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(Mark One)
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x
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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Delaware
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46-4314192
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(State or other jurisdiction
of incorporation or organization)
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(I.R.S. Employer
Identification No.)
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303 Colorado Street, Suite 3000
Austin, Texas
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78701
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(Address of principal executive offices)
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(Zip Code)
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Page
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Item 5.
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||
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•
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business strategy;
|
•
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reserves;
|
•
|
exploration and development drilling prospects, inventories, projects and programs;
|
•
|
ability to replace the reserves we produce through drilling and property acquisitions;
|
•
|
financial strategy, liquidity and capital required for our development program;
|
•
|
realized oil, natural gas and natural gas liquids (“NGLs”) prices;
|
•
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timing and amount of future production of oil, natural gas and NGLs;
|
•
|
hedging strategy and results;
|
•
|
future drilling plans;
|
•
|
competition and government regulations;
|
•
|
ability to obtain permits and governmental approvals;
|
•
|
pending legal or environmental matters;
|
•
|
marketing of oil, natural gas and NGLs;
|
•
|
leasehold or business acquisitions;
|
•
|
costs of developing our properties;
|
•
|
general economic conditions;
|
•
|
credit markets;
|
•
|
uncertainty regarding our future operating results; and
|
•
|
plans, objectives, expectations and intentions contained in this Quarterly Report that are not historical.
|
(1)
|
Bbl
. One stock tank barrel, of 42 U.S. gallons liquid volume, used in reference to crude oil, condensate or natural gas liquids.
|
(2)
|
Boe
. One barrel of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.
|
(3)
|
Boe/d
. One barrel of oil equivalent per day.
|
(4)
|
British thermal unit
or
Btu
. The heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
|
(5)
|
Completion
. The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
|
(6)
|
Condensate
. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
|
(7)
|
Dry hole.
A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
|
(8)
|
Developed acreage
. Acreage spaced or assigned to productive wells, excluding undrilled acreage held by production under the terms of the lease.
|
(9)
|
Economically producible
. A resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. For a complete definition of economically producible, refer to the SEC’s Regulation S-X, Rule 4-10(a)(10).
|
(10)
|
Exploitation
. A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.
|
(11)
|
Exploration costs.
Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and natural gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:
|
|
(i)
|
Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are referred to as geological and geophysical costs or G&G costs.
|
|
(ii)
|
Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.
|
|
(iii)
|
Dry hole contributions and bottom hole contributions.
|
|
(iv)
|
Costs of drilling and equipping exploratory wells.
|
|
(v)
|
Costs of drilling exploratory-type stratigraphic test wells.
|
|
(vi)
|
Idle drilling rig fees which are not chargeable to joint operations.
|
(12)
|
Exploratory well.
A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.
|
(13)
|
Field
.
An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious, strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms structural feature and stratigraphic condition are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.
|
(14)
|
Formation
. A layer of rock which has distinct characteristics that differ from nearby rock.
|
(15)
|
GAAP
. Accounting principles generally accepted in the United States.
|
(16)
|
Gross acres or gross wells
. The total acres or wells, as the case may be, in which an entity owns a working interest.
|
(17)
|
Horizontal drilling
. A drilling technique where a well is drilled vertically to a certain depth and then drilled laterally within a specified target zone.
|
(18)
|
Identified drilling locations
. Potential drilling locations specifically identified by our management based on evaluation of applicable geologic and engineering data accrued over our multi-year historical drilling activities.
|
(19)
|
Lease operating expense.
All direct and allocated indirect costs of lifting hydrocarbons from a producing formation to the surface constituting part of the current operating expenses of a working interest. Such costs include labor, superintendence, supplies, repairs, maintenance, allocated overhead charges, workover, insurance and other expenses incidental to production, but exclude lease acquisition or drilling or completion expenses.
|
(20)
|
LIBOR
. London Interbank Offered Rate.
|
(21)
|
MBbl
. One thousand barrels of crude oil, condensate or NGLs.
|
(22)
|
MBoe
. One thousand barrels of oil equivalent.
|
(23)
|
Mcf
. One thousand cubic feet of natural gas.
|
(24)
|
MMBtu
. One million British thermal units.
|
(25)
|
MMcf
. One million cubic feet of natural gas.
