Callon Petroleum Company Announces First Quarter 2015 Results and Increases Annual Production Guidance
NATCHEZ, Miss., May 6, 2015 /PRNewswire/ -- Callon Petroleum Company (NYSE: CPE) ("Callon" or the "Company") today reported results of operations for the three month period ended March 31, 2015. Presentation slides accompanying this earnings release are available on the Company's website at www.callon.com located within the Investors (Events and Presentations) section of the site.
The Company highlighted financial and operating results for the first quarter of 2015:
- Net daily production of 8,567 barrels of oil equivalent per day ("BOE/d"), an increase of 18% over the fourth quarter of 2014, comprised of 83% oil volume
- Lease operating costs, including workovers, of $9.03 per barrel of oil equivalent ("BOE"), a decrease of 20% compared to the fourth quarter of 2014
- Adjusted EBITDA, a non-GAAP financial measure(i), of $26.7 million
- Adjusted income available to common shareholders, a non-GAAP financial measure(i), of $0.00 per diluted share based on total average diluted shares outstanding of 57.5 million shares
- Financial flexibility enhanced by the completion of a common equity offering for $65.6 million in net proceeds and reaffirmation of the $250 million borrowing base under its credit facility
"We are pleased to report another quarter of record Permian production at over 8,500 barrels of oil per day, up nearly 20% over last quarter, thanks to a variety of operational successes including placing nine new horizontal wells on production," commented Fred Callon, Chairman and Chief Executive Officer. "We continue to enjoy strong well performance from multiple producing zones, including recent Lower Spraberry wells in Midland County, and Wolfcamp B wells in the Southern Midland Basin at our well-established East Bloxom development and steadily improving Garrison Draw field. In addition, our drilling program continues to benefit from incremental capital cost reductions which put us on a path to realize a 30% decrease in total completed well costs in the second half of 2015 compared to 2014 levels. As we progress into 2015 and beyond, we plan to overlay this competitive cost structure on an operating plan that will include the shifting of capital to the Lower Spraberry zone, enhancing our capital efficiency and production growth potential."
Operating and Financial Results
The following table presents summary information for the periods indicated, and are followed by the Company's financial statements.
Three Months Ended | |||||||||
March 31, 2015 | December 31, 2014 | March 31, 2014 | |||||||
Net production: | |||||||||
Oil (MBbls) | 638 | 529 | 332 | ||||||
Natural gas (MMcf) | 801 | 839 | 363 | ||||||
Total production (MBOE) | 771 | 669 | 392 | ||||||
Average daily production (BOE/d) | 8,567 | 7,270 | 4,355 | ||||||
% oil (BOE basis) | 83% | 79% | 85% | ||||||
Oil and natural gas revenues (in thousands): | |||||||||
Oil revenue | $ | 27,909 | $ | 34,409 | $ | 30,909 | |||
Natural gas revenue | 2,482 | 4,009 | 2,376 | ||||||
Total, excluding impact of cash-settled derivatives | $ | 30,391 | $ | 38,418 | $ | 33,285 | |||
Impact of cash-settled derivatives | 10,343 | 7,068 | (875) | ||||||
Total, including impact of cash-settled derivatives | $ | 40,734 | $ | 45,486 | $ | 32,410 | |||
Three Months Ended | |||||||||
Additional per BOE data: | March 31, 2015 | December 31, 2014 | March 31, 2014 | ||||||
Sales price, excluding impact of cash-settled derivatives | $ | 39.42 | $ | 57.44 | $ | 84.91 | |||
Sales price, including impact of cash-settled derivatives | 52.83 | 68.01 | 82.68 | ||||||
Lease operating expense | $ | 9.03 | $ | 11.23 | $ | 10.79 | |||
Production taxes | 2.94 | 3.80 | 4.89 | ||||||
Depletion, depreciation and amortization | 23.48 | 27.05 | 26.88 | ||||||
Adjusted G&A - total (a) | 6.15 | 5.89 | 11.47 | ||||||
Adjusted G&A - cash component (b) | 5.37 | 4.35 | 9.99 | ||||||
(a) | Excludes certain non-recurring expenses and non-cash valuation adjustments. See the reconciliation provided within this press release for a reconciliation of G&A expense on a GAAP basis to Adjusted G&A expense. |
(b) | Excludes the amortization of equity-settled share-based incentive awards and corporate depreciation and amortization. |
Total Revenue. For the quarter ended March 31, 2015, Callon reported total revenues of $30.4 million, excluding the $10.3 million impact of settled derivative contracts, comprised of oil revenues of $27.9 million and natural gas revenues of $2.5 million. Average daily production for the quarter was 8,567 BOE/d compared to average daily production of 7,270 BOE/d in the fourth quarter of 2014. Average realized prices, including and excluding the effects of hedging, are detailed below.
