Attached files
| file | filename |
|---|---|
| 8-K - CALLON PETROLEUM COMPANY FORM 8-K - Callon Petroleum Co | form8-kx2012yeearningsguid.htm |
| EX-99.2 - GUIDANCE RELEASE - Callon Petroleum Co | exh992-form8xk2013q1andful.htm |
| EX-99.3 - EARNINGS CALL ANNOUNCEMENT - Callon Petroleum Co | exh993-2012xq4andfullyearc.htm |
Exhibit 99.1
Callon Petroleum Company Reports Full Year And Fourth Quarter 2012 Results, Announces 2013 Capital Budget And Provides Operational Update
Natchez, MS (March 14, 2013) - Callon Petroleum Company (NYSE: CPE) (“Callon” or the “Company”) today reported results of operations for the three-month and 12-month periods ended December 31, 2012.
The Company highlighted full-year 2012 and recent operational activity:
• | Increased Permian production by 67% and Permian proved reserves by 24% over 2011. |
• | Replaced 222% of its total 2012 production from additions of Permian reserves. |
• | Continued strong performance from its horizontal Wolfcamp B wells in Upton county, with average production of 390 Boe per day per well over the first five months of production, excluding downtime. |
• | Significant improvement in drilling efficiency for long-lateral horizontal wells, completing the drilling of its last three horizontal Wolfcamp wells in an average 21 days. |
Callon also highlighted financial results for the fourth quarter of 2012:
• | Revenue of $28.7 million from daily production of 4,457 barrels of oil equivalent (“Boe”) of production, or $69.94 per Boe produced. |
• | Fully diluted net loss of $(0.01) per share, which includes a $0.3 million charge related to a non-cash, mark-to-market of the Company’s derivative positions and a $1.2 million impairment related to acquired assets. |
• | Discretionary cash flow, a non-GAAP financial measure, of $0.42 per diluted share. See “Non-GAAP Financial Measures” discussed and reconciled below. |
Fred Callon, Chairman and CEO commented, “Our Permian operations continue to deliver growth in both reserves and production, and are positioned to drive growth in total Company metrics. We will be focusing on program development of our de-risked, horizontal locations in the southern Midland basin in 2013 to deliver repeatable growth following a year of resource capture and evaluation in 2012. In addition, we will be optimizing our vertical drilling program through the targeting of additional deeper zones that have demonstrated encouraging production results. Our continued evaluation of our northern Midland assets will continue in parallel with this base level of activity as we finalize our plans for additional drilling in this area.”
Operational Update
Southern Midland. The Company continues to execute on the horizontal development of its southern Midland basin acreage position following drilling success in 2012. Callon is building upon the strong production results from its first two horizontal, Wolfcamp B shale wells at its East Bloxom field and has commenced program development of the area utilizing pad drilling with planned batch completions also starting in 2013. The Company drilled three horizontal Wolfcamp shale wells from a single pad in the first quarter of 2013, with two targeting the Wolfcamp B and one targeting the Wolfcamp A. These wells were drilled in an average of 21 days and are expected to carry a total cost of $6.5 million per well once they are completed.
Callon is extending its horizontal Wolfcamp development program to the Taylor Draw field in southern Reagan county where it is in the process of flowing back the Pembrook 9121 #1H. In addition, the Company's horizontal rig is currently drilling a four-well package from a single pad at this field. All five of these wells are targeting the Wolfcamp B shale.
The Company’s 2013 vertical drilling program is set to resume at the Pecan Acres field where its three recent wells have produced at an average initial rate of 224 Boe per day and an average 30-day rate of 166 Boe per day. Separately, Callon’s tests of deep zones, below the Atoka to the Woodford, have demonstrated encouraging results, with incremental initial production rates of approximately 100 Boe per day from these isolated zones. These deeper targets will be included in Callon’s ongoing vertical development efforts in the Pecan Acres and Carpe Diem fields in Midland county. Given recent reported results from offsetting horizontal Wolfcamp wells, which confirmed Callon's technical interpretation of this area, the Company is advancing plans for horizontal development of these two fields.
Northern Midland. Callon has drilled two horizontal wells and one vertical well to date in Borden county as part of its initial evaluation of this contiguous leasehold position of over 14,650 net acres.
