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Supplementary Information on Oil and Gas Operations—Unaudited
 12 Months Ended
Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]  
Supplementary Information of Oil and Gas Operations—Unaudited
Supplementary Information on Oil and Gas Operations—Unaudited
The following tables disclose certain financial data relative to the Company’s oil and gas producing activities, which are located onshore and offshore in the continental United States:
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
(amounts in thousands)
 
For the Year-Ended December 31,
 
2014
 
2013
 
2012
Acquisition costs:
 
 
 
 
 
     Proved (1)
$
3,064

 
$
177,880

 
$
352

     Unproved (1)
39,164

 
35,008

 
15,677

Divestitures—unproved (2)
(3,298
)
 
(487
)
 
(8,889
)
Exploration costs:
 
 
 
 
 
     Proved
67,297

 
34,344

 
72,361

     Unproved
13,515

 
20,112

 
18,033

Development costs
55,722

 
41,328

 
18,740

Capitalized general and administrative and interest costs
22,121

 
19,911

 
18,961

Total costs incurred
$
197,585

 
$
328,096

 
$
135,235



 
For the Year-Ended December 31,
  
2014
 
2013
 
2012
Accumulated depreciation, depletion and amortization (DD&A)
 
 
 
 
 
   Balance, beginning of year
$
(1,553,044
)
 
$
(1,472,244
)
 
$
(1,265,603
)
   Provision for DD&A
(86,406
)
 
(69,357
)
 
(59,496
)
   Ceiling test writedown
—

 
—

 
(137,100
)
   Sale of proved properties and other (3)
(8,610
)
 
(11,443
)
 
(10,045
)
Balance, end of year
$
(1,648,060
)
 
$
(1,553,044
)
 
$
(1,472,244
)
 
 
 
 
 
 
DD&A per Mcfe
$
1.99

 
$
1.82

 
$
1.75


(1)
During 2014, the Company entered into a joint venture in Louisiana for an aggregate purchase price of $24 million for an approximate 30,000 acre leasehold position. During 2013, the Company closed on the Gulf of Mexico Acquisition for an aggregate cash purchase price of $188.8 million (see Note 2). Additionally, the Company acquired 13,500 net unevaluated acres in Oklahoma targeting the Woodford Shale in 2013.

(2)
During 2012, the Company sold an additional portion of its Mississippian Lime acreage for $6.1 million.

(3)
During 2014, the Company sold its Eagle Ford assets for net proceeds of approximately $9.8 million. During 2013, the Company sold 50% of its saltwater disposal systems and related surface assets in the Woodford for net proceeds of approximately $10.4 million and its non-operated Wyoming assets for a cash purchase price of $1.0 million. During 2012, the Company sold its non-operated Arkansas assets for a net cash purchase price of $8.5 million.
At December 31, 2014 and 2013, unevaluated oil and gas properties totaled $109.1 million and $98.4 million, respectively, and were not subject to depletion. Unevaluated costs at December 31, 2014 included $16.8 million of costs related to 16 exploratory wells in progress at year-end. These costs are expected to be transferred to evaluated oil and gas properties during 2015 upon the completion of drilling. At December 31, 2013, unevaluated costs included $11.3 million related to 19 exploratory wells in progress. All of these costs were transferred to evaluated oil and gas properties during 2014. The Company capitalized $10.0 million, $6.6 million and $7.0 million of interest during 2014, 2013 and 2012, respectively. Of the total unevaluated oil and gas property costs of $109.1 million at December 31, 2014, $56.3 million, or 52%, was incurred in 2014, $21.1 million, or 19%, was incurred in 2013 and $31.7 million, or 29%, was incurred in prior years. The Company expects that the majority of the unevaluated costs at December 31, 2014 will be evaluated within the next 3 years, including $32.5 million that the Company expects to be evaluated during 2015.
Oil and Gas Reserve Information
The Company’s net proved oil and gas reserves at December 31, 2014 have been estimated by independent petroleum engineers in accordance with guidelines established by the SEC using a historical 12-month average pricing assumption.
The estimates of proved oil and gas reserves constitute those quantities of oil, gas,and natural gas liquids, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. However, there are numerous uncertainties inherent in estimating quantities of proved reserves and in providing the future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact. In addition, the present values should not be construed as the current market value of the Company’s oil and gas properties or the cost that would be incurred to obtain equivalent reserves.