Hedging impacts. For the quarter ended March 31, 2015, Callon recognized the following hedging-related items:
In Thousands | Per Unit | |||||
Natural gas derivatives | ||||||
Net gain on settlements | $ | 391 | $ | 0.49 | ||
Net loss on fair value adjustments | (125) | |||||
Total gain | $ | 266 | ||||
Oil derivatives | ||||||
Net gain on settlements | $ | 9,952 | $ | 15.60 | ||
Net loss on fair value adjustments | (7,789) | |||||
Total gain | $ | 2,163 | ||||
Total derivatives | ||||||
Net gain on settlements | $ | 10,343 | $ | 13.41 | ||
Net loss on fair value adjustments | (7,914) | |||||
Total gain on derivative contracts | $ | 2,429 | ||||
Average realized prices, including and excluding the impact of cash settled derivatives during the first quarter, were as follows:
Three Months Ended | |||
March 31, 2015 | |||
Average realized sales price: | |||
Oil (per Bbl) (excluding impact of cash-settled derivatives) | $ | 43.74 | |
Impact of cash-settled derivatives | 15.60 | ||
Oil (per Bbl) (including impact of cash-settled derivatives) | $ | 59.34 | |
Natural gas (perMcf) (excluding impact of cash-settled derivatives) | $ | 3.10 | |
Impact of cash-settled derivatives | 0.49 | ||
Natural gas (per Mcf) (including impact of cash-settled derivatives) | $ | 3.59 | |
Total (per BOE) (excluding impact of cash-settled derivatives) | $ | 39.42 | |
Impact of cash-settled derivatives | 13.41 | ||
Total (per BOE) (including impact of cash-settled derivatives) | $ | 52.83 | |
Lease Operating Expenses, including workover expense ("LOE"). LOE for the three months ended March 31, 2015 was $9.03 per BOE, compared to LOE of $11.23 per BOE in the fourth quarter of 2014. Higher production volumes and lower workover expenses contributed to the 20% per BOE decrease in the first quarter.
Production Taxes, including ad valorem taxes. Production taxes were $2.94 per BOE in the first quarter of 2015, representing approximately 7.5% of total revenue before the impact of derivative settlements. While severance taxes correlate directly with commodity prices, ad valorem taxes are linked to underlying assessed property values, which are based on historical prices and which have increased with the additional horizontal wells placed onto production in our Garrison Draw, East Bloxom and Carpe Diem fields. Consequently, adjustments to this tax rate lag changes in commodity prices. As property values are adjusted downward over time in a lower commodity price environment, we expect this component to trend down.
Depreciation, Depletion and Amortization ("DD&A"). DD&A for the three months ended March 31, 2015 was $23.48 per BOE compared to $27.05 per BOE in the fourth quarter of 2014, with the decrease in per unit DD&A being attributable to our increase in proved reserves relative to our depreciable asset base and reductions in assumed future development costs.