The first exploration well targeting the Cline shale, the Vickie Newton 3801 #1H, produced a cumulative 1,232 barrels of oil, with a peak rate of 97 barrels of oil per day, and has been temporarily abandoned. The Company will continue to monitor industry activity for new technical data that may benefit future evaluation efforts before additional exploration drilling of the Cline shale
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is pursued. This activity includes two horizontal Cline shale wells in the process of drilling approximately 10 miles south of the Company's acreage position.
Callon’s second horizontal exploration well in Borden county targeting the Mississippian lime, the Shirly Newton 2301 #1H, is currently flowing back after a delay in the completion process caused by stuck coiled tubing during the drill-out of plugs after stimulation. The well is producing hydrocarbons and continues to clean-up during the early stages of flow-back operations. Callon will continue to evaluate the results of this well and ongoing industry activity on offsetting acreage as it develops its drilling plans for the Mississippian lime in the second half of 2013.
The Company is finalizing the completion design for a multi-stage fracture stimulation of the vertical well that was drilled in late 2012 in Borden County to test several prospective zones and to provide core data for the area. Based on the production results from this well, the Shirly Newton 4801, Callon should be positioned to assess the potential for expanded vertical development of its Borden county acreage. In addition, the Company has begun the assessment of its acreage in Lynn County as part of its ongoing drilling and evaluation program in the northern Midland basin.
Deepwater Gulf of Mexico. Following the closing of the sale of its 11.25% working interest in the Habanero field, the Company’s remaining position in the deepwater Gulf of Mexico is a 15% working interest in the Medusa field. Following several months of partner discussions and technical evaluation, the operator has sanctioned a subsea development program that is targeted to begin by early 2014. Callon has begun to fund long-lead time items related to the development and will have the option to participate in all or part of the program once the drilling schedule is confirmed and total program costs are finalized.
2012 Estimated Proved Reserves. The Company ended 2012 with estimated net proved reserves of 14,072 MBoe, representing a 12% decrease over 2011 year-end estimated net proved reserves of 15,928 MBoe. The decrease is primarily due to the sale of the Company’s interest in the Habanero field (1,372 Mboe) and the downward revision of Haynesville shale undeveloped reserves at year-end 2012 (1,813 Mboe), which were reduced due to low natural gas prices. These decreases were partially offset by the Company’s development of a portion of its Permian basin, on which it proved up a total of 26 oil wells during 2012 and added 3,194 MBoe of proved reserves.
MBoe | |||
Total proved reserves at December 31, 2011 | 15,928 | ||
Less Habanero reserves | (1,372 | ) | |
Adjusted proved reserves at December 31, 2011 | 14,556 | ||
Purchase of reserves in place | 57 | ||
Extensions and discoveries | 3,194 | ||
Revisions of Haynesville natural gas reserves | (1,813 | ) | |
Revisions, other | (481 | ) | |
Production (excluding Habanero production) | (1,441 | ) | |
Total proved reserves at December 31, 2012 | 14,072 | ||
The benchmark prices for 2012, using SEC guidelines, were $94.74 per barrel of oil and $2.76 per MMBtu of natural gas. After adjusting for basis differentials and natural gas Btu content, the Company’s average realized prices over the remaining life of the proved reserves were $94.68 per barrel of oil and $4.81 per Mcf of natural gas for year-end 2012, as compared to $98.98 per barrel of oil and $5.60 per Mcf of natural gas for year-end 2011. The commodity prices reflected above for 2012 resulted in a present value of pre-tax future net cash flows discounted at 10% (PV-10) of $250 million for the Company's proved reserves, compared to $310 million at year-end 2011. PV-10 is a non-GAAP measure. See “Non-GAAP Financial Measures” below for the Company’s definition and reconciliation of PV-10 to the Standardized Measure (GAAP).
Financial Update
Total revenue for the fourth quarter of 2012 was $28.7 million compared to $31.8 million for the fourth quarter of 2011, a decrease of 10%. Total revenue for the full year 2012 was $110.7 million compared to $127.6 million in 2011. This year-over-year decrease was due to a decrease in commodity prices and production downtime primarily at our two deepwater fields, Habanero and Medusa, as well as our Haynesville well. Production declines were offset by production from our new Permian wells, 22 vertical and two horizontal, brought onto production during 2012.