The following table sets forth an analysis of the Company’s estimated quantities of net proved and proved developed oil (including condensate), gas and natural gas liquid reserves, all located onshore and offshore in the continental United States:
 
Oil
in
MBbls
 
NGL
in
MMcfe
 
Natural Gas
in
MMcf
 
Total
Reserves
in MMcfe
Proved reserves as of December 31, 2011
1,395

 
15,111

 
241,926

 
265,407

  Revisions of previous estimates (1)
195

 
(1,952
)
 
(56,780
)
 
(57,561
)
  Extensions, discoveries and other additions
647

 
14,572

 
46,390

 
64,844

  Sale of reserves in place
(81
)
 
—

 
(15,806
)
 
(16,292
)
  Production
(521
)
 
(3,365
)
 
(27,466
)
 
(33,957
)
Proved reserves as of December 31, 2012
1,635

 
24,366

 
188,264

 
222,441

  Revisions of previous estimates (1)
(156
)
 
804

 
38,383

 
38,247

  Extensions, discoveries and other additions
434

 
6,099

 
30,429

 
39,132

  Purchase of producing properties
1,833

 
1,915

 
22,274

 
35,187

  Sale of reserves in place
(34
)
 
—

 
(15
)
 
(218
)
  Production
(681
)
 
(4,754
)
 
(29,226
)
 
(38,066
)
Proved reserves as of December 31, 2013
3,031

 
28,430

 
250,109

 
296,723

  Revisions of previous estimates
(37
)
 
2,894

 
9,976

 
12,650

  Extensions, discoveries and other additions
475

 
49,990

 
82,364

 
135,205

  Purchase of producing properties
—

 
—

 
—

 
—

  Sale of reserves in place
(229
)
 
(334
)
 
(2,396
)
 
(4,105
)
  Production
(803
)
 
(7,482
)
 
(31,028
)
 
(43,325
)
Proved reserves as of December 31, 2014
2,437

 
73,498

 
309,025

 
397,148

 
 
 
 
 
 
 
 
Proved developed reserves
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  As of December 31, 2012
1,225

 
20,608

 
140,307

 
168,265

 
 
 
 
 
 
 
 
  As of December 31, 2013
2,709

 
23,173

 
163,728

 
203,152

 
 
 
 
 
 
 
 
  As of December 31, 2014
2,089

 
42,584

 
182,567

 
237,688

 
 
 
 
 
 
 
 
Proved undeveloped reserves
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  As of December 31, 2012 (1)
410

 
3,758

 
47,957

 
54,176

 
 
 
 
 
 
 
 
  As of December 31, 2013 (1)
322

 
5,257

 
86,381

 
93,571

 
 
 
 
 
 
 
 