General and Administrative, net of amounts capitalized ("G&A"). G&A excluding certain non-recurring items and non-cash incentive share-based compensation valuation adjustments ("Adjusted G&A", a non-GAAP measure(i)) was $4.7 million, or $6.15 per BOE, for the current period compared to $3.9 million, or $5.89 per BOE, for the fourth quarter of 2014. The cash component of Adjusted G&A, which excludes the amortization of equity-settled share-based incentive awards and corporate depreciation and amortization, was $4.1 million, or $5.37 per BOE, compared to $2.9 million or $4.35 per BOE for the fourth quarter of 2014. G&A and Adjusted G&A for the first quarter of 2015 are calculated as follows:
Recurring | Non-Recurring | ||||||||||||||
G&A expenses: | Cash | Non-Cash | Cash | Non-Cash | Total | ||||||||||
Cash G&A | $ | 4,137 | $ | — | $ | — | $ | — | $ | 4,137 | |||||
Restricted stock share-based compensation | — | 479 | — | — | 479 | ||||||||||
Change in the fair value of liability share-based awards | — | 2,578 | — | — | 2,578 | ||||||||||
Corporate depreciation & amortization | — | 129 | — | — | 129 | ||||||||||
Threatened proxy contest | — | — | 111 | — | 111 | ||||||||||
Early retirement expenses | — | — | 3,553 | 1,115 | 4,668 | ||||||||||
Total G&A expense: | $ | 4,137 | $ | 3,186 | $ | 3,664 | $ | 1,115 | $ | 12,102 | |||||
Adjusted G&A: | |||||||||||||||
Less: Change in the fair value of liability share-based awards | $ | (2,578) | |||||||||||||
Less: Early retirement expenses | (4,668) | ||||||||||||||
Less: Threatened proxy context expenses | (111) | ||||||||||||||
Adjusted G&A - total | 4,745 | ||||||||||||||
Restricted stock share-based compensation | (479) | ||||||||||||||
Corporate depreciation & amortization | (129) | ||||||||||||||
Adjusted G&A - cash component | $ | 4,137 | |||||||||||||
The Company recorded a one-time expense related to the early retirement of approximately 20% of its employee base with the reductions occurring in the Natchez and Houston offices. The Company expects the initiative will reduce future Adjusted G&A (including expensed and capitalized amounts) by approximately $5 million per year, starting in the second quarter of 2015.
Income (Loss) Available to Common Shareholders. The Company reported a net loss available to common shareholders of $12.2 million in the first quarter of 2015 and Adjusted income available to common shareholders ("Adjusted Income"), a non-GAAP measure(i), of $0.1 million, or $0.00 per diluted share.
The following tables reconcile to the related GAAP measure the Company's income (loss) available to common stockholders to Adjusted Income and the Company's net income (loss) to Adjusted EBITDA:
Three Months Ended | |||||||||
March 31, 2015 | December 31, 2014 | March 31, 2014 | |||||||
Income (loss) available to common stockholders | $ | (12,171) | $ | 16,988 | $ | (111) | |||
Net loss (gain) on derivatives, net of settlements | 5,144 | (14,249) | 1,065 | ||||||
Rig termination fee | 2,367 | — | — | ||||||
Change in the fair value of share-based awards | 1,676 | (1,713) | 1,726 | ||||||
Early retirement expenses | 3,034 | — | 1,601 | ||||||
Withdrawn proxy contest expenses | 72 | 65 | 775 | ||||||
Gain on sale of other property and equipment | — | — | (702) | ||||||
Loss on early redemption of debt | — | 1,985 | — | ||||||
Adjusted income | $ | 122 | $ | 3,076 | $ | 4,354 | |||
Adjusted income per fully diluted common share | $ | 0.00 | $ | 0.05 | $ | 0.11 | |||
Three Months Ended | |||||||||
March 31, 2015 | December 31, 2014 | March 31, 2014 | |||||||
Net income (loss) | $ | (10,197) | $ | 18,962 | $ | 1,863 | |||
Net loss (gain) on derivatives, net of settlements | 7,914 | (21,921) | 1,639 | ||||||
Change in the fair value of share-based awards | 2,059 | (1,941) | 3,101 | ||||||
Early retirement expenses | 4,668 | — | 2,463 | ||||||
Rig termination fee | 3,641 | — | — | ||||||
Loss on early redemption of debt | — | 3,054 | — | ||||||
Withdrawn proxy contest expenses | 111 | 100 | 1,193 | ||||||
Acquisition expense | 3 | 668 | — | ||||||
Income tax expense (benefit) | (5,077) | 10,504 | 1,341 | ||||||
Interest expense | 4,858 | 4,765 | 977 | ||||||
Depreciation, depletion and amortization | 18,546 | 18,521 | 10,598 | ||||||
Accretion expense | 209 | 223 | 228 | ||||||
Adjusted EBITDA | $ | 26,735 | $ | 32,935 | $ | 23,403 | |||
Adjusted EBITDA per diluted share | $ | 0.47 | $ | 0.59 | $ | 0.58 | |||
