Annual report pursuant to Section 13 and 15(d)

Supplemental Oil and Natural Gas Reserve Data (unaudited)

v2.4.0.8
Supplemental Oil and Natural Gas Reserve Data (unaudited)
 12 Months Ended
Dec. 31, 2013
Oil and Gas Exploration and Production Industries Disclosures [Abstract]  
Supplemental Oil and Natural Gas Reserve Data (unaudited)
Supplemental Information on Oil and Natural Gas Operations (Unaudited)
 
Oil and Natural Gas Properties

The following table discloses certain financial data relating to the Company’s oil and natural gas activities, all of which are located in the United States.
 
For the Year Ended December 31,
Capitalized costs incurred:
2013
 
2012
 
2011
    Evaluated Properties-
 
 
 
 
 
        Beginning of period balance
$
1,497,010

 
$
1,421,640

 
$
1,316,677

        Capitalized G&A
10,014

 
12,148

 
11,205

        Property acquisition costs
10,885

 
2,075

 
—

        Exploration costs
147,164

 
22,703

 
5,473

        Development costs
36,504

 
38,444

 
88,285

        End of period balance
$
1,701,577

 
$
1,497,010

 
$
1,421,640

 
 
 
 
 
 
    Unevaluated Properties (excluded from amortization):
 

 
 

 
 

        Beginning of period balance
$
68,776

 
$
2,603

 
$
8,106

        Acquisitions
2,259

 
29,590

 
2,422

        Exploration
10,767

 
34,674

 
1,372

        Capitalized interest
4,410

 
2,109

 
573

        Transfers to evaluated
(42,990
)
 
(200
)
 
(9,870
)
        End of period balance
$
43,222

 
$
68,776

 
$
2,603

 
 
 
 
 
 
    Accumulated depreciation, depletion and amortization:
 

 
 

 
 

        Beginning of period balance
$
1,296,265

 
$
1,208,331

 
$
1,155,915

        Provision charged to expense
42,251

 
48,524

 
52,416

        Sale of mineral interests
82,096

 
39,410

 
—

        End of period balance
$
1,420,612

 
$
1,296,265

 
$
1,208,331


Unevaluated property costs primarily include lease acquisition costs incurred at federal lease sales, unevaluated drilling costs, seismic, capitalized interest and certain overhead costs related to exploration and development. These costs are directly related to the acquisition and evaluation of unproved properties and major development projects. The excluded costs and related reserves are included in the amortization base as the properties are evaluated and proved reserves are established or impairment is determined. The Company expects that the majority of these costs will be evaluated over the next three but within five years. The Company’s unevaluated property balance decreased by $25,554 to $43,222 at December 31, 2013 compared to December 31, 2012. A significant portion of this decrease relates to the transfer of drilling and completion costs from the unevaluated property base to the evaluated property base.

Subsequent to December 31, 2013 and through March 10, 2014, the Company completed six horizontal exploration wells, drilled four horizontal wells and had two in progress. Additionally, the Company drilled two vertical exploratory wells and will be evaluating the results.

Depletion per unit-of-production (BOE) amounted to $31.12, $31.56 and $26.42 for the years ended December 31, 2013, 2012, and 2011, respectively. Lease operating expense per unit-of-production (BOE) amounted to $14.00, $14.81, and $9.92 for the years ended December 31, 2013, 2012, and 2011, respectively.

Under the full-cost accounting rules of the SEC, the Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under these rules, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net of related tax effects (the full-cost ceiling amount). These rules generally require pricing based on the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month and require a write-down if the “ceiling” is exceeded. Given the volatility of oil and natural gas prices, it is reasonably possible that the Company’s estimate of discounted future net cash flows from proved oil and natural gas reserves could change in the near term. If oil and natural gas prices decline significantly, even if only for a short period of time, it is possible that write-downs of oil and natural gas properties could occur in the future. For the years ended December 31, 2013, 2012, and 2011, the Company recorded no impairment charges related to its oil and natural gas properties as a result of this calculation.  
 
Estimated Reserves

The Company’s proved oil and natural gas reserves at December 31, 2013, 2012 and 2011 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.

Changes in the estimated net quantities of 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,
 
2013
 
2012
 
2011
Proved developed and undeveloped reserves:
 
 
 
 
 
Oil (MBbls):
 
 
 
 
 
Beginning of period
10,780

 
10,075

 
8,149

Revisions to previous estimates
(2,540
)
 
(488
)
 
(110
)
Purchase of reserves in place
150

 
38

 
—

Sale of reserves in place
(3,294
)
 
(504
)
 
(30
)
Extensions and discoveries
7,713

 
2,636

 
3,062

Production
(911
)
 
(977
)
 
(996
)
End of period
11,898

 
10,780

 
10,075

Natural Gas (MMcf):
 
 
 
 
 
Beginning of period
19,753

 
35,118

 
32,957

Revisions to previous estimates
(5,351
)
 
(10,838
)
 
486

Purchase of reserves in place
317

 
115

 
—

Sale of reserves in place
(4,576
)
 
(4,404
)
 
(308
)
Extensions and discoveries
10,619

 
3,350

 
7,064

Production
(3,011
)
 
(3,588
)
 