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Lease operating expenses, including production taxes, gathering and ad valorem taxes, for the fourth quarter of 2012 totaled $6.1 million, or $14.85 per Boe, a 58% increase per Boe over the fourth quarter of 2011 of $9.40 per Boe. Lease operating expenses for the full year 2012 totaled $26.6 million, or $16.86 per Boe, a 53% increase per Boe over the full year 2011 of $11.04 per Boe. This year-over-year increase was primarily due to significant growth in the number of wells now producing in our Permian basin properties as well as remediation work performed during 2012 on our Haynesville well as a result of interference from the fracture stimulation of an offset well.
Depreciation, depletion and amortization for the fourth quarter of 2012 totaled $13.7 million, or $33.42 per Boe, compared to $13.0 million, or $30.28 per Boe, in the fourth quarter of 2011. Depreciation, depletion and amortization for the full year 2012 totaled $49.7 million, or $31.56 per Boe, compared to $48.7 million, or $26.42 per Boe, for the full year 2011. The $1.0 million increase in DD&A expense for the year ended December 31, 2012 was primarily a result of planned exploration and development expenditures related to our onshore reserve development in the Permian basin area.
General and administrative expenses for the fourth quarter of 2012 totaled $4.5 million, or $11.00 per Boe, compared to $5.1 million, or $12.03 per Boe, in the fourth quarter of 2011. General and administrative expenses for the full year 2012 totaled to $20.4 million, or $12.93 per Boe, as compared to $16.6 million, or $9.03 per Boe, for the full year 2011. Of this $3.7 million year-over-year increase, $1.6 million was due to non-recurring employee expenses including early retirement and severance expense for which we had no expense during 2011. Additionally, we incurred an increase in non-cash charges of $1.2 million related to incentive compensation share-based instruments awarded during 2012. The remaining increase relates primarily to higher compensation-related expenses including the costs associated with hiring staff to support our onshore growth and 100%-operated Permian position, as well as relocation and related costs.
As a result of its derivative activities, the Company incurred a net cash settlement gain of $0.7 million in the fourth quarter of 2012. As a result of forward oil and natural gas price changes, the Company recognized non-cash unrealized mark-to-market derivative losses of $0.3 million for the fourth quarter of 2012. The Company realized a net cash settlement gain of $1.5 million for the year ended December 31, 2012. In addition, as a result of forward oil and natural gas price changes, the Company recognized non-cash unrealized mark-to-market derivative gains of $1.7 million during the year ended December 31, 2012. As previously announced, the Company elected to discontinue hedge accounting for its derivative contracts beginning with all agreements executed subsequent to December 31, 2011, resulting in both the realized and unrealized components of its derivative activity being recognized in current earnings. Prior to 2012, the Company’s unrealized gains and losses associated with its derivative contracts, which were designated as cash flow hedges, were recorded as a component of comprehensive income.
Discretionary cash flow (non-GAAP) for the fourth quarter of 2012 was $16.9 million, a decrease of $4.4 million, or 21%, over the fourth quarter of 2011 of $21.3 million. Discretionary cash flow (non-GAAP) for the full year 2012 was $55.5 million, a decrease of $22.8 million, or 29%, over the full year 2011 of $78.3 million. For a definition of discretionary cash flow and reconciliation to net cash flow provided from operating activities, see “Non-GAAP Financial Measures” below.
The Company reported a net loss of $0.4 million in the fourth quarter of 2012 compared to net income of $74.0 million in the fourth quarter of 2011. For the full year 2012, the Company reported net income of $2.7 million compared to net income of $106.4 million for the full year 2011. The 2011 results benefited from the full reversal of a $69.3 million deferred tax valuation allowance. Excluding certain non-cash items and their tax effect in the fourth quarters of 2012 and 2011, adjusted net income (non-GAAP) was $0.5 million, or $0.01 per diluted share, and $73.9 million, or $1.85 per diluted share, respectively. Excluding certain non-cash items and their tax effect for the years ending December 31, 2012 and 2011, adjusted net income (non-GAAP) was $1.5 million, or $0.04 per diluted share, and $101.9 million, or $2.64 per diluted share, respectively. For a definition of adjusted net income and a reconciliation of net income to adjusted net income, see “Non-GAAP Financial Measures” below.