Discretionary Cash Flow. Discretionary cash flow, a non-GAAP measure(i), for the first quarter of 2015 was $19.0 million or $0.33 per diluted share, and is reconciled to operating cash flow in the following table:
Three Months Ended | |||||||||
March 31, 2015 | December 31, 2014 | March 31, 2014 | |||||||
Cash flows from operating activities: | |||||||||
Net income (loss) | $ | (10,197) | $ | 18,962 | $ | 1,863 | |||
Adjustments to reconcile net income (loss) to cash provided by operating activities: | |||||||||
Depreciation, depletion and amortization | 18,546 | 18,521 | 10,598 | ||||||
Accretion expense | 209 | 223 | 228 | ||||||
Amortization of non-cash debt related items | 781 | 779 | 119 | ||||||
Amortization of deferred credit | — | (54) | (433) | ||||||
Deferred income tax (benefit) expense | (5,077) | 10,504 | 1,341 | ||||||
Net loss (gain) on derivatives, net of settlements | 7,914 | (21,921) | 1,639 | ||||||
Loss on early debt extinguishment | — | 3,054 | — | ||||||
Rig termination fee | 3,641 | — | — | ||||||
Gain on sale of other property and equipment | — | — | (1,080) | ||||||
Non-cash expense related to equity share-based awards | 86 | 692 | 996 | ||||||
Change in the fair value of liability share-based awards | 3,088 | (2,635) | 3,483 | ||||||
Discretionary cash flow | $ | 18,991 | $ | 28,125 | $ | 18,754 | |||
Discretionary cash flow per diluted share | $ | 0.33 | $ | 0.50 | $ | 0.47 | |||
Weighted average dilutive shares outstanding | 57,479 | 56,257 | 40,328 | ||||||
Changes in working capital | (5,988) | 9,090 | 2,908 | ||||||
Payments to settle asset retirement obligations | 258 | (525) | (26) | ||||||
Payments to settle vested liability share-based awards | |||||||||
related to early retirements | (3,538) | — | — | ||||||
Payments to settle vested liability share-based awards | (3,599) | — | (1,669) | ||||||
Net cash provided by operating activities | $ | 6,124 | $ | 36,690 | $ | 19,967 | |||
Operations Update
The following table summarizes the Company's drilling activity for the three months ended March 31, 2015:
Drilled | Completed (a) | Awaiting Completion | ||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||
Southern Midland Basin | ||||||||||||
Horizontal wells | 6 | 5.8 | 7 | 6.8 | 2 | 2.0 | ||||||
Total | 6 | 5.8 | 7 | 6.8 | 2 | 2.0 | ||||||
Central Midland Basin | ||||||||||||
Vertical wells | — | — | 1 | 0.4 | — | — | ||||||
Horizontal wells | 4 | 2.0 | 3 | 1.3 | 1 | 0.7 | ||||||
Total | 4 | 2.0 | 4 | 1.7 | 1 | 0.7 | ||||||
Total vertical wells | — | — | 1 | 0.4 | — | — | ||||||
Total horizontal wells | 10 | 7.8 | 10 | 8.1 | 3 | 2.7 | ||||||
Total | 10 | 7.8 | 11 | 8.5 | 3 | 2.7 | ||||||
(a) | Completions include wells drilled prior to 2015. |
For the three months ended March 31, 2015, the Company paid a total of $65.1 million of operational capital expenditures, including facilities, on a cash basis. These operational capital expenditures, inclusive of amounts paid for capital expenditures accrued at year-end, are detailed below:
Three Months Ended March 31, 2015 | ||||||||||||
Operational Capital Expenditures | Capitalized Interest | Capitalized G&A | Total Capital Expenditures | |||||||||
Cash basis | $ | 65,070 | $ | 2,889 | $ | 2,821 | $ | 70,780 | ||||
Timing adjustments (a) | (7,809) | (57) | — | (7,866) | ||||||||
Non-cash items | — | — | 2,145 | 2,145 | ||||||||
Accrual (GAAP) basis | $ | 57,261 | $ | 2,832 | $ | 4,966 | $ | 65,059 | ||||
(a) | Includes timing adjustments related to cash disbursements in the current period for capital expenditures incurred in the prior period. |
The Company has updated its operational capital guidance, on an accrual basis, that was established at $150 million to $165 million earlier this year. The update guidance of $160 million to $165 million reflects a higher than expected pace of drilling and completion due to operational efficiencies, combined with additional capital that has been budgeted to fund anticipated non-consenting working interest partners during the year. These increases are offset by higher than anticipated capital cost reductions realized to date. The revised operational guidance does not include any further assumed well costs reductions above those received to date. Callon currently anticipates drilling 26.9 net horizontal wells in 2015, an increase of approximately three net wells over previous estimates. As part of the new operational plan, the Company also plans to reallocate a portion of capital to drill an increased proportion of Lower Spraberry horizontal wells, targeting the drilling of 9.1 net wells during the year.
