Callon Petroleum Company Announces Third Quarter 2015 Results and Optimized Operational Plan

NATCHEZ, Miss., Nov. 4, 2015 /PRNewswire/ -- Callon Petroleum Company (NYSE: CPE) ("Callon" or the "Company") today reported results of operations for the three and nine month periods ended September 30, 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.

Highlights for the third quarter of 2015 include:

• Net daily production of 9,739 barrels of oil equivalent per day ("BOE/d"), an increase of 73% compared to the third quarter of 2014, comprised of 77% oil volume
• Adjusted EBITDA, a non-GAAP financial measure⁽ⁱ⁾, of $30.2 million, representing a margin of approximately 70% of Adjusted Total Revenues, a non-GAAP financial measure⁽ⁱ⁾
• Adjusted Income available to common shareholders, a non-GAAP financial measure⁽ⁱ⁾, of $0.05 per diluted share based on total average diluted shares outstanding of 66.3 million shares
• Discretionary cash flow per share, a non-GAAP financial measure⁽ⁱ⁾, of $0.38 per diluted share based on total average diluted shares outstanding of 66.3 million shares
• Acceleration of operational plan, and related infrastructure investment, to dedicate both horizontal rigs to the Central Midland Basin, primarily targeting the Lower Spraberry shale

"We continue to focus on improving our operating cost structure and capital efficiency in the current environment," commented Fred Callon, Chairman and Chief Executive Officer. "In order to advance our goal of funding our drilling program with internally generated cash flows by mid-2016, we made the decision in August to modify our operational plans and focus our two horizontal drilling rigs on our Central Midland acreage. We will focus on Lower Spraberry shale development through 2016, and will continue to monitor opportunities to develop the Wolfcamp A and Middle Spraberry as those zones are further delineated. Callon was able to quickly pivot in the current environment due to a property base that is entirely held by production, with no drilling commitments that would prevent us from targeting our highest return opportunities. We believe this unique flexibility will continue to benefit our operations in a volatile commodity price environment, and also create optionality to pursue acquisition and partnership opportunities that require near-term drilling to hold acreage."

Operations Update

Callon currently has 78 gross (67.6 net) horizontal wells located in the Central and Southern Midland Basin, producing from five established zones, including a Middle Spraberry well placed on production in late October 2015. During the third quarter, the Company accelerated a planned shift in operational focus to its Central Midland Basin properties, with a particular focus on Lower Spraberry drilling. Callon dedicated its two horizontal rigs to the Carpe Diem and Casselman-Bohannon fields in early September and plans to operate both rigs on its Central Midland acreage through 2016. Based on its operational plan for this new drilling program, the Company has established a preliminary operational capital budget, including facilities, of $110 million for 2016 assuming its current well cost of $5.9 million for a 7,500' lateral. This program currently contemplates the drilling of approximately 17.1 net horizontal wells, with 15.6 net wells targeting the Lower Spraberry. The Company anticipates announcing a formal capital budget plan approved by the Board of Directors and accompanying guidance metrics in early 2016.

The following table summarizes the Company's drilling activity for the period indicated:

Operational Capital Budget and Third Quarter Summary

In order to facilitate its tactical shift to the Central Midland area, the Company recently increased its 2015 operational capital budget by approximately 10% to $180 million (on an accrual, or GAAP, basis), with the increase primarily related to the facilities and infrastructure investment required to accommodate an increased level of activity. Part of the increase was also attributable to longer completed lateral lengths, enhanced completion designs, and non-consenting partner capital, offset in part by continued achieved reductions in well costs throughout the year. A reconciliation of the revised capital budget to the original plan is provided below (in millions):

For the three months ended September 30, 2015, the Company accrued $47.1 million in operational capital expenditures, including facilities, compared to $45.1 million in the second quarter of 2015. Total capital expenditures, inclusive of capitalized expenses, are detailed below on an accrual and cash basis (in thousands):

Fourth Quarter and Annual 2015 Guidance:

Operating and Financial Results

The following table presents summary information for the periods indicated, and are followed by the Company's financial statements.

Total Revenue. For the quarter ended September 30, 2015, Callon reported total revenues including cash-settled derivatives ("Adjusted Total Revenue," a non-GAAP financial measure⁽ⁱ⁾) of $44.1 million, comprised of oil revenues of $30.6 million, natural gas revenues of $3.7 million and the $9.8 million impact of settled derivative contracts. The table above reconciles to the related GAAP measure the Company's revenue to Adjusted Total Revenue. Average daily production for the quarter was 9,739 BOE/d compared to average daily production of 9,516 BOE/d in the second quarter of 2015. Average realized prices, including and excluding the effects of hedging, are detailed below.

Hedging impacts. For the quarter ended September 30, 2015, Callon recognized the following hedging-related items:

Average realized prices, including and excluding the impact of cash settled derivatives during the third quarter, were as follows:

Lease Operating Expenses, including workover expense ("LOE"). LOE for the three months ended September 30, 2015 was $8.03 per BOE, compared to LOE of $7.59 per BOE in the second quarter of 2015.

Production Taxes, including ad valorem taxes. Production taxes were $2.88 per BOE in the third quarter of 2015, representing approximately 7.5% of total revenue before the impact of derivative settlements.

Depreciation, Depletion and Amortization ("DD&A"). DD&A for the three months ended September 30, 2015 was $18.64 per BOE compared to $20.31 per BOE in the second quarter of 2015, with the decrease in per unit DD&A being attributable to increases in proved reserves relative to our depreciable asset base and assumed future development costs related to undeveloped proved reserves.

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 $4.1 million, or $4.63 per BOE, for the current period compared to $3.9 million, or $4.53 per BOE, for the second quarter of 2015. G&A and Adjusted G&A, which excludes the amortization of equity-settled, share-based incentive awards and corporate depreciation and amortization, for the third quarter of 2015 are calculated as follows (in thousands):

Write-down of Oil and Natural Gas Properties. During the third quarter of 2015, the Company recognized a write-down of oil and natural gas properties of $87.3 million as a result of the ceiling test limitation and the impact of lower commodity prices. No write-down of oil and natural gas properties was recognized during the comparable prior year periods.

Income (Loss) Available to Common Shareholders. The Company reported a net loss available to common shareholders of $113.8 million in the third quarter of 2015 and adjusted income available to common shareholders ("Adjusted Income"), a non-GAAP measure⁽ⁱ⁾, of $3.1 million, or $0.05 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 (in thousands):

Discretionary Cash Flow. Discretionary cash flow, a non-GAAP measure⁽ⁱ⁾, for the third quarter of 2015 was $25.1 million, or $0.38 per diluted share, and is reconciled to operating cash flow in the following table (in thousands):

Hedge Portfolio Summary

(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 such as "discretionary cash flow," "Adjusted Income," "Adjusted G&A" and "Adjusted EBITDA," and "Adjusted Total Revenues." 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 above 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.
• We believe that the non-GAAP measure of Adjusted Total Revenues is useful to investors because it provides readers with a revenue value more comparable to other companies who account for derivative contracts and hedges and include their affects in revenue. We believe Adjusted Total Revenue is also useful to investors as a measure of the actual cash inflows generated during the period.