Attached files
| file | filename |
|---|---|
| 8-K - CALLON PETROLEUM COMPANY FORM 8-K - Callon Petroleum Co | a2012-q3form8xkearningsgui.htm |
| EX-99.2 - EXHIBIT 99.2: GUIDANCE FOR THE FULL-YEAR 2012 - Callon Petroleum Co | a2012-q3guidancerelease.htm |
| EX-99.3 - EXHIBIT 99.3: ANNOUNCING CONFERENCE CALL REPORTING THIRD QUARTER 2012 RESULTS - Callon Petroleum Co | a2012-q3announcingconferen.htm |
EXHIBIT 99.1
Callon Petroleum Company Reports Results For The Third Quarter of 2012
Natchez, MS (November 7, 2012) - Callon Petroleum Company (NYSE: CPE) (“Callon” or the “Company”) today reported results of operations for the three-month period ended September 30, 2012.
The Company highlighted the recent operational activity and third quarter financial results:
• | Continued strong performance from the horizontal Wolfcamp B shale program, with average daily production rates of 576 Boe per well on a 30-day basis. |
• | Initiated completion operations on the Vickie Newton 3801 #1H, a horizontal well targeting the Cline shale and drilling of the Shirly Newton 2301 #1H, a horizontal well targeting the Mississippian lime. |
• | Expanded the Company's Permian acreage position in the Midland Basin to 32,649 total net acres, adding 6,964 net acres in the northern Midland Basin at an average price of $696 per acre since July 1, 2012. |
• | Revenue of $27.4 million from daily production of 4,337 barrels of oil equivalent (“Boe”) of production, or $68.67 per Boe produced. |
• | Net loss of $0.03 per share, which includes a $0.03 charge related to a non-cash, mark-to-market of the Company's derivative positions. |
• | Discretionary cash flow, a non-GAAP financial measure, of $0.33 per diluted share. |
Fred Callon, Chairman and CEO commented, “Our production profile is beginning to reflect the impact of our horizontal drilling program that we began earlier this year. We produced over 2,100 Boe per day from our Permian operations during the month of October, a 60% increase over our 2011 exit rate. In addition to a total inventory of over 70 identified horizontal Wolfcamp shale locations on our southern Midland Basin acreage, we are in the process of evaluating two additional horizontal oil plays targeting the Cline shale and Mississippian lime in the northern portion of the basin. These emerging plays represent a potential catalyst for acceleration of our drilling activity in the Permian beyond our foundation of horizontal Wolfcamp opportunities.”
Drilling Activity Update
Southern Midland. Production from Callon's initial two horizontal wells targeting the Wolfcamp B shale zone at its East Bloxom field in Upton County has averaged 576 Boe per day (gross) over the first 30 days of hydrocarbon production. Callon currently plans to recommence its drilling program in early 2013 at East Bloxom, targeting both the Wolfcamp A and Wolfcamp B shale zones.
The Company's third horizontal Wolfcamp B well, the Pembrook 9121H, is scheduled to begin drilling in late November at the Taylor Draw field in southern Reagan County.
Callon's vertical drilling program is currently focused on its Pecan Acres field in Midland County and CH Ranch field in Glasscock County. Three wells in Section 23 of the Pecan Acres field were completed in the third quarter and are in the process of flowing back, and two additional wells are awaiting completion. The Company will be evaluating the potential of deeper zones within this package of wells, completing two wells below the Strawn interval. At CH Ranch, one well targeting the Fusselman formation is awaiting completion during the fourth quarter of 2012.
Northern Midland. Callon is currently completing the Vickie Newton #3801 which is targeting the Cline shale in a lateral section totaling 6,679 feet. The Company is also in the process of drilling the lateral portion of the Shirly Newton 2301 #1H, a horizontal well targeting the Mississippian lime that is currently expected to be completed in December 2012.
Deepwater Gulf of Mexico. The Habanero #2 sidetrack is scheduled to commence drilling in December. In addition, Callon is continuing discussions with the working interest partner group regarding future development drilling plans at the Medusa field.
In 2013, Callon currently expects the Medusa field to be shut-in for 30 days for modifications to the West Delta 143 pipeline system, and Habanero to be shut-in for 74 days for both scheduled maintenance and the tie-in of the Cardamom project to the Auger tension leg platform facility.