Full-Year 2015 Updated Guidance:
Full Year 2015 | ||||
Previous | Updated | |||
Total production (BOE/d) | 8,000 - 8,400 | 8,800 - 9,300 | ||
% oil | 79% - 81% | 79% - 81% | ||
Expenses (per BOE) | ||||
LOE, including workovers | $8.75 - $9.50 | $8.50 - $9.50 | ||
Production taxes, including ad valorem | $3.00 - $3.50 | $2.75 - $3.25 | ||
Adjusted G&A (a) | $5.75 - $6.25 | $5.50 - $5.75 | ||
Adjusted G&A - Cash Component (b) | $4.89 - $5.31 | $4.00 - $4.75 | ||
Second Quarter 2015 Guidance:
First Quarter | Second Quarter | |||
2015 Actual | 2015 Guidance | |||
Total production (BOE/d) | 8,567 | 8,800 - 9,100 | ||
% oil | 83% | 78% - 81% | ||
Expenses (per BOE) | ||||
LOE, including workovers | $9.03 | $9.00 - $9.70 | ||
Production taxes, including ad valorem | $2.94 | $2.75 - $3.25 | ||
Adjusted G&A (a) | $6.15 | $5.50 - $5.75 | ||
Adjusted G&A - Cash Component (b) | $5.37 | $4.00 - $4.75 |
(a) | Excludes certain non-recurring expenses and non-cash valuation adjustments. See the reconciliation provided within the Non-GAAP financial measures and reconciliations section of this press release for a reconciliation of G&A expense on a GAAP basis to Adjusted G&A expense. |
(b) | Excludes share-settled stock-based compensation expense and corporate depreciation and amortization. |
Hedge Portfolio Summary:
For the Three Months Ended | |||||||||||||||||||||
June 30, | September 30, | December 31, | March 31, | June 30, | September 30, | December 31, | |||||||||||||||
Oil contracts | 2015 | 2015 | 2015 | 2016 | 2016 | 2016 | 2016 | ||||||||||||||
Swap contracts: | |||||||||||||||||||||
Total volume (MBbls) | 409 | 520 | 442 | 91 | 91 | 92 | 92 | ||||||||||||||
Weighted average price per Bbl | $ | 70.79 | $ | 67.22 | $ | 64.93 | $ | 63.50 | $ | 63.50 | $ | 63.50 | $ | 63.50 | |||||||
Swap contracts (Midland basis | |||||||||||||||||||||
Differentials): | |||||||||||||||||||||
Volume (MBbls) | 400 | 382 | 327 | — | — | — | — | ||||||||||||||
Weighted average price per Bbl | $ | (2.40) | $ | (2.39) | $ | (2.38) | $ | — | $ | — | $ | — | $ | — | |||||||
Collar contracts combined with | |||||||||||||||||||||
short puts (three-way collar): | |||||||||||||||||||||
Volume (MBbls) | — | — | — | 91 | 91 | 92 | 92 | ||||||||||||||
Weighted average price per Bbl | |||||||||||||||||||||
Ceiling (short call) | $ | — | $ | — | $ | — | $ | 70.00 | $ | 70.00 | $ | 70.00 | $ | 70.00 | |||||||
Floor (long put) | $ | — | $ | — | $ | — | $ | 60.00 | $ | 60.00 | $ | 60.00 | $ | 60.00 | |||||||
Short put | $ | — | $ | — | $ | — | $ | 45.00 | $ | 45.00 | $ | 45.00 | $ | 45.00 | |||||||
For the Three Months Ended | |||||||||||||||||||||
June 30, | September 30, | December 31, | March 31, | June 30, | September 30, | December 31, | |||||||||||||||
Natural gas contracts | 2015 | 2015 | 2015 | 2016 | 2016 | 2016 | 2016 | ||||||||||||||
Collar contracts combined with | |||||||||||||||||||||
short puts (three-way collar): | |||||||||||||||||||||
Volume (BBtu) | 227 | 207 | 161 | — | — | — | — | ||||||||||||||
Weighted average price per MMBtu | |||||||||||||||||||||
Ceiling (short call) | $ | 4.32 | $ | 4.32 | $ | 4.32 | $ | — | $ | — | $ | — | $ | — | |||||||
Floor (long put) | $ | 3.85 | $ | 3.85 | $ | 3.85 | $ | — | $ | — | $ | — | $ | — | |||||||
Short put | $ | 3.25 | $ | 3.25 | $ | 3.25 | $ | — | $ | — | $ | — | $ | — | |||||||
