Attached files
| file | filename |
|---|---|
| 8-K - CALLON PETROLEUM COMPANY FORM 8-K - Callon Petroleum Co | a2013-q2form8xkearningsgui.htm |
| EX-99.2 - NEWS RELEASE - GUIDANCE - Callon Petroleum Co | a2013-q2xguidancepressrele.htm |
| EX-99.3 - NEWS RELEASE - EARNINGS CALL ANNOUNCEMENT - Callon Petroleum Co | a2013-q2xearningscallannou.htm |
Exhibit 99.1
Callon Petroleum Company Reports Results For The Second Quarter of 2013 And Provides Capital Budget Update
Natchez, MS (August 8, 2013) - Callon Petroleum Company (NYSE: CPE) (“Callon” or the “Company”) today reported results of operations for the three-month period ended June 30, 2013. In addition, a presentation regarding second quarter results and an operational update will be posted on the Company’s website at www.callon.com and referenced during the scheduled conference call at 10 a.m. Central Time on August 9, 2013.
The Company highlighted second quarter results and recent operational activity:
• | Quarterly production averaged 3,615 Boepd, including 1,869 Boepd from Permian operations |
• | Net income of $0.00 per diluted share, or net loss of $0.02 per diluted share excluding the impact of unrealized mark-to-market derivative positions on a non-GAAP basis |
• | Discretionary cash flow, a non-GAAP financial measure, of $10.3 million |
• | Production from two upper Wolfcamp B development wells at an average peak 24-hour rate of 1,258 Boepd and an average peak 30-day rate of 634 Boepd |
• | Production from a lower Wolfcamp B evaluation well at a 24-hour rate of 860 Boepd during flowback operations |
• | Completion of the issuance of $75 million of Series A Cumulative Preferred Stock |
• | Increase in the operational budget to $170 million and the addition of a second horizontal drilling rig in the Midland Basin |
• | Acquisition of 2,186 net acres in Reagan and Upton Counties, Texas |
Fred Callon, Chairman and CEO said, “The past quarter represented an important step for our company, as our team demonstrated continued success in the upper Wolfcamp shale development program, in addition to evaluating additional zones for multi-lateral development on our existing acreage. Based on recent drilling results and delineation of multi-year inventory of identified horizontal drilling locations, we are poised to accelerate growth with the addition of a second horizontal drilling rig in the Midland Basin following a sequential production growth rate of approximately 20% in the second quarter.
“We estimate that the impact of a second horizontal rig supports targeted exit rates from our Permian operations of 3,500 Boepd in 2013 and 5,750 Boepd in 2014. Additionally, we expect this activity increase to be a catalyst for meaningful additions to our existing proved developed reserve base as we remain focused on converting acreage to cash flow. This forecasted increase in operating cash flow is complemented by a currently undrawn credit facility, providing us the flexibility to fund our Permian drilling plans for the foreseeable future.”
Operations Update
Permian Basin. The Company’s net production in the Permian Basin averaged 1,869 barrels of oil per day (“Boepd”) in the second quarter of 2013. During the second quarter, Callon drilled five horizontal wells and completed four gross horizontal wells, all of which were located in the southern Midland Basin. The production results for the completed wells are highlighted below on a gross basis:
Initial Production (Boepd) | ||||||||
Well | Target Zone | Lateral Length | Peak 24-Hour Rate | Peak 30-Day Rate | ||||
Neal 343H | Upper Wolfcamp B | 6,323’ | 1,229 (88% oil) | 561 (77% oil) | ||||
Neal 342H | Upper Wolfcamp B | 7,288’ | 1,287 (92% oil) | 707 (78% oil) | ||||
Weatherby 1H | Lower Wolfcamp B | 5,482’ | 860 (96% oil)* | t.b.d. | ||||
Schwartz 1H | Upper Wolfcamp B | 5,368’ | Flowing back | |||||
* Most recent available rate (during flowback) | ||||||||
The Company currently has seven gross horizontal wells in various stages of completion.
