepd (86% oil) and a peak 30-day rate of 455 boepd (81% oil).
The Company also completed two Upper Wolfcamp B wells, the Weatherby #2H and #3H, during the third quarter. These wells produced at an average peak 24-rate of 634 boepd (92% oil) and an average peak 30-day rate of 354 boepd (76% oil) from an average lateral length of 5,917’.
Carpe Diem (Midland County)
The Company is in the process of drilling the second well on a two-well pad, each with a planned lateral length of over 9,000’. These Upper Wolfcamp B wells are currently anticipated to be completed in early 2014.
Garrison Draw (Reagan County)
Callon drilled its first Upper Wolfcamp B well on this lease that was acquired in the second quarter of 2013. The well was drilled to a lateral length of 5,417’ and is currently flowing back.
In total, the Company currently expects to bring six additional horizontal wells on production in the fourth quarter of 2013, including the Neal 323H and 324H that are currently flowing back as described above.
Baird Ranch (Borden County)
Callon continues to progress its delineation efforts on its acreage in Borden County. 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). This well was completed as a single stage slickwater completion in the Mississippian chat.
The following table summarizes drilled and completed wells through September 30, 2013:
Drilled | Completed (a) | |||||||||||
Gross | Net | Gross | Net | |||||||||
Southern portion: | ||||||||||||
Vertical wells | 1 | 1.00 | — | — | ||||||||
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. |
Gulf of Mexico. The Company’s net interest in the Medusa field produced an average net rate of 1,017 Boepd during the three months ended September 30, 2013, approximately 89% being crude oil.
In addition, the Gulf of Mexico shelf properties produced at an average net rate of 864 Boepd for the third quarter.
The Company recently announced the sale of substantially all of its Gulf of Mexico operations for total cash consideration of $100 million, before 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.
Other. Callon entered into an agreement to sell its 69% interest in the Swan Lake field for $2 million. This field includes 429 net acres and produced approximately 173 thousand cubic feet per day during the three months ended September 30, 2013. This is the Company’s only field in the Haynesville shale.
Summary Financial Results
Operating Revenues. Operating revenues for the three months ended September 30, 2013 include oil and natural gas sales of $30.8 million from average production of 4,370 Boepd. These results compare with oil and natural gas sales of $27.4 million from average production of 4,337 Boepd during the comparable 2012 period.
Crude Oil Revenue. Crude oil revenues increased 12% to $27.0 million for the three months ended September 30, 2013 compared to revenues of $24.1 million for the same period of 2012. Contributing to the increase in crude oil revenue was a 10% increase in
realized crude oil prices compounded by a 2% increase in production. The average realized sales price increased to $105.11 per barrel during the third quarter of 2013 compared to $95.86 during the same period in 2012. The increase in production was primarily attributable to a 43 thousand barrels (“MBbls”) increase in production from our Permian properties, partially offset by a 19 MBbls decline in production from our Medusa field due to normal and expected declines, and the sale of our deepwater Habanero field in the fourth quarter of 2012, which produced 17 MBbls in the third quarter of 2012.
Natural Gas Revenue. Natural gas revenues of $3.8 million increased 13% during the three months ended September 30, 2013 as compared to natural gas revenues of $3.3 million for the same period of 2012. The increase primarily relates to a 16% increase in the average price realized partially offset by a 3% decrease in natural gas volumes. The decrease in production was driven largely by the sale of Habanero, the plugging and abandonment of our Mobile Bay 908 property, and normal and expected declines from our existing wells. These declines were primarily offset by the 106 million cubic feet increase in natural gas production from our Permian properties and an increase from our East Cameron 257 field, which had been shut-in since November 2011 and returned to production in May of 2013.
Lease Operating Expenses. Total lease operating expenses, including ad valorem taxes, remained relatively flat for the three months ended September 30, 2013. The slight increase is related to the significant growth in the number of wells now producing on our Permian Basin properties, partially offset by the sale of our interest in the Habanero deepwater property in December 2012. For the third quarter, lease operating expenses for the Permian properties were $2.5 million, excluding workover costs, or $11.21 per Boe.
Production Taxes. Production taxes increased 51% for the three months ended September 30, 2013 as compared to the same period of 2012, due to an increase of onshore production subject to these taxes while our offshore production is exempt from production taxes.
General and Administrative Expenses. General and administrative expenses, net of amounts capitalized, decreased $0.6 million during the three months ended September 30, 2013 compared to the same period of 2012 and relates primarily to costs in 2012 for non-recurring additional employee-related items including early retirement and severance expense for which we had no similar costs in the current period.
Interest Expense. Interest expense incurred during the three months ended September 30, 2013 decreased $0.7 million or 34% to $1.4 million compared to $2.1 million for the same period of 2012. The decrease in interest expense is primarily related to an increase in capitalized interest of $0.5 million resulting from a higher average unevaluated property balance for the three months ended September 30, 2013 compared to the corresponding period of 2012.