Swap contracts: | |||||||||||||||||||||
Total volume (BBtu) | 237 | 219 | 228 | — | — | — | — | ||||||||||||||
Weighted average price per MMBtu | $ | 3.98 | $ | 3.98 | $ | 3.96 | $ | — | $ | — | $ | — | $ | — | |||||||
Short call contracts: | |||||||||||||||||||||
Short call volume (BBtu) | 109 | 110 | 111 | — | — | — | — | ||||||||||||||
Short call price per MMBtu | $ | 5.00 | $ | 5.00 | $ | 5.00 | $ | — | $ | — | $ | — | $ | — | |||||||
i. See "Non-GAAP Financial Measures and Reconciliations" included within this release for related disclosures and calculations
Non-GAAP Financial Measures and Reconciliations
This news release refers to non-GAAP financial measures as "discretionary cash flow," "Adjusted Income," "Adjusted G&A" and "Adjusted EBITDA." These measures, detailed below, 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.
- 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. Discretionary cash flow and discretionary cash flow per diluted share are calculated using net income (loss) adjusted for certain items including depreciation, depletion and amortization, the impact of financial derivatives (including the mark-to-market effects, net of cash settlements and premiums paid or received related to our financial derivatives), remaining asset retirement obligations related to our divested offshore properties, restructuring and other non-recurring costs, deferred income taxes and other non-cash income items.
- Callon believes that the non-GAAP measure of Adjusted G&A is useful to investors because it provides readers with a meaningful measure of our recurring G&A expense and provides for greater comparability period-over-period. The table below details all adjustments to G&A on a GAAP basis to arrive at Adjusted G&A.
- We believe that the non-GAAP measure of Adjusted income available to common shareholders ("Adjusted Income") and Adjusted Income per diluted share are useful to investors because they provide readers with a meaningful measure of our profitability before recording certain items whose timing or amount cannot be reasonably determined. These measures exclude the net of tax effects of certain non-recurring items and non-cash valuation adjustments, which are detailed in the reconciliation provided below. Prior to being tax-effected and excluded, the amounts reflected in the determination of Adjusted Income and Adjusted Income per diluted share below were computed in accordance with GAAP.
- We calculate Adjusted Earnings before Interest, Income Taxes, Depreciation, Depletion and Amortization ("Adjusted EBITDA") as Adjusted income plus interest expense, income tax expense (benefit) and depreciation, depletion and amortization expense. Adjusted EBITDA is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income (loss), operating income (loss), cash flow provided by operating activities or other income or cash flow data prepared in accordance with GAAP. However, we believe that Adjusted EBITDA provides additional information with respect to our performance or ability to meet its future debt service, capital expenditures and working capital requirements. Because Adjusted EBITDA excludes some, but not all, items that affect net income (loss) and may vary among companies, the Adjusted EBITDA we present may not be comparable to similarly titled measures of other companies.