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2012 Capital Expenditures and 2013 Capital Budget
Callon’s total capital expenditures for the twelve months ended December 31, 2012 were $146.5 million and included the following amounts (in millions):
Southern Midland basin | $ | 70.3 | ||
Northern Midland basin | 21.4 | |||
Leasehold acquisitions and seismic | 37.2 | |||
Plugging and abandonment costs in the Gulf of Mexico | 2.3 | |||
Capitalized interest | 2.0 | |||
Capitalized general and administrative costs allocated directly to exploration and development projects | 13.3 | |||
Total capital expenditures | $ | 146.5 | ||
The following table summarizes drilled and completed wells through December 31, 2012:
Property | Drilling | Completion | ||||||||||
Gross | Net | Gross | Net | |||||||||
Southern Midland basin vertical wells | 15 | 10.7 | 22 | 16.0 | ||||||||
Southern Midland basin horizontal wells | 3 | 2.8 | 2 | 2.0 | ||||||||
Total | 18 | 13.5 | 24 | 18.0 | ||||||||
Property | Drilling | Completion | ||||||||||
Gross | Net | Gross | Net | |||||||||
Northern Midland basin vertical wells | 1 | 0.8 | — | — | ||||||||
Northern Midland basin horizontal wells | 2 | 1.8 | 1 | 1.0 | ||||||||
Total | 3 | 2.6 | 1 | 1.0 | ||||||||
Our 2013 capital budget has been established at $125 million with over 90% of our budgeted operating expenditures (including drilling, completion, infrastructure, and plugging and abandonment) allocated to our Midland basin operations. The 15% decrease in total capital from 2011 reflects our primary focus on drilling and completion activities in the Permian basin and reduced emphasis on acreage acquisitions that were budgeted in 2012 to expand the Company’s presence in the basin. Our budget includes further exploration and development of our Permian basin properties with plans to complete approximately 26 gross wells including 14 horizontal wells and 12 vertical wells. Components of the 2013 capital budget include (in millions):
Midland basin | $ | 97 | |
Gulf of Mexico | 10 | ||
Total projected operations budget | 107 | ||
Capitalized general and administrative costs | 14 | ||
Capitalized interest and other | 4 | ||
Total projected capital expenditures budget | $ | 125 | |
Liquidity and Hedging Update
At December 31, 2012 the Company’s liquidity was $56.1 million comprised of a cash balance of $1.1 million and available borrowing base of $55.0 million under its revolving credit facility. On June 20, 2012, the credit facility was increased to $200 million with an associated borrowing base of $60 million and a maturity of July 31, 2014. Subsequently, in October 2012, the credit facility was further amended to increase the borrowing base to $80 million and extend the maturity to March 15, 2016. The lending group was also expanded to five financial institutions at that time. Following the sale of our interest in the deepwater Habanero field, the borrowing base was revised to $65 million as of December 31, 2012. The borrowing base is scheduled to be reviewed and re-determined in April 2013.
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Subsequent to December 31, 2012, the Company restructured its crude oil collars covering 40,000 barrels per month for the year 2013, starting in February 2013. As a result of this transaction, the Company has hedged 40,000 barrels per month for 2013 under a fixed price swap set at $101.30 per barrel (NYMEX). In addition, the Company has hedged 30,000 barrels per month for 2014 under a fixed price swap set at $93.35 per barrel (NYMEX). The Company also sold a crude oil put at $70 per barrel for 30,000 barrels per month for 2014 as part of the oil hedge program restructuring.
Earnings Call Information
The Company will host a conference call on Friday, March 15, 2013 to discuss fourth quarter and full year 2012 financial and operating results. Management will also provide an operational update, and discuss its outlook for 2013 during the call.
Please join Callon Petroleum Company via the Internet for a webcast of the conference call:
Date/Time: Friday, March 15, 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:
Call-in number: 877-317-6789 (Toll-free)
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,” “PV-10 value” and “adjusted net income.”