Callon drilled two gross vertical wells and completed three gross vertical wells in the second quarter of 2013. Two of the completions were in the central Midland Basin, targeting multiple zones down to the Woodford shale. These wells, combined with an isolated deep test conducted in the first quarter of 2013, indicate meaningful reserve and production contributions from zones below the Atoka formation. In addition, the Company is currently drilling two similar vertical wells at its Carpe Diem field to evaluate the deeper potential on the acreage. The third vertical completion during the quarter was in the northern Midland Basin targeting three shallow intervals.
In June, Callon completed the acquisition of 2,468 gross (2,186 net) acres in Reagan and Upton Counties for a total purchase price of $11 million. The Company has identified an inventory of both horizontal and vertical locations on this acreage, with the drilling of the first horizontal well commencing in early August. This field, Garrison Draw, was producing at an average net rate of approximately 145 Boepd at the time of acquisition.
The following table summarizes drilled and completed wells through June 30, 2013:
Drilled | Completed (a) | |||||||||||
Gross | Net | Gross | Net | |||||||||
Southern portion: | ||||||||||||
Horizontal wells | 9 | 8.22 | 5 | 4.51 | ||||||||
Central portion: | ||||||||||||
Vertical wells | 3 | 1.75 | 4 | 2.29 | ||||||||
Horizontal wells | — | — | — | — | ||||||||
Total central portion | 3 | 1.75 | 4 | 2.29 | ||||||||
Northern portion: | ||||||||||||
Vertical wells | — | — | 1 | 0.75 | ||||||||
Horizontal wells | — | — | 1 | 0.75 | ||||||||
Total northern portion | — | — | 2 | 1.50 | ||||||||
Total | 12 | 9.97 | 11 | 8.30 | ||||||||
(a) | Completions include wells drilled prior to the first half of 2013. |
Gulf of Mexico. The Company’s net interest in the Medusa field, its remaining deepwater property, produced an average net rate of 800 Boepd during the three months ended June 30, 2013, approximately 88% being crude oil. The Medusa platform was shut-in for 23 days during the second quarter of 2013 for planned construction activities on the West Delta 143 oil pipeline through which Medusa’s production is transported. During this period, the stimulation of three existing wells was performed, as well as routine field maintenance. Facility operations were restored on June 27, 2013, and as of August 7, 2013, was producing approximately 1,100 Boepd, net as the field continues to be optimized after being brought back on production.
During the three months ended June 30, 2013, the Gulf of Mexico shelf properties produced at an average net rate of 870 Boepd. Callon completed the first stages of plugging and abandoning its only remaining operated shelf property, Mobile Bay 908, leaving the Company with an interest in five producing fields. Production from the East Cameron Block 257 field, which had been shut-in since November 2011, recommenced on May 9, 2013 and contributed an average of 232 Boepd of net production for the second quarter.
Capital Budget Update
In early August, the Board of Directors approved an increase in the Company’s operational capital budget (excluding acquisitions) of $45 million following the completion of a $75 million offering of cumulative preferred stock in late May. The increased capital will be directed to Callon’s horizontal drilling program, which will be expanded to include the development of its central Midland Basin position in Midland County, Texas. The Company’s current development program in the southern Midland Basin will also be extended to include the newly acquired Garrison Draw field referenced above. To facilitate this accelerated program in established areas of horizontal development, the Company entered into a one-year contract for a second horizontal drilling rig, which began earlier this month drilling at the Garrison Draw field before a planned mobilization to the Carpe Diem field. Callon’s first horizontal drilling rig will continue program development of its East Bloxom and Taylor Draw fields.