Callon Petroleum Company | |||||
Consolidated Balance Sheets | |||||
(in thousands, except par and per share values and share data) | |||||
March 31, 2015 | December 31, 2014 | ||||
ASSETS | |||||
Current assets: | |||||
Cash and cash equivalents | $ | 2,144 | $ | 968 | |
Accounts receivable | 31,930 | 30,198 | |||
Fair value of derivatives | 19,160 | 27,850 | |||
Other current assets | 989 | 1,441 | |||
Total current assets | 54,223 | 60,457 | |||
Oil and natural gas properties, full cost accounting method: | |||||
Evaluated properties | 2,140,937 | 2,077,985 | |||
Less accumulated depreciation, depletion and amortization | (1,496,454) | (1,478,355) | |||
Net oil and natural gas properties | 644,483 | 599,630 | |||
Unevaluated properties | 142,867 | 142,525 | |||
Total oil and natural gas properties | 787,350 | 742,155 | |||
Other property and equipment, net | 8,046 | 7,118 | |||
Restricted investments | 3,292 | 3,810 | |||
Deferred tax asset | 47,238 | 44,688 | |||
Deferred financing costs | 17,432 | 18,200 | |||
Other assets, net | 456 | 342 | |||
Total assets | $ | 918,037 | $ | 876,770 | |
LIABILITIES AND STOCKHOLDERS' EQUITY | |||||
Current liabilities: | |||||
Accounts payable and accrued liabilities | $ | 68,271 | $ | 76,753 | |
Accrued interest | 5,853 | 5,993 | |||
Cash-settled restricted stock unit awards | 6,473 | 3,856 | |||
Asset retirement obligations | 5,047 | 4,747 | |||
Deferred tax liability | 3,687 | 6,214 | |||
Fair value of derivatives | 473 | 1,249 | |||
Total current liabilities | 89,804 | 98,812 | |||
Senior secured revolving credit facility | 37,000 | 35,000 | |||
Secured second lien term loan | 300,000 | 300,000 | |||
Asset retirement obligations | 1,262 | 1,927 | |||
Cash-settled restricted stock unit awards | 2,300 | 7,175 | |||
Other long-term liabilities | 120 | 121 | |||
Total liabilities | 430,486 | 443,035 | |||
Stockholders' equity: | |||||
Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized: 1,578,948 and 1,578,948 shares outstanding, respectively | 16 | 16 | |||
Common stock, $0.01 par value, 110,000,000 shares authorized; 65,860,729 and 55,225,288 shares outstanding, respectively | 659 | 552 | |||
Capital in excess of par value | 592,042 | 526,162 | |||
Accumulated deficit | (105,166) | (92,995) | |||
Total stockholders' equity | 487,551 | 433,735 | |||
Total liabilities and stockholders' equity | $ | 918,037 | $ | 876,770 | |
Callon Petroleum Company | ||||||
Consolidated Statements of Operations | ||||||
(in thousands, except per share data) | ||||||
Three Months Ended March 31, | ||||||
2015 | 2014 | |||||
Operating revenues: | ||||||
Oil sales | $ | 27,909 | $ | 30,909 | ||
Natural gas sales | 2,482 | 2,376 | ||||
Total operating revenues | 30,391 | 33,285 | ||||
Operating expenses: | ||||||
Lease operating expenses | 6,959 | 4,230 | ||||
Production taxes | 2,265 | 1,917 | ||||
Depreciation, depletion and amortization | 18,104 | 10,538 | ||||
General and administrative | 12,102 | 10,807 | ||||
Accretion expense | 209 | 228 | ||||
Rig termination fee | 3,641 | — | ||||
Gain on sale of other property and equipment | — | (1,080) | ||||
Total operating expenses | 43,280 | 26,640 | ||||
Income (loss) from operations | (12,889) | 6,645 | ||||
Other (income) expenses: | ||||||
Interest expense | 4,858 | 977 | ||||
(Gain) loss on derivative contracts | (2,429) | 2,513 | ||||
Other income | (44) | (49) | ||||
Total other expenses | 2,385 | 3,441 | ||||
Income (loss) before income taxes | (15,274) | 3,204 | ||||
Income tax expense (benefit) | (5,077) | 1,341 | ||||
Net income (loss) | (10,197) | 1,863 | ||||
Preferred stock dividends | (1,974) | (1,974) | ||||
Loss available to common stockholders | $ | (12,171) | $ | (111) | ||
Loss per common share: | ||||||
Basic | $ | (0.21) | $ | (0.00) | ||
Diluted | $ | (0.21) | $ | (0.00) | ||