|
(26)
|
Natural gas liquids or NGLs
. The combination of ethane, propane, butane, isobutane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.
|
(27)
|
Net acres or net wells
. The percentage of total acres or wells, as the case may be, an owner has out of a particular number of gross acres or wells. For example, an owner who has a 50% interest in 100 gross acres owns 50 net acres.
|
(28)
|
NYMEX
. The New York Mercantile Exchange.
|
(29)
|
Operator
. The entity responsible for the exploration, development and production of a well or lease.
|
(30)
|
PE Units
. The single class of units that represents all of the membership interests in Parsley Energy, LLC.
|
(31)
|
Proved developed reserves
. Proved reserves that can be expected to be recovered:
|
|
(i)
|
Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well; or
|
|
(ii)
|
Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
|
(32)
|
Proved reserves
. Those quantities of oil and natural gas, 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. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence, within a reasonable time. For a complete definition of proved oil and natural gas reserves, refer to the SEC’s Regulation S-X, Rule 4-10(a)(22).
|
(33)
|
Proved undeveloped reserves
or
PUDs
. Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. The following rules apply to PUDs:
|
|
(i)
|
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances;
|
|
(ii)
|
Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time; and
|
|
(iii)
|
Under no circumstances shall estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
|
(34)
|
Reasonable certainty
. A high degree of confidence. For a complete definition of reasonable certainty, refer to the SEC’s Regulation S-X, Rule 4-10(a)(24).
|
(35)
|
Recompletion
. The process of re-entering an existing wellbore that is either producing or not producing and completing new or existing reservoirs in an attempt to establish new production or increase existing production.
|
(36)
|
Reliable technology
. A grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
|
(37)
|
Reserves.
Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development prospects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project.
|
(38)
|
Reservoir.
A porous and permeable underground formation containing a natural accumulation of producible hydrocarbons that is confined by impermeable rock or water barriers and is separate from other reservoirs.
|
(39)
|
SEC.
The United States Securities and Exchange Commission.
|
(40)
|
Spacing.
The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres,
e.g.
, 40-acre spacing, and is often established by regulatory agencies.
|
(41)
|
Undeveloped acreage.
Leased acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or natural gas regardless of whether such acreage contains proved reserves.
|
(42)
|
Wellbore.
The hole drilled by the bit that is equipped for oil or gas production on a completed well. Also called well or borehole.
|
(43)
|
Working interest.
The right granted to the lessee of a property to explore for and to produce and own oil, natural gas or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty or carried basis.
|
(44)
|
Workover.
Operations on a producing well to restore or increase production.
|
(45)
|
WTI.
West Texas Intermediate crude oil, which is a light, sweet crude oil, characterized by an American Petroleum Institute gravity, or API gravity, between 39 and 41 and a sulfur content of approximately 0.4 weight percent that is used as a benchmark for other crude oils.