The new operational capital budget includes the drilling of 22 gross horizontal wells and the completion of 17 gross horizontal wells in 2013, an increase of nine wells and five wells, respectively. The details of the expenditure program are highlighted below:
Midland Basin | $ | 142 | ||
Gulf of Mexico | 11 | |||
Total budgeted capital expenditures | $ | 153 | ||
Capitalized general and administrative costs | 13 | |||
Capitalized interest and other | 4 | |||
Total budgeted capitalized expenses | $ | 17 | ||
Total operational budget | 170 | |||
Acquisition - Southern Midland Basin | 11 | |||
Total capital expenditures | $ | 181 | ||
Summary Financial Results
Operating Revenues. Operating revenues for the three months ended June 30, 2013 include oil and natural gas sales of $22.8 million from average production of 3,615 Boepd. These results compare with oil and natural gas sales of $25.4 million from average production of 4,110 Boepd during the comparable 2012 period.
Crude Oil Revenue. Crude oil revenues decreased 14% to $19.1 million for the three months ended June 30, 2013 compared to revenues of $22.1 million for the same period of 2012. Contributing to the decrease in crude oil revenue was a 3% decrease in realized commodity prices compounded by a 11% decrease in production. In the second quarter of 2013, the average price realized for our crude oil volumes for the quarter decreased to $96.27 per barrel compared to $98.78 for the same period of 2012. The decrease in production for the quarter was primarily attributable to the sale of our deepwater Habanero field in the fourth quarter of 2012, which produced 31 thousand barrels of oil (“MBbls”) during the second quarter of 2012. Also contributing to the decrease was 23 days of down time at our Medusa field for scheduled pipeline maintenance. Additionally, normal and expected declines further reduced oil production. Partially offsetting these decreases in our Gulf of Mexico and other properties was a 21 MBbls increase in production from our Permian properties.
Natural Gas Revenue. Natural gas revenues of $3.7 million increased 13% during the three months ended June 30, 2013 as compared to natural gas revenues of $3.3 million for the same period of 2012. The increase primarily relates to a 29% increase in the average price realized to $4.70 per thousand cubic feet of natural gas produced. Compared to the second quarter of 2012, natural gas volumes decreased 13% primarily due to the sale of Habanero, from which we produced 52 million cubic feet (“MMcf’) of natural gas during the second quarter of 2012, and due to a decline in production from our Haynesville well, which produced 66 MMcf less during the second quarter of 2013 compared to the same quarter of 2012. Other normal and expected declines, primarily from our Gulf of Mexico shelf properties, also pushed overall production lower. These production decreases were partially offset by a 49 MMcf increase from our Permian properties and by a 72 MMcf increase from our East Cameron 257 field, which returned to production in May of 2013.
Lease Operating Expenses. Lease operating expenses, while flat on an absolute basis for the three months ended June 30, 2013 increased by 17% to $16.36 per barrel of oil equivalent (“Boe”) compared to $14.03 per Boe for the same period in 2012. The increase primarily relates to $0.6 million, or $1.90 per Boe, in workover costs associated with our Medusa field with the remainder related to growth in the number of wells now producing in our Permian Basin properties. These increases were partially offset by the sale of our Habanero deepwater property in December 2012.
Production Taxes. Production taxes increased 19% for the three months ended June 30, 2013 as compared to the same period of 2012. The increase relates to an increase of onshore production subject to these taxes while our deepwater offshore production is exempt from production taxes.
General and Administrative Expenses. General and administrative expenses, net of amounts capitalized, remained relatively flat for the three months ended June 30, 2013 compared to the same period of 2012.
Interest Expense. Interest expense incurred during the three months ended June 30, 2013 decreased $0.8 million or 36% to $1.5 million compared to $2.4 million for the same period of 2012. The decrease in interest expense is primarily related to an increase in capitalized interest of $0.8 million resulting from a higher average unevaluated property balance for the three months ended June 30, 2013 compared to the corresponding period of 2012.
Income Tax Expense. The unusually high effective tax rate (“ETR”) of 46% for the three months ended June 30, 2013 relates to the treatment of certain discrete items occurring in the second quarter of 2013, including shortfalls associated with the Company’s restricted stock awards vesting during the period. We expect the full-year 2013 ETR to approximate 30%, excluding discrete items.