  As of December 31, 2014
348

 
30,914

 
126,458

 
159,460


(1) The table above includes certain adjustments to previously disclosed estimated proved reserves as of December 31, 2013 and 2012. Specifically, as of December 31, 2014, the Company determined that it should have reflected additional downward revisions to certain of its proved undeveloped reserves totaling 5,088 MMcfe and 5,817 MMcfe as of December 31, 2013 and 2012, respectively. The table above reflects such adjustments of previous estimates for the years ended December 31, 2013 and 2012, respectively. The above adjustments had no material impact on the Company's financial statements for the years ended December 31, 2013 and 2012.
Year Ended December 31, 2014    
During 2014, the Company’s estimated proved reserves increased by 34%. Extensions, discoveries and other additions of 135 Bcfe were primarily due to successful drilling programs in the Company's Oklahoma and East Texas fields and its Thunder Bayou discovery. The Company added approximately 72 Bcfe of proved reserves in Oklahoma, 46 Bcfe in Texas and 15 Bcfe in the Gulf Coast. Overall, the Company had a 91% drilling success rate during 2014 on 58 gross wells drilled.
Year Ended December 31, 2013 
Extensions, discoveries and other additions were primarily due to the success of the Company's Oklahoma, Texas and Gulf Coast drilling programs.  The Company added approximately 23 Bcfe of proved reserves in Oklahoma, 5 Bcfe in the Gulf Coast and 10 Bcfe in Texas. Revisions of previous estimates were primarily a result of the increase in the historical 12-month average price per Mcf of natural gas used to calculate estimated proved reserves, which was $3.11 per Mcf at December 31, 2013 as compared to $2.20 per Mcf at December 31, 2012. The 35 Bcfe added through purchase of producing properties relates to the Company's Gulf of Mexico Acquisition (See Note 2).
Year Ended December 31, 2012
Extensions, discoveries and other additions were primarily due to the success the Company's Oklahoma, Texas and Gulf Coast drilling programs. The Company added approximately 27 Bcfe of proved reserves in Oklahoma, 9 Bcfe from the La Cantera discovery in the Gulf Coast and 27 Bcfe in the Carthage Field in Texas from horizontal drilling in the Cotton Valley. Revisions of previous estimates were primarily a result of the significant decrease in the historical 12-month average price per Mcf of natural gas used to calculate estimated proved reserves, which was $2.20 per Mcf at December 31, 2012 as compared to $3.34 per Mcf at December 31, 2011. Sale of reserves in place primarily related to the divestiture of the Company's non-operated Arkansas assets.
The following tables (amounts in thousands) present the standardized measure of future net cash flows related to proved oil and gas reserves together with changes therein, as defined by ASC Topic 932. Future production and development costs are based on current costs with no escalations. Estimated future cash flows have been discounted to their present values based on a 10% annual discount rate.
Standardized Measure
 
 
December 31,
 
2014
 
2013 (1)
 
2012 (1)
Future cash flows
$
1,711,404

 
$
1,243,627

 
$
728,878

Future production costs
(372,690
)
 
(295,666
)
 
(215,195
)
Future development costs
(244,784
)
 
(185,188
)
 
(110,825
)
Future income taxes
(121,192
)
 
(37,404
)
 
(9,642
)
Future net cash flows
972,738

 
725,369

 
393,216

10% annual discount
(424,176
)
 
(274,189
)
 
(162,393
)
Standardized measure of discounted future net cash flows
$
548,562

 
$
451,180

 
$
230,823


Changes in Standardized Measure
 
Year Ended December 31,
 
2014
 
2013 (1)
 
2012 (1)
Standardized measure at beginning of year
$
451,180

 
$
230,823

 
$
303,881

 
 
 
 
 
 
Sales and transfers of oil and gas produced, net of production costs
(173,540
)
 
(134,184
)
 
(92,562
)
Changes in price, net of future production costs
37,204

 
55,601

 
(140,230
)
Extensions and discoveries, net of future production and development costs
237,290

 
70,181

 
104,066

Changes in estimated future development costs, net of development costs incurred during this period
11,094

 
(25,389
)
 
77,188

Revisions of quantity estimates
25,591

 
58,508

 
(62,159
)
Accretion of discount
47,130

 
23,776

 
34,137

Net change in income taxes
(32,034
)
 
(13,182
)
 
30,559

Purchase of reserves in place
—

 
191,964

 
—

Sale of reserves in place
(7,240
)
 
(411
)
 
(8,186
)
Changes in production rates (timing) and other
(48,113
)
 
(6,507
)
 
(15,871
)
Net increase (decrease) in standardized measure
97,382

 
220,357

 
(73,058
)
Standardized measure at end of year
$
548,562

 
$
451,180

 
$
230,823


(1) The table above includes certain adjustments to previously disclosed estimated proved reserves as of December 31, 2013 and 2012. Specifically, as of December 31, 2014, the Company determined that it should have reflected additional downward revisions to certain of its proved undeveloped reserves totaling 5,088 MMcfe and 5,817 MMcfe as of December 31, 2013 and 2012, respectively. The table above reflects such adjustments of previous estimates for the years ended December 31, 2013 and 2012, respectively. The above adjustments had no material impact on the Company's financial statements for the years ended December 31, 2013 and 2012.
The historical twelve-month average prices of oil, gas and natural gas liquids used in determining standardized measure were:
 
2014
 
2013
 
2012
Oil, $/Bbl
$96.45
 
$106.19
 
$102.81
Ngls, $/Mcfe
4.11

 
5.10

 
6.07

Natural Gas, $/Mcf
3.80

 
3.11

 
2.20