Summary Financial Results
Operating Revenues. Operating revenues for the three months ended September 30, 2012 include oil and natural gas sales of $27.4 million from average production of 4,337 Boe per day. These results compare with oil and natural gas sales of $33.6 million from average production of 5,261 Boe per day during the comparable 2011 period.
Oil revenues decreased 9% to $24.1 million for the three months ended September 30, 2012 compared to revenues of $26.5 million for the same period of 2011. Contributing to the decrease in oil revenue was a 2% decrease in commodity prices compounded by a 7% decrease in production. The average price realized decreased to $95.86 per barrel compared to $98.27 for the same period of 2011. Production decreased to 251 thousand barrels (“MBbls”) during the third quarter of 2012 compared to production of 270 MBbls during the same period in 2011. The decrease in production was primarily attributable to approximately 39 days of downtime at our Habanero field for scheduled maintenance to the Auger Facility, combined with downtime at our Medusa and Habanero fields attributable to Hurricane Isaac. Excluding the effect of this downtime at our deepwater fields, oil production in the third quarter of 2012 compared to the same quarter of 2011 would have been relatively unchanged. Further contributing to the decrease were the normal and expected declines in production from our offshore properties. These production declines were offset by increased production from our Permian operations.
Natural gas revenues of $3.3 million decreased 52% during the three months ended September 30, 2012 as compared to natural gas revenues of $7.0 million for the same period of 2011. Contributing to the decline was a 31% decrease in the average price realized, which fell to $3.76 per thousand cubic feet of natural gas (“Mcf”) from $5.46 per Mcf, and a 31% decrease in natural gas production, driven primarily by down time at our East Cameron 257 well, which was suspended in the fourth quarter of 2011 due to a natural gas leak in an upstream section of the Stingray Pipeline that transports production volumes from the field. Production from our East Cameron 257 well is expected to resume once the pipeline is brought back online during the first quarter of 2013. Excluding the effect of this downtime at East Cameron 257, natural gas production decreases in the third quarter of 2012 compared to the same quarter of 2011 would have been approximately 20%. Also, the downtime at our Habanero and Medusa fields discussed previously, combined with normal and expected declines in natural gas production from our other wells, contributed to the period-to-period decline.
Our oil price realizations exceeded NYMEX prices by $3.64 per Bbl in the third quarter of 2012 due to hedging impacts and the premium received on our offshore production, partially offset by Permian Basin differentials and transportation costs. Our natural gas price realizations on a million British thermal unit (“MMBtu”) equivalent basis exceeded the related NYMEX prices by $0.86 per Mcf in the third quarter of 2012 primarily due to the value of the natural gas liquids in our Permian Basin and offshore natural gas streams. On a combined hydrocarbon equivalent basis, Callon received $68.67 per barrel of oil equivalent produced for the third quarter of 2012.
Lease Operating Expenses. Lease operating expenses for the three months ended September 30, 2012 were relatively unchanged at $5.9 million compared to $6.0 million for the same period in 2011. The decrease was primarily due to lower deepwater property throughput charges related to reduced production volumes from scheduled downtime and hurricane impacts, partially offset by cost increases related to the significant growth in the number of wells now producing on our Permian Basin properties.
General and Administrative Expenses. General and administrative expenses, net of amounts capitalized, increased to $6.4 million for the three months ended September 30, 2012 from $3.5 million for the same period of 2011. In addition to the hiring of additional staff to support our growth initiatives, the variance includes an increase of $2.5 million in the non-cash valuation adjustment required to mark a portion of our share-based awards to fair value and non-recurring additional employee-related costs, including early retirement expense, of $0.5 million.
Interest Expense. Interest expense on our debt obligations decreased 22% to $2.1 million for the three months ended September 30, 2012 compared to $2.7 million for the same period of 2011. The decrease relates to the redemption of $10.0 million principal of Senior Notes during June 2012 in addition to a $0.5 million increase in capitalized interest compared to 2011, partially offset by interest expense related to an increase in bank borrowings.
Net Income. For the three months ended September 30, 2012, the Company reported a net loss of $1.1 million and $0.03 per share, compared to net income and diluted earnings per share of $8.4 million and $0.21, respectively for the same period of 2011. Included in the three months ended September 30, 2012 was an after-tax loss of $1.1 million and $0.03 per share related to a mark-to-market of the Company's derivative positions.