Preferred Stock Dividends. On May 30, 2013, the Company issued $75.0 million of 10.0% Series A Cumulative Preferred Stock (the “Preferred Stock”). The first dividend date for the Preferred Stock was June 30, 2013, and these dividends were paid on June 28, 2013 in the amount of $0.7 million for the stub period beginning with the issuance on May 30, 2013 through the first dividend date.
Net Income. For the three months ended June 30, 2013, the Company reported net income of $0.1 million and $0.00 per diluted share, compared to net income and diluted earnings per share of $3.8 million and $0.09, respectively for the same period of 2012. Excluding the after-tax gains related to the unrealized mark-to-market derivative adjustments, Callon reported net loss of $0.8 million and loss per share of $0.02 for the second quarter of 2013.
Discretionary Cash Flow. Discretionary cash flow for the three months ended June 30, 2013 totaled $10.3 million compared to $12.3 million during the comparable prior year period. Net cash flow provided by operating activities, as defined by U.S. GAAP, was $7.4 million for the three months ended June 30, 2013, and $17.1 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 three months ended June 30, 2013 included the following amounts (in millions):
Southern Midland Basin | $ | 43 | ||
Central Midland Basin | 4 | |||
Northern Midland Basin | 3 | |||
Total capital expenditures | $ | 50 | ||
Capitalized general and administrative costs | 5 | |||
Capitalized interest and other | 2 | |||
Total capitalized expenses | $ | 7 | ||
Total operational expenditures | 57 | |||
Acquisition - Southern Midland Basin | 11 | |||
Total capital expenditures | $ | 68 | ||
Liquidity. At June 30, 2013, the Company’s total liquidity position was $88.4 million comprised of a cash balance of $13.4 million and borrowing availability of $75.0 million under its revolving credit facility with a current borrowing base of $75 million that was established in April 2013 and is anticipated to be redetermined in the third quarter of 2013.
Earnings Call Information
The Company will host a conference call on Friday, August 9, 2013 to discuss second quarter 2013 financial and operating results.
Please join Callon Petroleum Company via the Internet for a webcast of the conference call:
Date/Time: Friday, August 9, 2013, at 10:00 a. m. Central Time (11:00 a.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 Call-in number: 877-317-6789
Toll / International Call-in Number: 412-317-6026
An archive of the conference call webcast will also be available at www.callon.com in the “Investors” section of the website.
Presentation slides that will be discussed during the conference call will be available on the Company’s website at www.callon.com in the “Events and Presentations” section.
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 June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
2013 | 2012 | Change | 2013 | 2012 | Change | ||||||||||||||||||
Discretionary cash flow | $ | 10,281 | $ | 12,331 | $ | (2,050 | ) | $ | 21,589 | $ | 25,636 | $ | (4,047 | ) | |||||||||
Net working capital changes and other changes | (2,919 | ) | 4,760 | (7,679 | ) | (1,352 | ) | 1,805 | (3,157 | ) | |||||||||||||
Net cash flow provided by (used in) operating activities | $ | 7,362 | $ | 17,091 | $ | (9,729 | ) | $ | 20,237 | $ | 27,441 | $ | (7,204 | ) | |||||||||
The following table reconciles income available to common shares to adjusted income (in thousands; reconciling items are reflected net of tax):
Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||
Net (loss) income available to common shares | $ | 78 | $ | 3,799 | $ | (722 | ) | $ | 4,287 | ||||||
Less: Unrealized derivative loss (gains) | (837 | ) | (2,278 | ) | (161 | ) | (2,324 | ) | |||||||
Adjusted net income | $ | (759 | ) | $ | 1,521 | $ | (883 | ) | $ | 1,963 | |||||
Adjusted net income fully diluted earnings per share | $ | (0.02 | ) | $ | 0.04 | $ | (0.02 | ) | $ | 0.05 | |||||
The following tables present summary information for the three and six months ended June 30, 2013, and are followed by the Company’s financial statements.