Preferred Stock Dividends. On September 3, 2013, the Board of Directors declared a dividend of $1.25 per share, or a total of $2.0 million, 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.
Net Income. For the three months ended September 30, 2013, the Company reported net loss of $0.9 million and $0.02 per diluted share, compared to net loss of $1.1 million and $0.03 per diluted share respectively for the same period of 2012. On a non-GAAP basis, excluding the after-tax losses related to the unrealized mark-to-market derivative adjustments, Callon reported net income of $1.1 million and earnings per share of $0.03 for the third quarter of 2013.
Discretionary Cash Flow. Discretionary cash flow for the three months ended September 30, 2013 totaled $19.2 million compared to $13.0 million during the comparable prior year period. Net cash flow provided by operating activities, as defined by U.S. GAAP, was $15.0 million for the three months ended September 30, 2013 and $13.9 million for the comparable prior year period. (See “Non-GAAP Financial Measures” that follows and the accompanying reconciliation of discretionary cash flow, a non-GAAP measure, to net cash flow provided by operating activities)
Capital Expenditures. Callon’s capital expenditures for the nine months ended September 30, 2013 included the following amounts (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 | ||
Liquidity. At September 30, 2013, the Company’s total liquidity position was $58.9 million comprised of a cash balance of $0.9 million and borrowing availability of $58.0 million under its revolving credit facility. Subsequently, the Company’s borrowing base was established at $83.0 million, 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. To the extent the Company elects not to redeem the 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 2016 Senior Notes outstanding on December 20, 2013 in excess of $48 million.
Earnings Call Information
The Company will host a conference call on Thursday, November 7, 2013 to discuss third quarter 2013 financial and operating results.
Please join Callon Petroleum Company via the Internet for a webcast of the conference call:
Date/Time: Thursday, November 7, 2013, at 1:00 p.m. Central Time (2:00 p.m. Eastern Time)
Webcast: Live webcast will be available at www.callon.com in the “Investors” section of the website.
Alternatively, you may join by telephone:
Toll-free dial-in number: 1-877-546-5018
International dial-in number: 1-857-244-7550
Participant passcode: 76863822
Replay dial-in information:
Primary dial-in number: 1-888-286-8010
Secondary dial-in number: 1-617-801-6888
Participant passcode: 11726817
An archive of the conference call webcast will also be available at www.callon.com in the “Investors” section of the website.
Replay:
Non-GAAP Financial Measures
This news release refers to non-GAAP financial measures as “discretionary cash flow”. Callon believes that the non-GAAP measure of discretionary cash flow is useful as an indicator of an oil and gas exploration and production company’s ability to internally fund exploration and development activities and to service or incur additional debt. The Company also has included this information because changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the company may not control and may not relate to the period in which the operating activities occurred.
Reconciliation of Non-GAAP Financial Measures:
The following table reconciles net cash flow provided by operating activities to discretionary cash flow (in thousands):
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
2013 | 2012 | Change | 2013 | 2012 | Change | ||||||||||||||||||
Discretionary cash flow | $ | 19,150 | $ | 12,959 | $ | 6,191 | $ | 40,739 | $ | 38,595 | $ | 2,144 | |||||||||||
Net working capital changes and other changes | (4,173 | ) | 985 | (5,158 | ) | (5,525 | ) | 2,790 | (8,315 | ) | |||||||||||||
Net cash flow provided by (used in) operating activities | $ | 14,977 | $ | 13,944 | $ | 1,033 | $ | 35,214 | $ | 41,385 | $ | (6,171 | ) | ||||||||||
The following table reconciles income available to common shares to adjusted income (in thousands; reconciling items are reflected net of tax):
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||
Net (loss) income available to common shares | $ | (892 | ) | $ | (1,105 | ) | $ | (1,614 | ) | $ | 3,182 | ||||
Reconciling items, net of tax: | |||||||||||||||
Unrealized derivative loss (gains) | 1,984 | 1,039 | 1,823 | (1,285 | ) | ||||||||||
Gain on early redemption of debt | — | — | — | (888 | ) | ||||||||||
Adjusted net income | $ | 1,092 | $ | (66 | ) | $ | 209 | $ | 1,009 | ||||||
Adjusted net income fully diluted earnings per share | $ | 0.03 | $ | 0.00 | $ | 0.01 | $ | 0.03 | |||||||
The following tables present summary information for the three and nine months ended September 30, 2013, and are followed by the Company’s financial statements.
