Supplemental Oil and Gas Reserve Data (unaudited)
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Dec. 31, 2011
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Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Supplemental Oil and Gas Reserve Data (unaudited) |
Supplemental Oil and Natural Gas Reserve Data (unaudited)
The Company's proved oil and natural gas reserves at December 31, 2011, 2010 and 2009 have been estimated by Huddleston & Co., Inc., the Company’s independent petroleum engineers. The reserves were prepared in accordance with guidelines established by the SEC. Accordingly, the following reserve estimates are based upon existing economic and operating conditions.
There are numerous uncertainties inherent in establishing quantities of proved reserves. The following reserve data represents estimates only and should not be construed as being exact. In addition, the standardized measure of discounted future net cash flows should not be construed as the current market value of the Company's oil and natural gas properties or the cost that would be incurred to obtain equivalent reserves.
Estimated Reserves
Changes in the estimated net quantities of crude oil and natural gas reserves, all of which are located onshore within the continental United States and offshore within the Gulf of Mexico, are as follows:
Standardized Measure
The following tables present the standardized measure of future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2011. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil and natural gas reserves. Prior to December 31, 2009, the Company was required to determine estimated future net cash flows using period-end market prices for oil and natural gas without considering hedge contracts in place at the end of the period. Effective December 31, 2009, the SEC issued a final rule which changed prices used in reserves calculations. Prices are no longer based on a single-day, period-end price. Rather, they are based on either the preceding 12-months’ average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements. The following table summarizes the average 12-month oil and natural gas prices net of differentials for the respective periods:
Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10% annual discount rate.
Natural gas production from our deepwater and Permian Basin properties has a high BTU content of separator natural gas. The natural gas Mcf prices of $5.60 and $5.10 used in the 2011 and 2010 reserve estimates include adjustments to reflect the Btu content, transportation charges and other fees specific to the individual properties. The projected oil prices of $98.98 and $78.07 used in the 2011 and 2010 reserve estimates have been adjusted to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality.
The Company ended 2011 with estimated net proved reserves of 15,928 MBoe, representing a 17% increase over 2010 year-end estimated net proved reserves of 13,641 MBoe. The increase is primarily due to the Company’s development of a portion of its Permian Basin, on which it drilled a total of 36 oil wells during 2011.
The Company annually reviews its proved undeveloped reserves (“PUDs”) to ensure an appropriate plan for development exists. Generally, reserves for the Company’s onshore properties are booked as PUDs only if the Company has plans to convert the PUDs into proved developed reserves within five years of the date they are first booked as PUDs. Callon had 8,925 MBoe of PUDs at December 31, 2011, representing a 27% increase over the 7,019 MBoe of PUDs at December 31, 2010. Of its 2011 PUDs, 1,186 MBoe and 1,148 MBoe were attributable to the Company’s offshore properties in the Medusa and Habanero fields in the Gulf of Mexico, respectively. Callon plan to develop its Medusa PUDs by drilling a new well in 2013, and to develop its Habanero PUDs by side tracking an existing well during the fourth quarter of 2012. The Company did not convert any offshore, deepwater PUDs to proved developed in 2011.
During 2009, the Company acquired 711 MBbls and 1.3 Bcf, or 928 MBoe, of PUDs in its ExL acquisition. Callon’s development plan for these PUDs began during 2010, and is expected to convert all PUDs to PDPs by 2014. Also during 2009, Callon's deepwater Medusa field PUDs increased 100 MBoe as a result of including reserves related to the Deepwater Royalty Relief Act. These PUDs were previously excluded due to prices exceeding the BOEM imposed thresholds. As a result of court decisions, the BOEM is no longer enforcing its price thresholds.
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