Three Months Ended June 30, | |||||||||||||||
2013 | 2012 | Change | % Change | ||||||||||||
Net production: | |||||||||||||||
Crude oil (MBbls) | 198 | 223 | (25 | ) | (11 | )% | |||||||||
Natural gas (MMcf) | 787 | 902 | (115 | ) | (13 | )% | |||||||||
Total production (MBoe) | 329 | 374 | (45 | ) | (12 | )% | |||||||||
Average daily production (MBoe) | 3.6 | 4.1 | (0.5 | ) | (12 | )% | |||||||||
Average realized sales price (a): | |||||||||||||||
Crude oil (Bbl) | $ | 96.27 | $ | 98.78 | $ | (2.51 | ) | (3 | )% | ||||||
Natural gas (Mcf) | $ | 4.70 | $ | 3.65 | $ | 1.05 | 29 | % | |||||||
Average realized sales price on an equivalent basis (Boe) | $ | 69.18 | $ | 67.85 | $ | 1.33 | 2 | % | |||||||
Crude oil and natural gas revenues (in thousands): | |||||||||||||||
Crude oil revenue | $ | 19,061 | $ | 22,073 | $ | (3,012 | ) | (14 | )% | ||||||
Natural gas revenue | 3,699 | 3,287 | 411 | 13 | % | ||||||||||
Total | $ | 22,760 | $ | 25,360 | $ | (2,600 | ) | (10 | )% | ||||||
Additional per Boe data: | |||||||||||||||
Average realized sales price | $ | 69.18 | $ | 67.85 | $ | 1.33 | 2 | % | |||||||
Lease operating expense | 16.36 | 14.03 | 2.33 | 17 | % | ||||||||||
Production taxes | 2.09 | 1.54 | 0.55 | 36 | % | ||||||||||
Operating margin | $ | 50.73 | $ | 52.28 | $ | (1.55 | ) | (3 | )% | ||||||
Other expenses per Boe: | |||||||||||||||
Depletion, depreciation and amortization | $ | 32.38 | $ | 31.69 | $ | 0.69 | 2 | % | |||||||
General and administrative | 13.81 | 11.70 | 2.11 | 18 | % | ||||||||||
(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 | $ | 94.22 | $ | 93.49 | $ | 0.73 | 1 | % | |||||||
Basis differential and quality adjustments | 2.52 | 3.68 | (1.16 | ) | (32 | )% | |||||||||
Transportation | (0.47 | ) | (0.68 | ) | 0.21 | (31 | )% | ||||||||
Hedging | — | 2.29 | (2.29 | ) | (100 | )% | |||||||||
Average realized price per Bbl of crude oil | $ | 96.27 | $ | 98.78 | $ | (2.51 | ) | (3 | )% | ||||||
Average NYMEX price per million British thermal units (“MMBtu”) | $ | 4.01 | $ | 2.35 | $ | 1.66 | 71 | % | |||||||
Basis differential, quality and Btu adjustments | 0.69 | 1.30 | (0.61 | ) | (47 | )% | |||||||||
Average realized price per Mcf of natural gas | $ | 4.70 | $ | 3.65 | $ | 1.05 | 29 | % | |||||||
Six Months Ended June 30, | |||||||||||||||
2013 | 2012 | Change | % Change | ||||||||||||
Net production: | |||||||||||||||
Crude oil (MBbls) | 404 | 465 | (61 | ) | (13 | )% | |||||||||
Natural gas (MMcf) | 1,525 | 1,806 | (281 | ) | (16 | )% | |||||||||
Total production (MBoe) | 658 | 766 | (108 | ) | (14 | )% | |||||||||
Average daily production (MBoe) | 3.6 | 4.2 | (0.6 | ) | (14 | )% | |||||||||
Average realized sales price (a): | |||||||||||||||
Crude oil (Bbl) | $ | 95.55 | $ | 102.86 | $ | (7.31 | ) | (7 | )% | ||||||
Natural gas (Mcf) | $ | 4.39 | $ | 3.78 | $ | 0.61 | 16 | % | |||||||
Average realized sales price on an equivalent basis (Boe) | $ | 68.85 | $ | 71.36 | $ | (2.51 | ) | (4 | )% | ||||||
Crude oil and natural gas revenues (in thousands): | |||||||||||||||