Discretionary Cash Flow. Discretionary cash flow for the three months ended September 30, 2012 totaled $13.0 million compared to $20.0 million during the comparable prior year period. Net cash flow provided by operating activities, as defined by U.S. GAAP, was $13.9 million for the three months ended September 30, 2012, and $27.0 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 total capital expenditures for the nine months ended September 30, 2012 were $115.4 million and included the following amounts (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 drilled and completed wells through September 30, 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 | ||||||||
Northern Midland Basin vertical wells | 1 | 0.8 | — | — | ||||||||
Northern Midland Basin horizontal wells | 1 | 1.0 | — | — | ||||||||
Total | 19 | 14.5 | 21 | 16.8 | ||||||||
Liquidity. At November 1, 2012, the Company's total liquidity position was $37.5 million comprised of a cash balance of $1.5 million and borrowing availability of $36.0 million under its revolving credit facility with a current borrowing base of $80.0 million that was established in October 2012.
Third Quarter 2012 Conference Call
A conference call to discuss this release has been scheduled for Thursday, November 8, 2012 at 1:00 pm CDT. The telephone number to access the conference call is 1-877-317-6789 (toll-free). The conference call will also be webcast live on the Internet, and can be accessed by accessing Callon's website at www.callon.com in the "Investors" section of the website. A Q&A period will follow. An archive of the conference call webcast will also be available at www.callon.com in the "Investors” section of the website.
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 discretionary cash flow to net cash flow provided by operating activities (in thousands):
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
2,012 | 2,011 | Change | 2,012 | 2,011 | Change | ||||||||||||||||||
Discretionary cash flow | $ | 12,960 | $ | 19,989 | $ | (7,029 | ) | $ | 38,595 | $ | 56,996 | $ | (18,401 | ) | |||||||||
Net working capital changes and other changes | 984 | 6,982 | (5,998 | ) | 2,790 | 933 | 1,857 | ||||||||||||||||
Net cash flow provided by (used in) operating activities | $ | 13,944 | $ | 26,971 | $ | (13,027 | ) | $ | 41,385 | $ | 57,929 | $ | (16,544 | ) | |||||||||
Discretionary cash flow | $ | 12,960 | |||||||||||||||||||||
Weighted average shares outstanding for diluted net income (loss) per share | 39,575 | ||||||||||||||||||||||
Discretionary cash flow per diluted share | $ | 0.33 | |||||||||||||||||||||
Other Financial and Operational Tables:
Three Months Ended September 30, | ||||||||||||||||||||
2,012 | 2,011 | 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 | (0.9 | ) | (17 | ) | % | |||||||||||||
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 | ) | % | ||||||||||
Nine Months Ended September 30, | ||||||||||||||||||||
2,012 | 2,011 | Change | % Change | |||||||||||||||||
Net production: | ||||||||||||||||||||
Crude oil (MBbls) | 716 | 746 | (30 | ) | (4 | ) | % | |||||||||||||
Natural gas (MMcf) | 2,695 | 4,014 | (1,318 | ) | (33 | ) | % | |||||||||||||
Total production (Mboe) | 1,165 | 1,415 | (250 | ) | (18 | ) | % | |||||||||||||
Average daily production (MBoe) | 4.3 | 5.2 | (0.9 | ) | (17 | ) | % | |||||||||||||
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 | ) | % | ||||||||||
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 | 65,744 | |||||||
Other assets, net | 2,004 | 717 | |||||||
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 | 3,164 | |||||||
Total liabilities | 200,137 | 168,504 | |||||||
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 | ) | (125,289 | ) | |||||
Total stockholders' equity | 205,462 | 201,203 | |||||||
Total liabilities and stockholders' equity | $ | 405,599 | $ | 369,707 | |||||
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||
2,012 | 2,011 | 2,012 | 2,011 | |||||||||||||||||
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 | ||||||||||||||||
Nine Months Ended September 30, | ||||||||||
2,012 | 2,011 | |||||||||
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 | ||||||
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, the timing of drilling and completion activities, and estimates of the duration of scheduled downtime of offshore production, 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 are 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