(5,081
)
End of period
17,751

 
19,753

 
35,118

 
 
 
 
 
 
Proved developed reserves:
 
 
 
 
 
Oil (MBbls):
 
 
 
 
 
Beginning of period
4,955

 
5,069

 
4,503

End of period
5,960

 
4,955

 
5,069

Natural Gas (MMcf):
 
 
 
 
 
Beginning of period
10,680

 
11,605

 
12,715

End of period
9,059

 
10,680

 
11,605

     MBOE:
 
 
 
 
 
Beginning of period
6,735

 
7,003

 
6,622

End of period
7,470

 
6,735

 
7,003

Proved undeveloped reserves:
 
 
 
 
 
Oil (MBbls):
 
 
 
 
 
Beginning of period
5,825

 
5,006

 
3,645

End of period
5,938

 
5,825

 
5,006

Natural Gas (MMcf):
 
 
 
 
 
Beginning of period
9,073

 
23,513

 
20,241

End of period
8,692

 
9,073

 
23,513

     MBOE
 
 
 
 
 
         Beginning of period
7,337

 
8,925

 
7,019

         End of period
7,387

 
7,337

 
8,925



Total Proved Reserves: The Company ended 2013 with estimated net proved reserves of 14,857 MBOE, representing a 6% increase over 2012 year-end estimated net proved reserves of 14,072 MBOE. The increase is primarily due the Company’s development of its Permian basin, on which it drilled a total of 26 oil wells during 2013. The increase is offset by the sale of the Company’s interest in the Medusa field and due to the Company’s reclassification of certain vertical PUD locations to the horizontal probable and PUD categories.

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, and to a small extent, horizontal PDP and PUD categories.
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 increased 1% to 7,387 MBOE from 7,337 MBOE at December 31, 2013 and 2012, respectively. The Company added 5,168 MBOE to its PUDs, primarily from the continued horizontal development of its Permian Basin properties. The increase in Permian Basin PUDs was partially offset by the reclassification of 3,724 MBOE, or 51%, included in the year-end 2012 PUD reserves related to vertical PUD locations that were reclassified to the horizontal probable, and to a small extent, horizontal PDP and PUD categories. The reclassified vertical PUDs include Wolfberry PUD locations that included certain target zones that are now expected to be more efficiently developed by the Company’s multi-level horizontal drilling programs initiated in 2012. Also offsetting the Permian Basin PUD growth were the sale of 1,297 MBOE, or 18%, included in the year-end 2012 PUD reserves related to our Medusa field and the conversion of a small portion of 2012 PUD reserves to PDPs during 2013 from the drilling of vertical wells.

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 were attributable to the Company’s offshore properties in the Medusa field in the Gulf of Mexico. As previously noted, the Company sold its interest in the Medusa field during 2013.

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, 2013. 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 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:
 
 
2013
 
2012
 
2011
Average 12-month price, net of differentials, per Mcf of natural gas
 
$
5.45

 
$
4.81

 
$
5.60

Average 12-month price, net of differentials, per barrel of oil
 
$
92.16

 
94.68

 
98.98



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 $5.45 and $4.81 used in the 2013 and 2012 reserve estimates include adjustments to reflect the Btu content, transportation charges and other fees specific to the individual properties. The oil prices of $92.16 and $94.68 used in the 2013 and 2012 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,
 
2013
 
2012
 
2011
Future cash inflows
$
1,193,299

 
$
1,115,570

 
$
1,194,079

Future costs -
 
 
 
 
 
Production
(357,005
)
 
(249,329
)
 
(356,653
)
Development and net abandonment
(155,667
)
 
(273,817
)
 
(268,628
)
Future net inflows before income taxes
680,627

 
592,424

 
568,798

Future income taxes
(68,239
)
 
(55,772
)
 
(78,813
)
Future net cash flows
612,388

 
536,652

 
489,985

10% discount factor
(328,442
)
 
(305,504
)
 
(219,628
)
Standardized measure of discounted future net cash flows
$
283,946

 
$
231,148

 
$
270,357

 
 
 
 
 
 
 
Changes in Standardized Measure
For the year ended December 31,
 
2013
 
2012
 
2011
Standardized measure at the beginning of the period
$
231,148

 
$
270,357

 
$
198,916

Changes
 
 
 
 
 
Sales and transfers, net of production costs
(78,661
)
 
(84,044
)
 
(107,297
)
Net change in sales and transfer prices, net of production costs
(46,088
)
 
47,261

 
125,518

Net change due to purchases and sales of in place reserves
(145,711
)
 
(35,665
)
 
1,275

Extensions, discoveries, and improved recovery, net of future production and development costs incurred
212,431

 
53,446

 
22,598

Changes in future development cost
153,983

 
39,815

 
(83,110
)
Revisions of quantity estimates
(68,958
)
 
(77,322
)
 
(949
)
Accretion of discount
25,010

 
30,989

 
68,384

Net change in income taxes
1,751

 
13,969

 
(32,918
)
Changes in production rates, timing and other
(959
)
 
(27,658
)
 
77,940

Aggregate change
52,798

 
(39,209
)
 
71,441

Standardized measure at the end of period
$
283,946

 
$
231,148

 
$
270,357