Crude oil revenue | $ | 38,601 | $ | 47,822 | $ | (9,221 | ) | (19 | )% | ||||||
Natural gas revenue | 6,700 | 6,833 | (133 | ) | (2 | )% | |||||||||
Total | $ | 45,301 | $ | 54,655 | $ | (9,354 | ) | (17 | )% | ||||||
Additional per Boe data: | |||||||||||||||
Average realized sales price | $ | 68.85 | $ | 71.36 | $ | (2.51 | ) | (4 | )% | ||||||
Lease operating expense | 16.93 | 19.07 | (2.14 | ) | (11 | )% | |||||||||
Production taxes | 1.86 | 1.46 | 0.40 | 27 | % | ||||||||||
Operating margin | $ | 50.06 | $ | 50.83 | $ | (0.77 | ) | (2 | )% | ||||||
Other expenses per Boe: | |||||||||||||||
Depletion, depreciation and amortization | $ | 32.97 | $ | 31.38 | $ | 1.59 | 5 | % | |||||||
General and administrative | 12.59 | 12.28 | 0.31 | 3 | % | ||||||||||
(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 | $ | 94.30 | $ | 98.21 | $ | (3.91 | ) | (4 | )% | ||||||
Basis differential and quality adjustments | 1.81 | 4.33 | (2.52 | ) | (58 | )% | |||||||||
Transportation | (0.56 | ) | (0.78 | ) | 0.22 | (28 | )% | ||||||||
Hedging | — | 1.10 | (1.10 | ) | (100 | )% | |||||||||
Average realized price per Bbl of crude oil | $ | 95.55 | $ | 102.86 | (7.31 | ) | (7 | )% | |||||||
Average NYMEX price per million British thermal units (“MMBtu”) | $ | 3.75 | $ | 2.43 | $ | 1.32 | 54 | % | |||||||
Basis differential, quality and Btu adjustments | 0.64 | 1.35 | (0.71 | ) | (53 | )% | |||||||||
Average realized price per Mcf of natural gas | $ | 4.39 | $ | 3.78 | $ | 0.61 | 16 | % | |||||||
CALLON PETROLEUM COMPANY CONSOLIDATED BALANCE SHEETS (In thousands, except per share data) | |||||||
June 30, 2013 | December 31, 2012 | ||||||
ASSETS | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 13,406 | $ | 1,139 | |||
Accounts receivable | 15,828 | 15,608 | |||||
Fair market value of derivatives | 1,647 | 1,674 | |||||
Other current assets | 904 | 1,502 | |||||
Total current assets | 31,785 | 19,923 | |||||
Oil and natural gas properties, full-cost accounting method: | |||||||
Evaluated properties | 1,583,159 | 1,497,010 | |||||
Less accumulated depreciation, depletion and amortization | (1,317,961 | ) | (1,296,265 | ) | |||
Net oil and natural gas properties | 265,198 | 200,745 | |||||
Unevaluated properties excluded from amortization | 55,182 | 68,776 | |||||
Total oil and natural gas properties | 320,380 | 269,521 | |||||
Other property and equipment, net | 9,926 | 10,058 | |||||
Restricted investments | 3,800 | 3,798 | |||||
Investment in Medusa Spar LLC | 7,946 | 8,568 | |||||
Deferred tax asset | 63,892 | 64,383 | |||||
Other assets, net | 3,474 | 1,922 | |||||
Total assets | $ | 441,203 | $ | 378,173 | |||
LIABILITIES AND STOCKHOLDERS' EQUITY | |||||||
Current liabilities: | |||||||
Accounts payable and accrued liabilities | $ | 40,637 | $ | 36,016 | |||
Asset retirement obligations | 6,223 | 2,336 | |||||
Fair market value of derivatives | 106 | 125 | |||||
Total current liabilities | 46,966 | 38,477 | |||||
13% Senior Notes: | |||||||
Principal outstanding | 96,961 | 96,961 | |||||
Deferred credit, net of accumulated amortization of $19,415 and $17,800, respectively | 12,092 | 13,707 | |||||
