HOUSTON, Feb. 12, 2019 /PRNewswire/ -- Callon Petroleum Company (NYSE: CPE) ("Callon" or the "Company") today announced its 2019 capital expenditure budget, reflecting a combination of financial discipline and capital efficiency gains.
- 2019 forecasted annual production of 39.5 - 41.5 MBoe/d (77% - 78% oil), representing growth of over 20% compared to current "street" consensus of 32.7 MBoe/d for 2018
- Planned sequential decrease in 2019 operational capital expenditures to a range of $500 to $525 million
- Running an average of five drilling rigs to support larger and more efficient, multi-well pad development
- Plan to place 47 - 49 net wells on production with an increase of approximately 15% in average net lateral length over the 2018 program
- Year-end 2018 proved reserves of 238.5 MMBoe (54% proved developed and 76% oil), an annual increase in total proved reserves of 74% and proved developed reserves of 85%
- Year-end 2018 PV-10 value1 of $3.1 billion
Joe Gatto, President and Chief Executive Officer of Callon, stated, "Our 2019 capital program highlights our commitment to generate free cash flow in the near-term as we transition to scaled development of our high quality asset base. Strong cash operating margins underpin our plan and are complemented by capital efficiency improvements resulting from multi-well pad development in the Delaware Basin, increasing lateral lengths across our portfolio and a significant reduction in facilities spending. Even under our flat $50/Bbl WTI oil price assumption, we expect to be free cash flow positive in the fourth quarter of 2019 with a full year outspend that is almost half of our 2018 projection. In addition, although our production growth rate will be lower than previous years, the combination of a well-established Midland Basin operation and the emerging impact of large pad development in the Delaware Basin positions us for a sustained trajectory over the longer term with capital expenditures within or below internal cash flows." He continued, "Our tremendous progress maturing the business in recent years now allows us to benefit from repeatable well investments that will drive improved corporate-level returns due to scale efficiencies, reduced facilities needs and shallower production decline rates on a consolidated basis. Any improvement in commodity prices would further enhance that return on capital profile, as we have no plans to increase capital investment in 2019 with higher oil prices."
2019 Capital Expenditures Budget
Callon expects operational capital expenditures to range between $500 and $525 million in 2019, with infrastructure and facilities capital comprising approximately 15% of operational capital. The percentage of operational expenditures allocated to the Delaware Basin is planned to increase to approximately 60% of the total with a transition to larger pad development in our Spur area as the year progresses to capture additional capital efficiencies and optimize development of our multi-zone resource base. Specifically, our average pad size in the Spur area is expected to more than double relative to our 2018 activity. As a result, completion activity will be primarily focused on the Midland Basin in the first half of the year and shift to a high proportion of multi-well pads in the Delaware Basin in the second half of 2019, accelerating production growth into year-end while maximizing capital efficiency. The program is also designed to optimize production and resource recovery from multiple zones through various co-development concepts that are tailored to specific operating areas. As a result, we will target seven discrete flow units in 2019, but the largest amount of wells are scheduled for the Wolfcamp A (upper and lower intervals).
Importantly, our plan also incorporates a 15% increase in lateral length to approximately 8,400 feet as our highly contiguous Delaware Basin position enters program development, enabling us to place more net lateral feet on production in 2019 despite a decrease in net wells placed on line (47 to 49 wells) relative to 2018. Based upon this level of activity and associated allocation of capital, we are guiding to an average daily production rate range of 39.5 to 41.5 MBoe/d with an associated oil cut of 77% to 78%.
We are currently operating six rigs and one dedicated completion crew. We expect to reduce the number of active rigs from six to four by mid-year after building a sufficient inventory of wells awaiting completion to provide operational flexibility for an increased proportion of larger pad concepts. We began 2019 with one dedicated completion crew and intend to reactivate a second crew to reduce cycle times on large development pads once the necessary drilling activity has been completed.
In addition to operational capital expenditures, we forecast 2019 capitalized general & administrative expenses (cash component) of approximately $25 to $30 million and expect to capitalize 100% of cash interest expense that would otherwise be reflected on the income statement. Based upon current market interest rates, we estimate an applicable weighted average interest rate on our total average debt balances to be approximately 6%. In total, we forecast total capital expenditures (including estimated total capitalized expenses) of $615 million at the midpoint for 2019. This amount also includes land and seismic expenditures associated with the execution of our operational program. To the extent we identify accretive "bolt-on" land acquisition opportunities, we expect that these non-organic capital costs would be funded by divestitures of non-core properties or monetization of infrastructure investments.
2018 Proved Reserves
The Company recently completed the reserve audit for the year ended December 31, 2018 with its independent reserve auditor, DeGolyer and MacNaughton. As of December 31, 2018, Callon's estimated total proved reserves were 238.5 MMBoe, a 74% increase over the previous year-end. The proved reserves estimate is comprised of 76% oil and 54% proved developed estimated volumes. The PV-10 value1 of proved reserves at year-end 2018 was $3.1 billion, with a proved developed producing reserves value of $2.2 billion.
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 for subsequent review under the "News" link on the top of the homepage.
Non-GAAP Disclosure
PV-10
Year-end pre-tax PV-10 value is a non-GAAP financial measure as defined by the SEC. Callon believes that the presentation of pre-tax PV-10 value is relevant and useful to its investors because it presents the discounted future net cash flows attributable to reserves prior to taking into account future corporate income taxes and the Company's current tax structure. The Company further believes investors and creditors use pre-tax PV-10 values as a basis for comparison of the relative size and value of its reserves as compared with other companies.
The GAAP financial measure most directly comparable to pre-tax PV-10 is the standardized measure of discounted future net cash flows ("Standardized Measure"). Pre-tax PV-10 is calculated using the Standardized Measure before deducting future income taxes, discounted at 10%. The Company expects to include a full reconciliation of pre-tax PV-10 to the GAAP financial measure of Standardized Measure in its Earnings Press Release on Form 8-K for the fourth quarter 2018 financial and operating results, which it intends to file with the SEC on February 26, 2019.
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 2019 production guidance and capital expenditure forecast; estimated reserve quantities and the present value thereof; anticipated returns and financial position; and the implementation of the Company's business plans and strategy, as well as statements including the words "believe," "expect," "may," "will," "forecast," "plans" and words of similar meaning. These statements reflect the Company's current views with respect to future events and financial performance based on management's experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. 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. Any forward-looking statement speaks only as of the date of which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. 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, cost and availability of equipment and labor, 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
Mark Brewer
Director of Investor Relations
1-281-589-5200
1 A non-GAAP financial measure: The 12-month average benchmark pricing used to estimate proved reserves in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission ("SEC") and pre-tax PV-10 value for crude oil and natural gas was $65.56 per Bbl of WTI crude oil and $3.10 per MMBtu of natural gas at Henry Hub before differential adjustments. After differential adjustments, the Company's SEC pricing realizations for year-end 2018 were $58.40 per Bbl of oil and $3.64 per Mcf of natural gas. Please refer to the Non-GAAP Disclosure at the end of this release for information regarding pre-tax PV-10.
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