• | 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. |
• | Adjusted net income and adjusted net income per diluted share, which excludes (1) impairments, (2) unrealized (gain) loss on commodity derivatives, (3) loss (gain) on retirement of debt and (4) related income tax effect. The amounts included in the calculation of adjusted net income and adjusted net income per diluted share below were computed in accordance with GAAP. We believe adjusted net income and adjusted net income per diluted share are useful to investors because they provide readers with a more meaningful measure of our profitability before recording certain items whose timing or amount cannot be reasonably determined. |
• | PV-10 value is the present value of future net pre-tax cash flows attributable to estimated net proved reserves, discounted at 10% per annum. PV-10 value is computed on the same basis as standardized measure, a GAAP financial measure, but does not include a provision for future income taxes. We believe PV-10 value to be an important measure for evaluating the relative significance of our oil and gas properties, because it excludes income taxes which may vary materially among companies. PV-10 is not, however, a substitute for standardized measure. |
These measures are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website.
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Reconciliation of Non-GAAP Financial Measures:
The following table reconciles the PV-10 value to the standardized measure (in thousands):
2012 | 2011 | $ Change | % Change | ||||||||||||
PV-10 Value | $ | 250,097 | $ | 309,890 | $ | (59,793 | ) | (19 | )% | ||||||
Future income taxes | (18,949 | ) | (39,533 | ) | 20,584 | 52 | % | ||||||||
Standardized measure | $ | 231,148 | $ | 270,357 | $ | (39,209 | ) | (15 | )% | ||||||
The following table reconciles net cash flow provided by operating activities to discretionary cash flow (in thousands):
Three Months Ended December 31, | Twelve Months Ended December 31, | ||||||||||||||||||||||
2012 | 2011 | Change | 2012 | 2011 | Change | ||||||||||||||||||
Discretionary cash flow | $ | 16,891 | $ | 21,313 | $ | (4,422 | ) | $ | 55,486 | $ | 78,309 | $ | (22,823 | ) | |||||||||
Net working capital changes and other changes | (6,986 | ) | (75 | ) | (6,911 | ) | (4,196 | ) | 858 | (5,054 | ) | ||||||||||||
Net cash flow provided by operating activities | $ | 9,905 | $ | 21,238 | $ | (11,333 | ) | $ | 51,290 | $ | 79,167 | $ | (27,877 | ) | |||||||||
The following table reconciles income available to common shares to adjusted income (in thousands; reconciling items are reflected net of tax):
For the Three Months Ended December 31, | For the Year Ended December 31, | |||||||||||||||
2012 | 2011 | 2012 | 2011 | |||||||||||||
Net (loss) income available to common shares | $ | (435 | ) | $ | 73,951 | $ | 2,747 | $ | 106,396 | |||||||
Less: Unrealized derivative gains | 169 | — | (1,116 | ) | — | |||||||||||
Less: Gain on early redemption of debt | — | — | (888 | ) | (1,262 | ) | ||||||||||
Plus: Impairment (gain) related to acquired assets | 765 | (10 | ) | 765 | (3,277 | ) | ||||||||||
Adjusted net income | $ | 499 | $ | 73,941 | $ | 1,508 | $ | 101,857 | ||||||||
Adjusted net income fully diluted earnings per share | $ | 0.01 | $ | 1.85 | $ | 0.04 | $ | 2.64 | ||||||||
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The following tables present summary information for the three and twelve-month periods ended December 31, 2012, and are followed by the Company’s financial statements.