Total 13% Senior Notes | 109,053 | 110,668 | |||||
Senior secured revolving credit facility | — | 10,000 | |||||
Asset retirement obligations | 7,175 | 10,965 | |||||
Other long-term liabilities | 1,474 | 2,092 | |||||
Total liabilities | 164,668 | 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; 40,277 and 39,801 shares outstanding, respectively | 404 | 398 | |||||
Capital in excess of par value | 399,380 | 328,116 | |||||
Retained deficit | (123,265 | ) | (122,543 | ) | |||
Total stockholders' equity | 276,535 | 205,971 | |||||
Total liabilities and stockholders' equity | $ | 441,203 | $ | 378,173 | |||
CALLON PETROLEUM COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS (In thousands, except per share data) | ||||||||||||||||
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||||
Operating revenues: | ||||||||||||||||
Crude oil sales | $ | 19,061 | $ | 22,073 | $ | 38,601 | $ | 47,822 | ||||||||
Natural gas sales | 3,699 | 3,287 | 6,700 | 6,833 | ||||||||||||
Total operating revenues | 22,760 | 25,360 | 45,301 | 54,655 | ||||||||||||
Operating expenses: | ||||||||||||||||
Lease operating expenses | 5,384 | 5,246 | 11,142 | 13,484 | ||||||||||||
Production taxes | 687 | 575 | 1,226 | 1,122 | ||||||||||||
Depreciation, depletion and amortization | 10,654 | 11,844 | 21,696 | 24,033 | ||||||||||||
General and administrative | 4,545 | 4,374 | 8,284 | 9,405 | ||||||||||||
Accretion expense | 533 | 562 | 1,098 | 1,135 | ||||||||||||
Total operating expenses | 21,803 | 22,601 | 43,446 | 49,179 | ||||||||||||
Income from operations | 957 | 2,759 | 1,855 | 5,476 | ||||||||||||
Other (income) expenses: | ||||||||||||||||
Interest expense | 1,537 | 2,384 | 3,052 | 4,961 | ||||||||||||
Gain on early extinguishment of debt | — | (1,366 | ) | — | (1,366 | ) | ||||||||||
Gain on derivative contracts | (1,981 | ) | (3,505 | ) | (1,563 | ) | (3,575 | ) | ||||||||
Other income, net | (44 | ) | (157 | ) | (89 | ) | (461 | ) | ||||||||
Total other (income) expenses, net | (488 | ) | (2,644 | ) | 1,400 | (441 | ) | |||||||||
Income before income taxes | 1,445 | 5,403 | 455 | 5,917 | ||||||||||||
Income tax expense | 663 | 1,610 | 494 | 1,754 | ||||||||||||
Income (loss) before equity in earnings of Medusa Spar LLC | 782 | 3,793 | (39 | ) | 4,163 | |||||||||||
Equity in (loss) earnings of Medusa Spar LLC | (24 | ) | 6 | (3 | ) | 124 | ||||||||||
Net income (loss) | 758 | 3,799 | (42 | ) | 4,287 | |||||||||||
Preferred stock dividends | (680 | ) | — | (680 | ) | — | ||||||||||
Net income (loss) available to common shareholders | $ | 78 | $ | 3,799 | $ | (722 | ) | $ | 4,287 | |||||||
Net income (loss) per common share: | ||||||||||||||||
Basic | $ | 0.00 | $ | 0.10 | $ | (0.02 | ) | $ | 0.11 | |||||||
Diluted | $ | 0.00 | $ | 0.09 | $ | (0.02 | ) | $ | 0.11 | |||||||
Shares used in computing net income (loss) per common share: | ||||||||||||||||
Basic | 40,089 | 39,399 | 39,941 | 39,375 | ||||||||||||
Diluted | 40,323 | 40,155 | 39,941 | 40,204 | ||||||||||||
