Annual report pursuant to Section 13 and 15(d)

Supplemental Information on Oil and Natural Gas Properties (Unaudited)

v3.10.0.1
Supplemental Information on Oil and Natural Gas Properties (Unaudited)
 12 Months Ended
Dec. 31, 2018
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)

Estimated Reserves

The Company’s proved oil and natural gas reserves at December 31, 2018, 2017 and 2016 have been estimated by DeGolyer and MacNaughton, the Company’s current independent petroleum and geological firm (the “Reserve Engineering Firm”). 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.

Extrapolation of performance history and material balance estimates were utilized by the Company’s Reserve Engineering 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.

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:
 
2018
 
2017
 
2016
Oil (MBbls):
 
 
 
 
 
 
Beginning of period
 
107,072

 
71,145

 
43,348

Purchase of reserves in place
 
30,756

 
8,388

 
25,054

Sale of reserves in place
 
—

 
—

 
(1,718
)
Extensions and discoveries
 
67,763

 
39,267

 
14,479

Revisions to previous estimates
 
(8,982
)
 
(1,548
)
 
(4,544
)
Reclassifications due to changes in development plan
 
(7,069
)
 
(3,623
)
 
(1,194
)
Production
 
(9,443
)
 
(6,557
)
 
(4,280
)
End of period
 
180,097

 
107,072

 
71,145

Natural Gas (MMcf):
 
 
 
 
 
 
Beginning of period
 
179,410

 
122,611

 
65,537

Purchase of reserves in place
 
53,563

 
12,711

 
36,474

Sale of reserves in place
 
—

 
—

 
(2,765
)
Extensions and discoveries
 
103,149

 
48,648

 
17,194

Revisions to previous estimates
 
41,767

 
18,121

 
16,842

Reclassifications due to changes in development plan
 
(11,976
)
 
(11,785
)
 
(2,913
)
Production
 
(15,447
)
 
(10,896
)
 
(7,758
)
End of period
 
350,466

 
179,410

 
122,611

Total (MBOE):
 
 
 
 
 
 
Beginning of period
 
136,974

 
91,580

 
54,271

Purchase of reserves in place
 
39,683

 
10,507

 
31,133

Sale of reserves in place
 
—

 
—

 
(2,179
)
Extensions and discoveries
 
84,955

 
47,375

 
17,345

Revisions to previous estimates
 
(2,021
)
 
1,472

 
(1,737
)
Reclassifications due to changes in development plan
 
(9,065
)
 
(5,587
)
 
(1,680
)
Production
 
(12,018
)
 
(8,373
)
 
(5,573
)
End of period
 
238,508

 
136,974

 
91,580


 
 
For the Year Ended December 31,
Proved developed reserves:
 
2018
 
2017
 
2016
Oil (MBbls):
 
 
 
 
 
 
Beginning of period
 
51,920

 
32,920

 
22,257

End of period
 
92,202

 
51,920

 
32,920

Natural gas (MMcf):
 
 
 
 
 
 
Beginning of period
 
104,389

 
61,871

 
38,157

End of period
 
218,417

 
104,389

 
61,871

MBOE:
 
 
 
 
 
 
Beginning of period
 
69,318

 
43,232

 
28,617

End of period
 
128,605

 
69,318

 
43,232

Proved undeveloped reserves:
 
 
 
 
 
 
Oil (MBbls):
 
 
 
 
 
 
Beginning of period
 
55,152

 
38,225

 
21,091

End of period
 
87,895

 
55,152

 
38,225

Natural gas (MMcf):
 
 
 
 
 
 
Beginning of period
 
75,021

 
60,740

 
27,380

End of period
 
132,049

 
75,021

 
60,740

MBOE:
 
 
 
 
 
 
Beginning of period
 
67,656

 
48,348

 
25,654

End of period
 
109,903

 
67,656

 
48,348

Total proved reserves:
 
 
 
 
 
 
  Oil (MBbls):
 
 
 
 
 
 
Beginning of period
 
107,072

 
71,145

 
43,348

End of period
 
180,097

 
107,072

 
71,145

Natural gas (MMcf):
 
 
 
 
 
 
Beginning of period
 
179,410

 
122,611

 
65,537

End of period
 
350,466

 
179,410

 
122,611

MBOE:
 
 
 
 
 
 
Beginning of period
 
136,974

 
91,580

 
54,271

End of period
 
238,508

 
136,974

 
91,580



Total Proved Reserves

The Company ended 2018 with estimated net proved reserves of 238,508 MBOE, representing a 74% increase over 2017 year-end estimated net proved reserves of 136,974 MBOE. The Company added 124,638 MBOE primarily from the Delaware Asset Acquisition completed third quarter of 2018 and development efforts in the Permian Basin, where it drilled a total of 70 gross (57.5 net) wells. This increase was offset by 2018 production, negative revisions of previous estimates of 2,021 MBOE primarily related to technical revisions of proved undeveloped reserves, and reclassifications of proved undeveloped reserves of 9,065 MBOE from 19 PUD locations primarily due to acreage trades and changes in our development plan, including larger pad development concepts and co-development of zones. These changes resulted in the anticipated drilling of PUD locations being moved beyond five years from initial booking.

