NATCHEZ, Miss., Nov. 2, 2016 /PRNewswire/ -- 

Callon Petroleum Company (NYSE: CPE) ("Callon" or the "Company") today reported results of operations for the three months ended September 30, 2016.

Presentation slides accompanying this earnings release are available on the Company's website at www.callon.com located on the "Presentations" page within the Investors section of the site.

Financial and operational highlights for the third quarter of 2016 and other recent data points include:

• Net daily production of 16,598 barrels of oil equivalent per day ("BOE/d"), an increase of 23% compared to the second quarter of 2016
• GAAP income per diluted common share of $0.14 and Adjusted Income per fully diluted common share, a non-GAAP financial measure⁽ⁱ⁾, of $0.09
• Closed the Plymouth Acquisition and related common stock financing, expanding our WildHorse area footprint to over 20,000 net acres and total Midland Basin acreage to over 40,000 net acres
• Continued strong performance from our initial Wolfcamp A completion in Howard County (Silver City Unit A 01H), with cumulative production of over 192,000 BOE (89% oil) in the first 110 days on production
• Commenced program development of the WildHorse area with a two-well pad targeting both the Wolfcamp A and Lower Spraberry zones in northwest Howard County
• Refinanced our Term Loan with the issuance of Senior Notes, reducing our cost of capital and establishing a benchmark, publicly-traded security for future financing opportunities
• Raised 2016 full year production guidance to a range of 15,250 – 15,550 BOE/d and reaffirmed operational capital guidance for 2016 of $140 million

"Our strong recent well results combined with the longer term performance of our production base enable us to continue our track record of sustained production growth within a restrained capital program," commented Fred Callon, Chairman and Chief Executive Officer. "Given our expanded portfolio of drilling opportunities that deliver solid returns on investment at less than $50 per barrel of oil, combined with low leverage metrics and liquidity of almost $500 million, we currently anticipate adding a third horizontal drilling rig in early 2017 and are preparing for a fourth rig in the second half of 2017. We forecast this program would deliver approximately 30,000 BOE/d of annual average production in 2018, while generating free cash flow by mid-year 2018 based on our 2018 planning case assumptions of $50 per barrel and a theoretical increase of 15% in completed well costs to address the impact of evolving completion designs and potential upward pressure on service costs from anticipated increases in core Permian Basin activity."

Operations Update

At September 30, 2016, we had 124 gross (98.0 net) horizontal wells producing from six established flow units. Net daily production for the three months ended September 30, 2016 grew approximately 70% to 16,598 BOE/d (approximately 76% oil) as compared to the same period of 2015. Sequentially, we grew production more than 23% compared to the second quarter of 2016.

For the three months ended September 30, 2016, we operated 1.6 horizontal drilling rigs, drilled 8 gross (5.4 net) horizontal wells, completed 11 gross (6.8 net) horizontal wells, and placed 7 gross (5.2 net) horizontal wells on production. As of September 30, 2016, we had 3 gross (2.8 net) horizontal wells awaiting completion.

Well Activity Summary

The following table details well-related activity for the quarter by focus area:

During the third quarter, we continued to focus on development of two flow units within the Lower Spraberry in the Monarch area while also progressing the infrastructure buildout of WildHorse in preparation for program development with multi-well pads. The following table highlights wells that achieved peak rates during the period:

In early October, our first Wolfcamp A well in the Monarch area was placed on production in the Pecan Acres field in close proximity to recent offsetting industry activity in this zone. The Wolfcamp A represents our fifth producing flow unit in the Monarch area, inclusive of the upper and lower benches of the Lower Spraberry, the Middle Spraberry and the Wolfcamp B. This well was drilled from a stacked two-well pad with a Lower Spraberry (upper bench) well. Both wells are cleaning up and have not reached peak rates.

We also completed two drilled, uncompleted wells in the Ranger area that were acquired earlier this year as part of our AMI transaction in western Reagan County. Our development activity in the Ranger area had previously been focused on Lower Wolfcamp B, and these wells expand our efforts to the Upper Wolfcamp B and Wolfcamp A. Importantly, we utilized a new generation completion design on these latest wells, with proppant loading approximating 2,000 pounds per foot combined with tighter stage spacing. Both wells were placed online in late September and have not reached peak rates.

Our first operated completion in the WildHorse area yielded encouraging results with the Silver City Unit A 01H well achieving 24-Hour and 30-Day IP rates of 334 (91% oil) and 292 (89% oil) BOE/d per 1,000 feet of completed lateral, respectively. This Wolfcamp A well has produced over 192 MBOE in the first 110 days since first production. As part of our newly initiated program development of WildHorse, we recently finished drilling two wells in offsetting acreage targeting both the Wolfcamp A and Lower Spraberry zones from a two-well pad. The rig remains active on this acreage, currently drilling two additional wells targeting both the Wolfcamp A and Lower Spraberry zones from a stacked two-well pad.

