Annual report pursuant to Section 13 and 15(d)

Supplemental Oil and Gas Reserve Data (unaudited)

v2.4.0.6
Supplemental Oil and Gas Reserve Data (unaudited)
12 Months Ended
Dec. 31, 2011
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:
 
Reserve Quantities
For the year ended December 31,
 
2011
 
2010
 
2009
Proved developed and undeveloped reserves:
 
 
 
 
 
Crude Oil (MBbls):
 
 
 
 
 
Beginning of period
8,149

 
6,479

 
6,027

Revisions to previous estimates
(110
)
 
423

 
(356
)
Change in ownership

 

 
563

Purchase of reserves in place

 

 
1,257

Sale of reserves in place
(30
)
 

 

Extensions and discoveries
3,062

 
2,106

 

Production
(996
)
 
(859
)
 
(1,012
)
End of period
10,075

 
8,149

 
6,479

Natural Gas (MMcf):
 
 
 
 
 
Beginning of period
32,957

 
19,103

 
18,651

Revisions to previous estimates
486

 
354

 
3,632

Change in ownership

 

 
420

Purchase of reserves in place

 

 
2,140

Sale of reserves in place
(308
)
 

 

Extensions and discoveries
7,064

 
18,392

 

Production
(5,081
)
 
(4,892
)
 
(5,740
)
End of period
35,118

 
32,957

 
19,103

Proved developed reserves:
 
 
 
 
 
Crude Oil (MBbls):
 
 
 
 
 
Beginning of period
4,503

 
4,346

 
4,663

End of period
5,069

 
4,503

 
4,346

Natural Gas (MMcf):
 
 
 
 
 
Beginning of period
12,715

 
12,301

 
13,463

End of period
11,605

 
12,715

 
12,301

Proved undeveloped reserves:
 
 
 
 
 
Crude Oil (MBbls):
 
 
 
 
 
Beginning of period
3,645

 
2,133

 
1,364

End of period
5,006

 
3,645

 
2,133

Natural Gas (MMcf):
 
 
 
 
 
Beginning of period
20,241

 
6,802

 
5,188

End of period
23,513

 
20,241

 
6,802


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:

 
 
2011
 
2010
 
2009
Average 12-month price, net of differentials, per Mcf of natural gas
 
$
5.60

 
$
5.10

 
$
4.75

Average 12-month price, net of differentials, per barrel of oil
 
98.98

 
78.07

 
57.40


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.
 
Standardized Measure
For the year ended December 31,
 
2011
 
2010
 
2009
Future cash inflows
$
1,194,079

 
$
804,111

 
$
462,607

Future costs -
 
 
 
 
 
Production
(356,653
)
 
(277,793
)
 
(195,735
)
Development and net abandonment
(268,628
)
 
(146,870
)
 
(50,170
)
Future net inflows before income taxes
568,798

 
379,448

 
216,702

Future income taxes
(78,813
)
 
(24,719
)
 
(2,809
)
Future net cash flows
489,985

 
354,729

 
213,893

10% discount factor
(219,628
)
 
(155,813
)
 
(77,972
)
 
 
 
 
 
 
Standardized measure of discounted future net cash flows
$
270,357

 
$
198,916

 
$
135,921

 
 
 
 
 
 
 
Changes in Standardized Measure
For the year ended December 31,
 
2011
 
2010
 
2009
Standardized measure at the beginning of the period
$
198,916

 
$
135,921

 
$
86,305

 
 
 
 
 
 
Sales and transfers, net of production costs
(107,297
)
 
(72,171
)
 
(82,674
)
Net change in sales and transfer prices, net of production costs
125,518

 
126,571

 
94,435

Net change due to purchases and sales of in place reserves
1,275

 
621

 
45,009

Extensions, discoveries, and improved recovery, net of future production and development costs incurred
22,598

 
23,739

 
                 --

Changes in future development cost
(83,110
)
 
(68,960
)
 
6,194

Revisions of quantity estimates
(949
)
 
23,295

 
39,242

Accretion of discount
68,384

 
10,597

 
5,797

Net change in income taxes
(32,918
)
 
(5,170
)
 
(2,368
)
Changes in production rates, timing and other
77,940

 
24,473

 
(56,019
)
Aggregate change
71,441

 
62,995

 
49,616

 
 
 
 
 
 
Standardized measure at the end of period
$
270,357

 
$
198,916

 
$
135,921


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.