Shares used in computing loss per common share: | ||||||
Basic | 57,479 | 40,328 | ||||
Diluted | 57,479 | 40,328 | ||||
Callon Petroleum Company | ||||||
Consolidated Statements of Cash Flows | ||||||
(in thousands) | ||||||
Three Months Ended March 31, | ||||||
2015 | 2014 | |||||
Cash flows from operating activities: | ||||||
Net income (loss) | $ | (10,197) | $ | 1,863 | ||
Adjustments to reconcile net income (loss) to cash provided by operating activities: | ||||||
Depreciation, depletion and amortization | 18,546 | 10,598 | ||||
Accretion expense | 209 | 228 | ||||
Amortization of non-cash debt related items | 781 | 119 | ||||
Amortization of deferred credit | — | (433) | ||||
Deferred income tax (benefit) expense | (5,077) | 1,341 | ||||
Net loss on derivatives, net of settlements | 7,914 | 1,639 | ||||
Gain on sale of other property and equipment | — | (1,080) | ||||
Non-cash expense related to equity share-based awards | 86 | 996 | ||||
Change in the fair value of liability share-based awards | 3,088 | 3,483 | ||||
Payments to settle asset retirement obligations | 258 | (26) | ||||
Changes in current assets and liabilities: | ||||||
Accounts receivable | (2,125) | (2,928) | ||||
Other current assets | 452 | 707 | ||||
Current liabilities | (355) | 5,155 | ||||
Payments to settle vested liability share-based awards related to early retirements | (3,538) | — | ||||
Payments to settle vested liability share-based awards | (3,599) | (1,669) | ||||
Change in other assets, net | (319) | (26) | ||||
Net cash provided by operating activities | 6,124 | 19,967 | ||||
Cash flows from investing activities: | ||||||
Capital expenditures | (70,780) | (65,760) | ||||
Proceeds from sales of mineral interest and equipment | 272 | 2,226 | ||||
Net cash used in investing activities | (70,508) | (63,534) | ||||
Cash flows from financing activities: | ||||||
Borrowings on credit facility | 60,000 | 46,000 | ||||
Payments on credit facility | (58,000) | — | ||||
Payment of deferred financing costs | (12) | (1,729) | ||||
Issuance of common stock | 65,546 | — | ||||
Payment of preferred stock dividends | (1,974) | (1,974) | ||||
Net cash provided by financing activities | 65,560 | 42,297 | ||||
Net change in cash and cash equivalents | 1,176 | (1,270) | ||||
Balance, beginning of period | 968 | 3,012 | ||||
Balance, end of period | $ | 2,144 | $ | 1,742 | ||
Earnings Call Information
The Company will host a conference call on Thursday, May 7, 2015 to discuss first quarter 2015 financial and operating results.
Please join Callon Petroleum Company via the Internet for a webcast of the conference call:
Date/Time: | Thursday, May 7, 2015, at 8:00 a.m. Central Time (9:00 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 using the following numbers: | |
Toll Free: | 1-888-349-0096 |
Canada Toll Free: | 1-855-669-9657 |
International: | 1-412-902-0125 |
Request to join: | Callon Petroleum Company Earnings call |
An archive of the conference call webcast will also be available at www.callon.com in the "Investors" section of the website.
About Callon Petroleum
Callon Petroleum Company is an independent energy company focused on the acquisition, development, exploration, and operation of oil and gas properties in the Permian Basin in West Texas.
This news release is posted on the Company's website at www.callon.com and will be archived there for subsequent review under the "News" link on the top of the homepage.
Cautionary Statement Regarding Forward Looking Statements
This news release contains 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, as well as statements including the words "believe," "expect," "plans" and words of similar meaning. These 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:
Joe Gatto
Chief Financial Officer, Senior Vice President and Treasurer
1-800-451-1294