Three Months Ended December 31, | ||||||||||||||
2012 | 2011 | Change | % Change | |||||||||||
Net production: | ||||||||||||||
Crude oil (MBbls) | 261 | 250 | 11 | 4 | % | |||||||||
Natural gas (MMcf) | 893 | 1,067 | (174 | ) | (16 | )% | ||||||||
Total production (MBoe) | 410 | 428 | (18 | ) | (4 | )% | ||||||||
Average daily production (Boe) | 4,457 | 4,652 | (195 | ) | (4 | )% | ||||||||
Average realized sales price: | ||||||||||||||
Crude oil (Bbl) | $ | 94.63 | $ | 105.96 | $ | (11.33 | ) | (11 | )% | |||||
Natural gas (Mcf) | 4.45 | 4.95 | (0.50 | ) | (10 | )% | ||||||||
Total (Boe) | 69.94 | 74.33 | (4.39 | ) | (6 | )% | ||||||||
Crude oil and natural gas revenues (in thousands): | ||||||||||||||
Crude oil revenue | $ | 24,701 | $ | 26,534 | $ | (1,833 | ) | (7 | )% | |||||
Natural gas revenue | 3,975 | 5,278 | (1,303 | ) | (25 | )% | ||||||||
Total | $ | 28,676 | $ | 31,812 | $ | (3,136 | ) | (10 | )% | |||||
Additional per Boe data: | ||||||||||||||
Sales price | $ | 69.94 | $ | 74.33 | $ | (4.39 | ) | (6 | )% | |||||
Lease operating expense | (14.85 | ) | (9.40 | ) | (5.45 | ) | (58 | )% | ||||||
Operating margin | $ | 55.09 | $ | 64.93 | $ | (9.84 | ) | (15 | )% | |||||
Other expenses per Boe: | ||||||||||||||
Depletion, depreciation and amortization | $ | 33.42 | $ | 30.28 | $ | 3.14 | 10 | % | ||||||
General and administrative (net of management fees) | 11.00 | 12.03 | (1.03 | ) | (9 | )% | ||||||||
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For the Year Ended December 31, | ||||||||||||||
2012 | 2011 | Change | % Change | |||||||||||
Net production: | ||||||||||||||
Crude oil (MBbls) | 977 | 996 | (19 | ) | (2 | )% | ||||||||
Natural gas (MMcf) | 3,588 | 5,081 | (1,493 | ) | (29 | )% | ||||||||
Total production (MBoe) | 1,575 | 1,843 | (268 | ) | (15 | )% | ||||||||
Average daily production (Boe/d) | 4,303 | 5,049 | (746 | ) | (15 | )% | ||||||||
Average realized sales price (a): | ||||||||||||||
Crude oil (Bbl) | $ | 98.86 | $ | 101.34 | $ | (2.48 | ) | (2 | )% | |||||
Natural gas (Mcf) | 3.94 | 5.25 | (1.31 | ) | (25 | )% | ||||||||
Total (Boe) | 70.31 | 69.26 | 1.05 | 2 | % | |||||||||
Crude oil and natural gas revenues (in thousands): | ||||||||||||||
Crude oil revenue | $ | 96,584 | $ | 100,962 | $ | (4,378 | ) | (4 | )% | |||||
Natural gas revenue | 14,149 | 26,682 | (12,533 | ) | (47 | )% | ||||||||
Total | $ | 110,733 | $ | 127,644 | $ | (16,911 | ) | (13 | )% | |||||
Additional per Boe data: | ||||||||||||||
Sales price | $ | 70.31 | $ | 69.26 | $ | 1.05 | 2 | % | ||||||
Lease operating expense | (16.86 | ) | (11.04 | ) | (5.82 | ) | (53 | )% | ||||||
Operating margin | $ | 53.45 | $ | 58.22 | $ | (4.77 | ) | (8 | )% | |||||
Other expenses per Boe: | ||||||||||||||
Depletion, depreciation and amortization | $ | 31.56 | $ | 26.42 | $ | 5.14 | 19 | % | ||||||
General and administrative (net of management fees) | 12.93 | 9.03 | 3.90 | 43 | % | |||||||||
(a) Below is a reconciliation of the average NYMEX price to the average realized sales price per Bbl of oil and price per Mcf of natural gas: | ||||||||||||||
Average NYMEX oil price ($/Bbl) | $ | 94.19 | $ | 95.14 | $ | (0.95 | ) | (1 | )% | |||||
Basis differential and quality adjustments | 3.97 | 7.58 | (3.61 | ) | (48 | )% | ||||||||
Transportation | (0.75 | ) | (1.00 | ) | 0.25 | 25 | % | |||||||
Hedging | 1.45 | (0.38 | ) | 1.83 | 482 | % | ||||||||
Average realized oil price ($/Bbl) | $ | 98.86 | $ | 101.34 | $ | (2.48 | ) | (2 | )% | |||||
Average NYMEX gas price ($/MMBtu) | $ | 2.82 | $ | 4.03 | $ | (1.21 | ) | (30 | )% | |||||
Basis differential and quality adjustments | 1.12 | 1.22 | (0.10 | ) | (8 | )% | ||||||||
Average realized gas price ($/Mcf) | $ | 3.94 | $ | 5.25 | $ | (1.31 | ) | (25 | )% | |||||
