Annual report pursuant to Section 13 and 15(d)

Supplemental Oil and Natural Gas Reserve Data (unaudited)

v2.4.0.6
Supplemental Oil and Natural Gas Reserve Data (unaudited)
12 Months Ended
Dec. 31, 2012
Oil and Gas Exploration and Production Industries Disclosures [Abstract]  
Supplemental Oil and Natural Gas Reserve Data (unaudited)
Supplemental Crude Oil and Natural Gas Reserve Data (unaudited))
 
The Company's proved oil and natural gas reserves at December 31, 2012, 2011 and 2010 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 deemed 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,
 
2012
 
2011
 
2010
Proved developed and undeveloped reserves:
 
 
 
 
 
Crude Oil (MBbls):
 
 
 
 
 
Beginning of period
10,075

 
8,149

 
6,479

Revisions to previous estimates
(488
)
 
(110
)
 
423

Change in ownership

 

 

Purchase of reserves in place
38

 

 

Sale of reserves in place
(504
)
 
(30
)
 

Extensions and discoveries
2,636

 
3,062

 
2,106

Production
(977
)
 
(996
)
 
(859
)
End of period
10,780

 
10,075

 
8,149

Natural Gas (MMcf):
 
 
 
 
 
Beginning of period
35,118

 
32,957

 
19,103

Revisions to previous estimates
(10,838
)
 
486

 
354

Change in ownership

 

 

Purchase of reserves in place
115

 

 

Sale of reserves in place
(4,404
)
 
(308
)
 

Extensions and discoveries
3,350

 
7,064

 
18,392

Production
(3,588
)
 
(5,081
)
 
(4,892
)
End of period
19,753

 
35,118

 
32,957

 
 
 
 
 
 
Proved developed reserves:
 
 
 
 
 
Crude Oil (MBbls):
 
 
 
 
 
Beginning of period
5,069

 
4,503

 
4,346

End of period
4,955

 
5,069

 
4,503

Natural Gas (MMcf):
 
 
 
 
 
Beginning of period
11,605

 
12,715

 
12,301

End of period
10,680

 
11,605

 
12,715

     MBoe:
 
 
 
 
 
Beginning of period
7,003

 
6,622

 
6,396

End of period
6,735

 
7,003

 
6,622

Proved undeveloped reserves:
 
 
 
 
 
Crude Oil (MBbls):
 
 
 
 
 
Beginning of period
5,006

 
3,645

 
2,133

End of period
5,825

 
5,006

 
3,645

Natural Gas (MMcf):
 
 
 
 
 
Beginning of period
23,513

 
20,241

 
6,802

End of period
9,073

 
23,513

 
20,241

     MBoe
 
 
 
 
 
         Beginning of period
8,925

 
7,019

 
3,267

         End of period
7,337

 
8,925

 
7,019



Total Proved Reserves: The Company ended 2012 with estimated net proved reserves of 14,072 MBoe, representing a 12% decrease over 2011 year-end estimated net proved reserves of 15,928 MBoe. The decrease is primarily due to the sale of the Company's interest in the Habanero field and the downward revision of our Haynesville Shale undeveloped reserves at year-end 2012, which were reduced due to low natural gas prices. These decreases were partially offset by the Company’s development of a portion of its Permian basin, on which it drilled a total of 27 oil wells during 2012.