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: | |||||||||||||||
Average NYMEX price per barrel ("Bbl") of crude oil | $ | 105.82 | $ | 92.22 | $ | 13.60 | 15 | % | |||||||
Basis differential and quality adjustments | (0.24 | ) | 3.28 | (3.52 | ) | (107 | )% | ||||||||
Transportation | (0.47 | ) | (0.68 | ) | 0.21 | (31 | )% | ||||||||
Hedging | — | 1.04 | (1.04 | ) | (100 | )% | |||||||||
Average realized price per Bbl of crude oil | $ | 105.11 | $ | 95.86 | $ | 9.25 | 10 | % | |||||||
Average NYMEX price per million British thermal units (“MMBtu”) | $ | 3.56 | $ | 2.90 | $ | 0.66 | 23 | % | |||||||
Basis differential, quality and Btu adjustments | 0.82 | 0.86 | (0.04 | ) | (5 | )% | |||||||||
Average realized price per Mcf of natural gas | $ | 4.38 | $ | 3.76 | $ | 0.62 | 16 | % | |||||||
Nine Months Ended September 30, | |||||||||||||||
2013 | 2012 | Change | % Change | ||||||||||||
Net production: | |||||||||||||||
Crude oil (MBbls) | 661 | 716 | (55 | ) | (8 | )% | |||||||||
Natural gas (MMcf) | 2,389 | 2,695 | (306 | ) | (11 | )% | |||||||||
Total production (MBoe) | 1,060 | 1,165 | (105 | ) | (9 | )% | |||||||||
Average daily production (MBoe) | 3.9 | 4.3 | (0.4 | ) | (9 | )% | |||||||||
Average realized sales price (a): | |||||||||||||||
Crude oil (Bbl) | $ | 99.27 | $ | 100.39 | $ | (1.12 | ) | (1 | )% | ||||||
Natural gas (Mcf) | $ | 4.39 | $ | 3.77 | $ | 0.62 | 16 | % | |||||||
Average realized sales price on an equivalent basis (Boe) | $ | 71.79 | $ | 70.44 | $ | 1.35 | 2 | % | |||||||
Crude oil and natural gas revenues (in thousands): | |||||||||||||||
Crude oil revenue | $ | 65,615 | $ | 71,883 | $ | (6,268 | ) | (9 | )% | ||||||
Natural gas revenue | 10,483 | 10,174 | 309 | 3 | % | ||||||||||
Total | $ | 76,098 | $ | 82,057 | $ | (5,959 | ) | (7 | )% | ||||||
Additional per Boe data: | |||||||||||||||
Average realized sales price | $ | 71.79 | $ | 70.44 | $ | 1.35 | 2 | % | |||||||
Lease operating expense | 15.48 | 16.04 | (0.56 | ) | (3 | )% | |||||||||
Production taxes | 2.09 | 1.53 | 0.56 | 37 | % | ||||||||||
Operating margin | $ | 54.22 | $ | 52.87 | $ | 1.35 | 3 | % | |||||||
Other expenses per Boe: | |||||||||||||||
Depletion, depreciation and amortization | $ | 31.70 | $ | 30.90 | $ | 0.80 | 3 | % | |||||||
General and administrative | 13.31 | 13.60 | (0.29 | ) | (2 | )% | |||||||||
(a) Below is a reconciliation of the average NYMEX price to the average realized sales price: | |||||||||||||||
Average NYMEX price per barrel ("Bbl") of crude oil | $ | 98.14 | $ | 96.21 | $ | 1.93 | 2 | % | |||||||
Basis differential and quality adjustments | 1.66 | 3.84 | (2.18 | ) | (57 | )% | |||||||||
Transportation | (0.53 | ) | (0.74 | ) | 0.21 | (28 | )% | ||||||||
Hedging | — | 1.08 | (1.08 | ) | (100 | )% | |||||||||
Average realized price per Bbl of crude oil | $ | 99.27 | $ | 100.39 | (1.12 | ) | (1 | )% | |||||||
Average NYMEX price per million British thermal units (“MMBtu”) | $ | 3.68 | $ | 2.43 | $ | 1.25 | 51 | % | |||||||
Basis differential, quality and Btu adjustments | 0.71 | 1.34 | (0.63 | ) | (47 | )% | |||||||||
Average realized price per Mcf of natural gas | $ | 4.39 | $ | 3.77 | $ | 0.62 | 16 | % | |||||||
CALLON PETROLEUM COMPANY CONSOLIDATED BALANCE SHEETS (In thousands, except per share data) | |||||||
September 30, 2013 | December 31, 2012 | ||||||
ASSETS | |||||||
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 | |||
CALLON PETROLEUM COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS (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 | ||||||||||||
CALLON PETROLEUM COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (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 | ||||
This news release is posted on the company’s website at www.callon.com and will be archived there for subsequent review. It can be accessed from the ‘News Releases” link on the top of the homepage.
This news release contains projections forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements include all statements regarding our reserves as well as statements including the words “believe,” “expect,” “plans” and words of similar meaning. These projections and statements reflect the Company’s current views with respect to future events and financial performance. No assurances can be given, however, that these events will occur or that these projections will be achieved, and actual results could differ materially from those projected as a result of certain factors. Some of the factors which could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements include the volatility of oil and gas prices, ability to drill and complete wells, operational, regulatory and environment risks, our ability to finance our activities and other risks more fully discussed in our filings with the Securities and Exchange Commission, including our Annual Reports on Form 10-K, available on our website or the SEC’s website at www.sec.gov.