Annual report pursuant to Section 13 and 15(d)

Supplemental Information on Oil and Natural Gas Properties (unaudited)

v3.8.0.1
Supplemental Information on Oil and Natural Gas Properties (unaudited)
 12 Months Ended
Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]  
Supplemental Information on Oil and Natural Gas Properties (unaudited)
Supplemental Information on Oil and Natural Gas Operations (Unaudited)

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,

 
2017
 
2016
 
2015
Evaluated Properties (a)
 
 
 
 
 
 
   Beginning of period balance
 
$
2,754,353

 
$
2,335,223

 
$
2,077,985

   Capitalized G&A expenses
 
11,982

 
12,222

 
10,529

   Property acquisition costs (b)
 
144,358

 
216,561

 
26,726

   Exploration costs
 
239,453

 
38,612

 
81,320

   Development costs
 
279,424

 
151,735

 
138,663

   End of period balance
 
$
3,429,570

 
$
2,754,353

 
$
2,335,223

Unevaluated Properties (a)(c)
 
 
 
 
 
 
   Beginning of period balance
 
$
668,721

 
$
132,181

 
$
142,525

   Property acquisition costs (b)
 
590,308

 
548,673

 
5,520

   Exploration costs
 
6,374

 
8,631

 
4,576

   Capitalized interest expenses
 
33,783

 
19,857

 
10,459

   Transfers to Evaluated Properties
 
(131,170
)
 
(40,621
)
 
(30,899
)
   End of period balance
 
$
1,168,016

 
$
668,721

 
$
132,181

Accumulated depreciation, depletion and amortization
 
 
 
 
 
 
   Beginning of period balance
 
$
1,947,673

 
$
1,756,018

 
$
1,478,355

   Provision charged to expense
 
115,897

 
71,330

 
69,228

   Write-down of oil and natural gas properties (a)
 
—

 
95,788

 
208,435

   Sale of mineral interests and equipment (a)
 
20,525

 
24,537

 
—

   End of period balance
 
$
2,084,095

 
$
1,947,673

 
$
1,756,018

(a)
The Company uses the full cost method of accounting for its exploration and development activities. See the Company’s accounting policy about oil and natural gas properties in Note 2 for details on the full cost method of accounting.
(b)
See Note 3 in the Footnotes to the Financial Statements for additional information about the Company’s significant acquisitions.
(c)
Unevaluated property costs primarily include lease acquisition costs, unevaluated drilling costs, seismic, capitalized interest expenses and certain overhead costs related to exploration and development. These costs are directly related to the acquisition and evaluation of unproved properties. 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 majority of these costs are primarily associated with the Company’s focus areas of its future development program and are expected to be evaluated over ten to fifteen years. The Company’s unevaluated property balance of $1,168,016 as of December 31, 2017, consisted of $121,096, $447,925, $26,648 and $572,347 of costs attributable to our Monarch, WildHorse, Ranger and Spur operating areas, respectively.

Subsequent to December 31, 2017, and through February 23, 2018, the Company drilled eight gross (6.0 net) horizontal wells and completed five gross (3.0 net) horizontal wells and had three gross (3.0 net) horizontal wells awaiting completion.
 
Depletion per unit-of-production, on a BOE basis, amounted to $13.82, $12.81 and $19.74 for the years ended December 31, 2017,  2016, and 2015, respectively. Lease operating expenses per unit-of-production, on a BOE basis, amounted to $5.96, $6.88, and $7.71 for the years ended December 31, 2017,  2016, and 2015, respectively.

Estimated Reserves

The Company’s proved oil and natural gas reserves at December 31, 2017, 2016 and 2015 have been estimated by DeGolyer and MacNaughton, the Company’s current 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.