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CALLON PETROLEUM COMPANY CONSOLIDATED BALANCE SHEETS (In thousands, except share data) | |||||||
December 31, | |||||||
2012 | 2011 | ||||||
ASSETS | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 1,139 | $ | 43,795 | |||
Accounts receivable | 15,608 | 15,181 | |||||
Fair market value of derivatives | 1,674 | 2,499 | |||||
Other current assets | 1,502 | 1,601 | |||||
Total current assets | 19,923 | 63,076 | |||||
Crude oil and natural gas properties, full-cost accounting method: | |||||||
Evaluated properties | 1,497,010 | 1,421,640 | |||||
Less accumulated depreciation, depletion and amortization | (1,296,265 | ) | (1,208,331 | ) | |||
Net oil and natural gas properties | 200,745 | 213,309 | |||||
Unevaluated properties excluded from amortization | 68,776 | 2,603 | |||||
Total oil and natural gas properties | 269,521 | 215,912 | |||||
Other property and equipment, net | 10,058 | 10,512 | |||||
Restricted investments | 3,798 | 3,790 | |||||
Investment in Medusa Spar LLC | 8,568 | 9,956 | |||||
Deferred tax asset | 64,383 | 65,743 | |||||
Other assets, net | 1,922 | 718 | |||||
Total assets | $ | 378,173 | $ | 369,707 | |||
LIABILITIES AND STOCKHOLDERS' EQUITY | |||||||
Current liabilities: | |||||||
Accounts payable and accrued liabilities | $ | 36,016 | $ | 26,057 | |||
Asset retirement obligations | 2,336 | 1,260 | |||||
Fair market value of derivatives | 125 | — | |||||
Total current liabilities | 38,477 | 27,317 | |||||
13% Senior Notes: | |||||||
Principal outstanding | 96,961 | 106,961 | |||||
Deferred credit, net of accumulated amortization of $17,800 and $13,123, respectively | 13,707 | 18,384 | |||||
Total 13% Senior Notes | 110,668 | 125,345 | |||||
Senior secured revolving credit facility | 10,000 | — | |||||
Asset retirement obligations | 10,965 | 12,678 | |||||
Other long-term liabilities | 2,092 | 3,165 | |||||
Total liabilities | 172,202 | 168,505 | |||||
Stockholders' equity: | |||||||
Preferred Stock, $.01 par value, 2,500,000 shares authorized; | — | — | |||||
Common Stock, $.01 par value, 60,000,000 shares authorized; 39,800,548 and 39,398,416 shares outstanding at December 31, 2012 and 2011, respectively | 398 | 394 | |||||
Capital in excess of par value | 328,116 | 324,474 | |||||
Other comprehensive income | — | 1,624 | |||||
Retained deficit | (122,543 | ) | (125,290 | ) | |||
Total stockholders' equity | 205,971 | 201,202 | |||||
Total liabilities and stockholders' equity | $ | 378,173 | $ | 369,707 | |||
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CALLON PETROLEUM COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS (In thousands, except per share amounts) | |||||||
For the year ended December 31, | |||||||
2012 | 2011 | ||||||
Operating revenues: | |||||||
Crude oil sales | $ | 96,584 | $ | 100,962 | |||
Natural gas sales | 14,149 | 26,682 | |||||
Total operating revenues | 110,733 | 127,644 | |||||
Operating expenses: | |||||||
Lease operating expenses | 26,554 | 20,347 | |||||
Depreciation, depletion and amortization | 49,701 | 48,701 | |||||
General and administrative | 20,358 | 16,636 | |||||
Accretion expense | 2,253 | 2,338 | |||||
Impairment of other property and equipment | 1,177 | — | |||||
Total operating expenses | 100,043 | 88,022 | |||||
Income from operations | 10,690 | 39,622 | |||||
Other (income) expenses: | |||||||
Interest expense | 9,108 | 11,717 | |||||
Gain on early extinguishment of debt | (1,366 | ) | (1,942 | ) | |||
Gain on acquired assets | — | (5,041 | ) | ||||
Gain on derivative contracts | (1,717 | ) | — | ||||
Other income, net | (79 | ) | (1,426 | ) | |||
Total other expenses, net | 5,946 | 3,308 | |||||