CALLON PETROLEUM COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands) | ||||||||
Six Months Ended June 30, | ||||||||
2013 | 2012 | |||||||
Cash flows from operating activities: | ||||||||
Net income (loss) | $ | (42 | ) | $ | 4,287 | |||
Adjustments to reconcile net income to cash provided by operating activities: | ||||||||
Depreciation, depletion and amortization | 22,405 | 24,676 | ||||||
Accretion expense | 1,098 | 1,135 | ||||||
Amortization of non-cash debt related items | 228 | 225 | ||||||
Amortization of deferred credit | (1,615 | ) | (1,538 | ) | ||||
Non-cash gain on early extinguishment of debt | — | (1,366 | ) | |||||
Equity in loss (earnings) of Medusa Spar LLC | 3 | (124 | ) | |||||
Deferred income tax expense | 494 | 1,754 | ||||||
Unrealized loss (gain) on derivative contracts | (249 | ) | (3,897 | ) | ||||
Non-cash expense related to equity share-based awards | 734 | 722 | ||||||
Change in the fair value of liability share-based awards | (852 | ) | 989 | |||||
Payments to settle asset retirement obligations | (615 | ) | (1,029 | ) | ||||
Changes in current assets and liabilities: | ||||||||
Accounts receivable | 789 | (2,036 | ) | |||||
Other current assets | 598 | 63 | ||||||
Current liabilities | (324 | ) | 4,756 | |||||
Payments to settle vested liability share-based awards | (239 | ) | (199 | ) | ||||
Change in natural gas balancing receivable | (118 | ) | (95 | ) | ||||
Change in natural gas balancing payable | (62 | ) | (17 | ) | ||||
Change in other long-term liabilities | (206 | ) | — | |||||
Change in other assets, net | (1,790 | ) | (865 | ) | ||||
Cash provided by operating activities | $ | 20,237 | $ | 27,441 | ||||
Cash flows from investing activities: | ||||||||
Capital expenditures | (58,385 | ) | (72,538 | ) | ||||
Acquisition | (11,000 | ) | — | |||||
Proceeds from sale of mineral interest and equipment | 1,389 | 522 | ||||||
Distribution from Medusa Spar LLC | 616 | 1,120 | ||||||
Cash used in investing activities | $ | (67,380 | ) | $ | (70,896 | ) | ||
Cash flows from financing activities: | ||||||||
Borrowings on senior secured revolving credit facility | 31,000 | 10,000 | ||||||
Payments on senior secured revolving credit facility | (41,000 | ) | — | |||||
Redemption of 13% senior notes | — | (10,225 | ) | |||||
Issuance of preferred stock | 70,090 | — | ||||||
Payment of preferred stock dividends | (680 | ) | — | |||||
Taxes paid related to exercise of employee stock options | — | (2 | ) | |||||
Cash provided by (used in) financing activities | $ | 59,410 | $ | (227 | ) | |||
Net change in cash and cash equivalents | 12,267 | (43,682 | ) | |||||
Beginning of period cash and cash equivalents | 1,139 | 43,795 | ||||||
End of period cash and cash equivalents | $ | 13,406 | $ | 113 | ||||
Callon Petroleum Company is engaged in the acquisition, development, exploration and operation of oil and gas properties in Texas, Louisiana and the offshore waters of the Gulf of Mexico.
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.
For further information contact
Rodger W. Smith, 1-800-451-1294