The following tables disclose changes in the estimated net quantities of oil and natural gas reserves, all of which are located onshore within the continental United States:
໿

 
For the Year Ended December 31,
Proved developed and undeveloped reserves:
 
2017
 
2016
 
2015
Oil (MBbls):
 
 
 
 
 
 
Beginning of period
 
71,145

 
43,348

 
25,733

Revisions to previous estimates
 
(5,171
)
 
(5,738
)
 
(1,632
)
Purchase of reserves in place
 
8,388

 
25,054

 
2,932

Sale of reserves in place
 
—

 
(1,718
)
 
(23
)
Extensions and discoveries
 
39,267

 
14,479

 
19,127

Production
 
(6,557
)
 
(4,280
)
 
(2,789
)
End of period
 
107,072

 
71,145

 
43,348

Natural Gas (MMcf):
 
 
 
 
 
 
Beginning of period
 
122,611

 
65,537

 
42,548

Revisions to previous estimates
 
6,336

 
13,929

 
4,870

Purchase of reserves in place
 
12,711

 
36,474

 
2,915

Sale of reserves in place
 
—

 
(2,765
)
 
(105
)
Extensions and discoveries
 
48,648

 
17,194

 
19,621

Production
 
(10,896
)
 
(7,758
)
 
(4,312
)
End of period
 
179,410

 
122,611

 
65,537


 
For the Year Ended December 31,
Proved developed reserves:
 
2017
 
2016
 
2015
Oil (MBbls):
 
 
 
 
 
 
Beginning of period
 
32,920

 
22,257

 
14,006

End of period
 
51,920

 
32,920

 
22,257

Natural gas (MMcf):
 
 
 
 
 
 
Beginning of period
 
61,871

 
38,157

 
25,171

End of period
 
104,389

 
61,871

 
38,157

MBOE:
 
 
 
 
 
 
Beginning of period
 
43,232

 
28,617

 
18,201

End of period
 
69,318

 
43,232

 
28,617

Proved undeveloped reserves:
 
 
 
 
 
 
Oil (MBbls):
 
 
 
 
 
 
Beginning of period
 
38,225

 
21,091

 
11,727

End of period
 
55,152

 
38,225

 
21,091

Natural gas (MMcf):
 
 
 
 
 
 
Beginning of period
 
60,740

 
27,380

 
17,377

End of period
 
75,021

 
60,740

 
27,380

MBOE:
 
 
 
 
 
 
Beginning of period
 
48,348

 
25,654

 
14,623

End of period
 
67,656

 
48,348

 
25,654



Total Proved Reserves: The Company ended 2017 with estimated net proved reserves of 136,974 MBOE, representing a 50% increase over 2016 year-end estimated net proved reserves of 91,580 MBOE. The Company added 57,881 MBOE primarily from the Company’s acquisition and development efforts in the Permian Basin, where it drilled a total of 49 gross (38.2 net) wells. This increase was primarily offset by 2017 production and revisions. The decrease from revisions was primarily due to the removal of 13 proved undeveloped locations as a result of a change in the Company’s development and drilling plans within its operating areas and the removal of certain proved developed vertical well locations..

The Company ended 2016 with estimated net proved reserves of 91,580 MBOE, representing a 69% increase over 2015 year-end estimated net proved reserves of 54,271 MBOE. The Company added 48,477 MBOE primarily from the Company’s acquisition and development efforts in the Permian Basin, where it drilled a total of 29 gross (20.9 net) wells. This increase was primarily offset by 11,168 MBOE related to divestitures, 2016 production and revisions primarily due to pricing.

The Company ended 2015 with estimated net proved reserves of 54,271 MBOE, representing a 65% increase over 2014 year-end estimated net proved reserves of 32,824 MBOE. The increase was primarily due the Company’s development of its properties in the Permian Basin, where it drilled a total of 36 gross (27.1 net) wells, and acquisitions made during 2015. This increase was primarily offset by 2015 production and revisions.

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 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 40% to 67,656 MBOE from 48,348 MBOE at December 31, 2017 and 2016, respectively. The Company added 3,267 MBOE to its PUDs, primarily from acquisitions in the Permian Basin, and added 30,198 MBOE from the continued horizontal development of its Permian Basin properties. The increase in the Permian Basin PUDs was partially offset by 5,876 MBOE of revisions primarily due to the removal of 13 PUD locations as a result of a change in the Company’s development and drilling plans within its operating areas and downward revisions to its current PUD locations. In addition, the increase in Permian Basin PUDs was offset by the reclassification of 8,281 MBOE, or 17%, included in the year-end 2016 PUDs, to PDPs as a result of our horizontal development of Permian Basin properties at a total cost of approximately $57,019, net.