Income before income taxes | 4,744 | 36,314 | |||||
Income tax expense (benefit) | 2,223 | (69,283 | ) | ||||
Income before equity in earnings of Medusa Spar LLC | 2,521 | 105,597 | |||||
Equity in earnings of Medusa Spar LLC | 226 | 799 | |||||
Net income available to common shares | $ | 2,747 | $ | 106,396 | |||
Net income per common share: | |||||||
Basic | $ | 0.07 | $ | 2.81 | |||
Diluted | $ | 0.07 | $ | 2.76 | |||
Shares used in computing net income per common share: | |||||||
Basic | 39,522 | 37,908 | |||||
Diluted | 40,337 | 38,582 | |||||
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CALLON PETROLEUM COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands) | |||||||
For the year ended December 31, | |||||||
2012 | 2011 | ||||||
Cash flows from operating activities: | |||||||
Net income | $ | 2,747 | $ | 106,396 | |||
Adjustments to reconcile net income to | |||||||
cash provided by operating activities: | |||||||
Depreciation, depletion and amortization | 51,043 | 49,753 | |||||
Accretion expense | 2,253 | 2,338 | |||||
Amortization of non-cash debt related items | 402 | 461 | |||||
Amortization of deferred credit | (3,086 | ) | (3,155 | ) | |||
Equity in earnings of Medusa Spar LLC | (226 | ) | (799 | ) | |||
Deferred income tax expense | 2,223 | 10,928 | |||||
Valuation allowance | — | (80,211 | ) | ||||
Unrealized gain on derivative contracts | (1,683 | ) | — | ||||
Impairment of other property and equipment | 1,176 | — | |||||
Gain on acquired assets | — | (4,995 | ) | ||||
Non-cash gain for early debt extinguishment | (1,366 | ) | (1,942 | ) | |||
Non-cash expense related to equity share-based awards | 1,697 | 1,337 | |||||
Change in the fair value of liability share-based awards | 1,620 | 761 | |||||
Payments to settle asset retirement obligations | (1,314 | ) | (2,563 | ) | |||
Changes in current assets and liabilities: | |||||||
Accounts receivable | (883 | ) | (3,734 | ) | |||
Other current assets | 100 | 180 | |||||
Current liabilities | 1,753 | 4,695 | |||||
Payments to settle vested liability share-based awards | (3,383 | ) | — | ||||
Change in natural gas balancing receivable | 51 | 252 | |||||
Change in natural gas balancing payable | (102 | ) | (115 | ) | |||
Change in other long-term liabilities | 205 | 100 | |||||
Change in other assets, net | (1,937 | ) | (520 | ) | |||
Cash provided by operating activities | $ | 51,290 | $ | 79,167 | |||
Cash flows from investing activities: | |||||||
Capital expenditures | (133,299 | ) | (100,243 | ) | |||
Acquisitions | (2,075 | ) | — | ||||
Proceeds from sale of mineral interests and equipment | 39,936 | 7,615 | |||||
Investment in restricted assets related to plugging and abandonment | — | (150 | ) | ||||
Distribution from Medusa Spar LLC | 1,735 | 1,267 | |||||
Cash used in investing activities | $ | (93,703 | ) | $ | (91,511 | ) | |
Cash flows from financing activities: | |||||||
Borrowings on senior secured revolving credit facility | 53,000 | — | |||||
Payments on senior secured revolving credit facility | (43,000 | ) | — | ||||
Redemption of 13% senior notes | (10,225 | ) | (35,062 | ) | |||
Issuance of common stock | — | 73,765 | |||||
Taxes paid related to exercise of employee stock options | (18 | ) | — | ||||
Cash (used in) provided by financing activities | $ | (243 | ) | $ | 38,703 | ||
Net change in cash and cash equivalents | (42,656 | ) | 26,359 | ||||
Cash and cash equivalents: | |||||||
Balance, beginning of period | 43,795 | 17,436 | |||||
Balance, end of period | $ | 1,139 | $ | 43,795 | |||
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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
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