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, revisions of previous estimates, and reclassifications of PUD locations from our development and drilling plan. The Company reclassified 13 PUD 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, revisions primarily due to pricing, and reclassifications of 4 PUD locations as a result of a change in the Company’s development and dilling plans within its operating areas.

Capitalized Costs

Capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows:
 
 
As of December 31,
 
 
2018
 
2017
Oil and natural gas properties:
 
 
 
 
   Evaluated properties
 
$
4,585,020

 
$
3,429,570

   Unevaluated properties
 
1,404,513

 
1,168,016

Total oil and natural gas properties
 
5,989,533

 
4,597,586

   Accumulated depreciation, depletion, amortization and impairment
 
(2,270,675
)
 
(2,084,095
)
Total oil and natural gas properties capitalized
 
$
3,718,858

 
$
2,513,491



Costs Incurred

Costs incurred in oil and natural gas property acquisitions, exploration and development activities are as follows:
 
 
For the Year Ended December 31,
 
 
2018
 
2017
 
2016
Acquisition costs:
 
 
 
 
 
 
   Evaluated properties
 
$
347,305

 
$
156,340

 
$
228,832

   Unevaluated properties
 
466,816

 
499,295

 
536,540

Development costs
 
259,410

 
148,254

 
111,065

Exploration costs
 
323,458

 
239,453

 
38,612

   Total costs incurred
 
$
1,396,989

 
$
1,043,342

 
$
915,049



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, 2018. 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:
໿
 
 
2018
 
2017
 
2016
Average 12-month price, net of differentials, per barrel of oil (a)
 
$
58.40

 
$
49.48

 
$
40.03

Average 12-month price, net of differentials, per Mcf of natural gas (b)
 
$
3.64

 
$
3.47

 
$
2.71


(a)
Includes adjustments to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality.
(b)
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.

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,
 
 
2018
 
2017
 
2016
Future cash inflows
 
$
11,794,080

 
$
5,920,328

 
$
3,180,005

Future costs
 
 
 
 
 
 
Production
 
(2,923,959
)
 
(1,692,871
)
 
(974,667
)
Development and net abandonment
 
(1,429,787
)
 
(680,948
)
 
(384,117
)
Future net inflows before income taxes
 
7,440,334

 
3,546,509

 
1,821,221

Future income taxes (a)
 
(782,470
)
 
(166,985
)
 
(1,602
)
Future net cash flows
 
6,657,864

 
3,379,524

 
1,819,619

10% discount factor
 
(3,716,571
)
 
(1,822,842
)
 
(1,009,787
)
Standardized measure of discounted future net cash flows
 
$
2,941,293

 
$
1,556,682

 
$
809,832

໿
(a)
As of December 31, 2018, 2017, and 2016 the Company’s statutory tax rate applied was 21%, 21%, and 35%, respectively.


 
Changes in Standardized Measure

 
For the Year Ended December 31,

 
2018
 
2017
 
2016
Standardized measure at the beginning of the period
 
$
1,556,682

 
$
809,832

 
$
570,890

Sales and transfers, net of production costs
 
(481,306
)
 
(294,172
)
 
(150,628
)
Net change in sales and transfer prices, net of production costs
 
222,802

 
176,234

 
(103,136
)
Net change due to purchases and sales of in place reserves
 
554,697

 
129,454

 
260,859

Extensions, discoveries, and improved recovery, net of future production and development costs incurred
 
1,093,773

 
635,000

 
180,228

Changes in future development cost
 
40,483

 
36,983

 
82,320

Revisions of quantity estimates
 
(167,096
)
 
(79,325
)
 
(35,938
)
Accretion of discount
 
157,676

 
80,983

 
57,091

Net change in income taxes
 
(187,841
)
 
(20,073
)
 
16

Changes in production rates, timing and other
 
151,423

 
81,766

 
(51,870
)
Aggregate change
 
1,384,611

 
746,850

 
238,942

Standardized measure at the end of period
 
$
2,941,293

 
$
1,556,682

 
$
809,832