The Company’s PUDs increased 88% to 48,348 MBOE from 25,654 MBOE at December 31, 2016 and 2015, respectively. The Company added 17,482 MBOE to its PUDs, primarily from acquisitions in the Permian Basin, net of divestitures, and added 12,035 MBOE from the continued horizontal development of its Permian Basin properties, net of revisions. The increase in Permian Basin PUDs was partially offset by the reclassification of 6,823 MBOE, or 27%, included in the year-end 2015 PUDs, to PDPs as a result of our horizontal development of Permian Basin properties at a total cost of approximately $43,415, net.

The Company’s PUDs increased 75% to 25,654 MBOE from 14,623 MBOE at December 31, 2015 and 2014, respectively. The Company added 13,774 MBOE to its PUDs, net of revisions, primarily from the continued horizontal development of its Permian Basin properties and from acquisitions in the Permian Basin. The increase in Permian Basin PUDs was partially offset by the reclassification of 2,742 MBOE, or 19%, included in the year-end 2014 PUDs, to PDPs as a result of our horizontal development of Permian Basin properties at a total cost of approximately $55,933, net.

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, 2017. 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 the preceding 12-months’ average price based on closing prices on the first day of each month. The following table summarizes the average 12-month oil and natural gas prices net of differentials for the respective periods:
໿

 
2017
 
2016
 
2015
Average 12-month price, net of differentials, per Mcf of natural gas (a)
 
$
3.47

 
$
2.71

 
$
2.73

Average 12-month price, net of differentials, per barrel of oil (b)
 
$
49.48

 
$
40.03

 
$
47.25

(a)
Includes a high Btu content of separator natural gas and adjustments to reflect the Btu content, transportation charges and other fees specific to the individual properties.
(b)
Includes adjustments to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality.

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.
໿

 
Standardized Measure

 
For the Year Ended December 31,

 
2017
 
2016
 
2015
Future cash inflows
 
$
5,920,328

 
$
3,180,005

 
$
2,227,463

Future costs
 
 
 
 
 
 
Production
 
(1,692,871
)
 
(974,667
)
 
(827,555
)
Development and net abandonment
 
(680,948
)
 
(384,117
)
 
(239,100
)
Future net inflows before income taxes
 
3,546,509

 
1,821,221

 
1,160,808

Future income taxes (a)
 
(166,985
)
 
(1,602
)
 
—

Future net cash flows
 
3,379,524

 
1,819,619

 
1,160,808

10% discount factor
 
(1,822,842
)
 
(1,009,787
)
 
(589,918
)
Standardized measure of discounted future net cash flows
 
$
1,556,682

 
$
809,832

 
$
570,890

໿
(a)
As of December 31, 2017, 2016, and 2015 the Company’s statutory tax rate applied was 21%, 35%, and 35%, respectively.


 
Changes in Standardized Measure

 
For the Year Ended December 31,

 
2017
 
2016
 
2015
Standardized measure at the beginning of the period
 
$
809,832

 
$
570,890

 
$
579,542

Sales and transfers, net of production costs
 
(294,172
)
 
(150,628
)
 
(110,476
)
Net change in sales and transfer prices, net of production costs
 
176,234

 
(103,136
)
 
(286,660
)
Net change due to purchases and sales of in place reserves
 
129,454

 
260,859

 
37,616

Extensions, discoveries, and improved recovery, net of future production and development costs incurred
 
635,000

 
180,228

 
184,469

Changes in future development cost
 
36,983

 
82,320

 
108,216

Revisions of quantity estimates
 
(79,325
)
 
(35,938
)
 
(12,625
)
Accretion of discount
 
80,983

 
57,091

 
62,968

Net change in income taxes
 
(20,073
)
 
16

 
35,407

Changes in production rates, timing and other
 
81,766

 
(51,870
)
 
(27,567
)
Aggregate change
 
746,850

 
238,942

 
(8,652
)
Standardized measure at the end of period
 
$
1,556,682

 
$
809,832

 
$
570,890