Extrapolation of performance history and material balance estimates were utilized by the Company's independent petroleum and geological firm to project future recoverable reserves for the producing properties where sufficient history existed to suggest performance trends and where these methods were applicable to the subject reservoirs.  The projections for the remaining producing properties were necessarily based on volumetric calculations and/or analogy to nearby producing completions.  Reserves assigned to nonproducing zones and undeveloped locations were projected on the basis of volumetric calculations and analogy to nearby production.
Proved Undeveloped Reserves: 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. The Company's PUDs decreased 18% to 7,337 MBoe from 8,925 MBoe at December 31, 2012 and 2011, respectively. Additions during the year added 2,344 MBoe to the Company's PUDs, offset by (1) 557 MBoe primarily comprised of transfers to PDPs as a result of our development program, (2) 1,148 MBoe related to the sale of Habanero, and (3) 2,227 MBoe related to reductions in our PUD reserves, primarily related to the Haynesville Shale, by amounts no longer deemed to be economic PUDs at year-end. Of the Company's year-end 2011 PUD reserves, 6% were converted to proved developed producing reserves by year end 2012, at a total cost of approximately $19 million, net.

Of the Company's 2012 PUDs, 1,297 MBoe are attributable to the Company’s offshore properties in the Medusa fields in the Gulf of Mexico. The Company's deepwater PUDs have been classified as PUDs for more than five years, though we expect to develop these PUDs within the next two years. Callon's decision to classify these reserves as PUDs was primarily based on (1) its ongoing development activities in the area, (2) its historical record of completing development of comparable long-term projects, (3) the amount of time which Callon have maintained the leases or booked reserves without significant development activities and (4) the extent to which Callon have followed previously adopted development plans. Callon's discussions with the field's operator have resulted in the modification of certain development plans for Medusa to drill or sidetrack PUDs within a shorter period of time than originally estimated. The Company expects to develop its Medusa PUDs by drilling a new well by the first quarter of 2014. The Company did not convert any offshore, deepwater PUDs to proved developed in 2012.

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, 2012. 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. Prices 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:
 
 
2012
 
2011
 
2010
Average 12-month price, net of differentials, per Mcf of natural gas
 
$
4.81

 
$
5.60

 
$
5.10

Average 12-month price, net of differentials, per barrel of crude oil
 
94.68

 
98.98

 
78.07



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 $4.81 and $5.60 used in the 2012 and 2011 reserve estimates include adjustments to reflect the Btu content, transportation charges and other fees specific to the individual properties. The projected oil prices of $94.68 and $98.98 used in the 2012 and 2011 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,
 
2012
 
2011
 
2010
Future cash inflows
$
1,115,570

 
$
1,194,079

 
$
804,111

Future costs -
 
 
 
 
 
Production
(249,329
)
 
(356,653
)
 
(277,793
)
Development and net abandonment
(273,817
)
 
(268,628
)
 
(146,870
)
Future net inflows before income taxes
592,424

 
568,798

 
379,448

Future income taxes
(55,772
)
 
(78,813
)
 
(24,719
)
Future net cash flows
536,652

 
489,985

 
354,729

10% discount factor
(305,504
)
 
(219,628
)
 
(155,813
)
Standardized measure of discounted future net cash flows
$
231,148

 
$
270,357

 
$
198,916

 
 
 
 
 
 
 
Changes in Standardized Measure
For the year ended December 31,
 
2012
 
2011
 
2010
Standardized measure at the beginning of the period
$
270,357

 
$
198,916

 
$
135,921

Sales and transfers, net of production costs
(84,044
)
 
(107,297
)
 
(72,171
)
Net change in sales and transfer prices, net of production costs
47,261

 
125,518

 
126,571

Net change due to purchases and sales of in place reserves
(35,665
)
 
1,275

 
621

Extensions, discoveries, and improved recovery, net of future production and development costs incurred
53,446

 
22,598

 
23,739

Changes in future development cost
39,815

 
(83,110
)
 
(68,960
)
Revisions of quantity estimates
(77,322
)
 
(949
)
 
23,295

Accretion of discount
30,989

 
68,384

 
10,597

Net change in income taxes
13,969

 
(32,918
)
 
(5,170
)
Changes in production rates, timing and other
(27,658
)
 
77,940

 
24,473

Aggregate change
(39,209
)
 
71,441

 
62,995

Standardized measure at the end of period
$
231,148

 
$
270,357

 
$
198,916