Capital Expenditures

For the three months ended September 30, 2016, we accrued $43.3 million in operational capital expenditures, including facilities expenditures of $4.5 million, compared to $21.1 million in the second quarter of 2016. Total capital expenditures, inclusive of capitalized expenses, are detailed below on an accrual and cash basis (in thousands):

Operating and Financial Results

The following table presents summary information for the periods indicated:

Total Revenue. For the quarter ended September 30, 2016, Callon reported total revenues of $55.9 million and total revenues including cash-settled derivatives ("Adjusted Total Revenue," a non-GAAP financial measure⁽ⁱ⁾) of $60 million, including the $4.1 million impact of settled derivative contracts. The table above reconciles to the related GAAP measure of the Company's revenue to Adjusted Total Revenue. Average daily production for the quarter was 16,598 BOE/d compared to average daily production of 13,451 BOE/d in the second quarter of 2016. Average realized prices, including and excluding the effects of hedging, are detailed below.

Hedging impacts. For the quarter ended September 30, 2016, Callon recognized the following hedging-related items (in thousands):

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 per BOE for the three months ended September 30, 2016 was $6.52 per BOE, compared to LOE of $5.97 per BOE in the second quarter of 2016. The increase in this metric was primarily related to higher saltwater disposal and fuel and power expenses related to assets acquired during 2016. We continue to make investments in infrastructure in these areas to support our planned increases in drilling activity and expect these investments to reduce our LOE in these areas over time.

Production Taxes, including ad valorem taxes. Production taxes were $2.28 per BOE in the third quarter of 2016, representing approximately 6.2% of total revenue before the impact of derivative settlements.

Depreciation, Depletion and Amortization ("DD&A"). DD&A for the three months ended September 30, 2016 was $11.33 per BOE compared to $13.31 per BOE in the second quarter of 2016. The write-down of our oil and natural gas properties recorded during the second quarter 2016 reduced the amortizable base, while our underlying reserve base continues to increase as we progress our horizontal development program. Combined, these changes resulted in the $1.98 per BOE reduction in DD&A.

General and Administrative ("G&A"). G&A for the third quarter of 2016 was $7.9 million, or $5.17 per BOE, compared to $6.3 million, or $5.15 per BOE, for the second quarter of 2016. G&A, excluding certain non-cash incentive share-based compensation valuation adjustments, ("Adjusted G&A", a non-GAAP measure⁽ⁱ⁾) was $4.5 million, or $2.96 per BOE, for the third quarter of 2016 compared to $4.3 million, or $3.55 per BOE, for the second quarter of 2016. The cash component of Adjusted G&A was $3.6 million, or $2.38 per BOE, for the third quarter of 2016 compared to $3.6 million, or $2.92 per BOE, for the second quarter of 2016.

For the third quarter of 2016, G&A and Adjusted G&A, which excludes the amortization of equity-settled, share-based incentive awards and corporate depreciation and amortization, are calculated as follows (in thousands):

Income tax expense. Callon typically provides for income taxes at a statutory rate of 35% adjusted for permanent differences expected to be realized, which primarily relate to non-deductible executive compensation expenses and state income taxes. We recorded $0.1 million income tax expense for the three months ended September 30, 2016. At September 30, 2016 we had a valuation allowance of $139.6 million. Adjusted Income per fully diluted common share, a non-GAAP financial measure⁽ⁱ⁾, adjusts our income (loss) available to common stockholders to reflect our theoretical tax provision for the quarter as if the valuation allowance did not exist.

A breakdown of the Company's anticipated 2016 operational plan and associated expenditures is presented below:

 

2016 Guidance Update

 

Hedge Portfolio Summary

The following table summarizes our open derivative positions as of November 2, 2016:

Income (Loss) Available to Common Shareholders. The Company reported a net income available to common shareholders of $19.3 million in the third quarter of 2016 and Adjusted Income available to common shareholders of $12.9 million, or $0.09 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 2016 was $42.7 million and is reconciled to operating cash flow in the following table (in thousands):

 

 

 

Non-GAAP Financial Measures and Reconciliations

This news release refers to non-GAAP financial measures such as "Discretionary Cash Flow," "Adjusted Income (Loss)," "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 natural 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 above 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 effects in revenue. We believe Adjusted Total Revenue is also useful to investors as a measure of the actual cash inflows generated during the period.

Earnings Call Information

The Company will host a conference call on Thursday, November 3, 2016, to discuss third quarter 2016 financial and operating results.

Please join Callon Petroleum Company via the Internet for a webcast of the conference call:

Alternatively, you may join by telephone using the following numbers:

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 natural 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 regarding wells anticipated to be drilled and placed on production; future levels of drilling activity and associated production and cash flow expectations; the Company's 2016 guidance and capital expenditure forecast; reserve quantities and the present value thereof; and the implementation of the Company's business plans and strategy, 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 natural 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 and Quarterly Reports on Form 10-Q, available on our website or the SEC's website at www.sec.gov.

For further information contact:
Eric Williams
Manager, Finance
1-800-451-1294

 

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SOURCE Callon Petroleum Company