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
|
(In thousands, except per share data)
|
||||||||||||||
REVENUES
|
|
|
|
|
|
|
|
||||||||
Oil sales
|
$
|
396,325
|
|
|
$
|
178,066
|
|
|
$
|
727,428
|
|
|
$
|
347,811
|
|
Natural gas sales
|
12,235
|
|
|
12,983
|
|
|
29,659
|
|
|
25,450
|
|
||||
Natural gas liquids sales
|
57,275
|
|
|
20,336
|
|
|
97,895
|
|
|
37,749
|
|
||||
Other
|
1,953
|
|
|
2,292
|
|
|
5,547
|
|
|
3,525
|
|
||||
Total revenues
|
467,788
|
|
|
213,677
|
|
|
860,529
|
|
|
414,535
|
|
||||
OPERATING EXPENSES
|
|
|
|
|
|
|
|
||||||||
Lease operating expenses
|
35,904
|
|
|
29,631
|
|
|
64,736
|
|
|
47,258
|
|
||||
Transportation and processing costs
|
6,471
|
|
|
—
|
|
|
12,738
|
|
|
—
|
|
||||
Production and ad valorem taxes
|
27,331
|
|
|
11,397
|
|
|
51,517
|
|
|
22,559
|
|
||||
Depreciation, depletion and amortization
|
145,552
|
|
|
83,315
|
|
|
266,751
|
|
|
152,285
|
|
||||
General and administrative expenses (including stock-based compensation of $5,363 and $5,251 for the three months ended June 30, 2018 and 2017 and $10,432 and $9,460 for the six months ended June 30, 2018 and 2017)
|
35,991
|
|
|
31,761
|
|
|
70,986
|
|
|
55,803
|
|
||||
Exploration and abandonment costs
|
3,366
|
|
|
2,442
|
|
|
8,777
|
|
|
5,205
|
|
||||
Acquisition costs
|
(2
|
)
|
|
7,176
|
|
|
2
|
|
|
8,520
|
|
||||
Accretion of asset retirement obligations
|
359
|
|
|
193
|
|
|
713
|
|
|
329
|
|
||||
Other operating expenses
|
2,477
|
|
|
2,503
|
|
|
4,652
|
|
|
4,786
|
|
||||
Total operating expenses
|
257,449
|
|
|
168,418
|
|
|
480,872
|
|
|
296,745
|
|
||||
OPERATING INCOME
|
210,339
|
|
|
45,259
|
|
|
379,657
|
|
|
117,790
|
|
||||
OTHER INCOME (EXPENSE)
|
|
|
|
|
|
|
|
||||||||
Interest expense, net
|
(33,758
|
)
|
|
(22,764
|
)
|
|
(65,726
|
)
|
|
(42,100
|
)
|
||||
Gain on sale of property
|
5,166
|
|
|
—
|
|
|
5,055
|
|
|
—
|
|
||||
Loss on early extinguishment of debt
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,891
|
)
|
||||
(Loss) gain on derivatives
|
(9,466
|
)
|
|
43,514
|
|
|
(20,259
|
)
|
|
68,130
|
|
||||
Change in TRA liability
|
—
|
|
|
—
|
|
|
(82
|
)
|
|
(20,549
|
)
|
||||
Interest income
|
1,686
|
|
|
2,178
|
|
|
3,809
|
|
|
4,549
|
|
||||
Other income (expense)
|
234
|
|
|
(177
|
)
|
|
535
|
|
|
773
|
|
||||
Total other income (expense), net
|
(36,138
|
)
|
|
22,751
|
|
|
(76,668
|
)
|
|
6,912
|
|
||||
INCOME BEFORE INCOME TAXES
|
174,201
|
|
|
68,010
|
|
|
302,989
|
|
|
124,702
|
|
||||
INCOME TAX EXPENSE
|
(33,243
|
)
|
|
(12,216
|
)
|
|
(56,568
|
)
|
|
(30,618
|
)
|
||||
NET INCOME
|
140,958
|
|
|
55,794
|
|
|
246,421
|
|
|
94,084
|
|
||||
LESS: NET INCOME ATTRIBUTABLE TO
NONCONTROLLING INTERESTS |
(21,803
|
)
|
|
(15,048
|
)
|
|
(44,376
|
)
|
|
(23,896
|
)
|
||||
NET INCOME ATTRIBUTABLE TO
PARSLEY ENERGY, INC. STOCKHOLDERS |
$
|
119,155
|
|
|
$
|
40,746
|
|
|
$
|
202,045
|
|
|
$
|
70,188
|
|
|
|
|
|
|
|
|
|
||||||||
Net income per common share:
|
|
|
|
|
|
|
|
||||||||
Basic
|
$
|
0.44
|
|
|
$
|
0.17
|
|
|
$
|
0.76
|
|
|
$
|
0.30
|
|
Diluted
|
$
|
0.44
|
|
|
$
|
0.17
|
|
|
$
|
0.76
|
|
|
$
|
0.30
|
|
Weighted average common shares outstanding:
|
|
|
|
|
|
|
|
||||||||
Basic
|
272,239
|
|
|
245,698
|
|
|
266,479
|
|
|
233,255
|
|
||||
Diluted
|
272,846
|
|
|
246,792
|
|
|
267,043
|
|
|
234,315
|
|
|
Issued Shares
|
|
|
|
|
|
|
|
|
|
Shares
|
|
|
|
|
|
|
|
|
|||||||||||||||||||||
|
Class A
Common Stock
|
|
Class B
Common Stock
|
|
Class A
Common Stock
|
|
Class B
Common Stock
|
|
Additional
paid in capital
|
|
Retained earnings
|
|
Treasury stock
|
|
Treasury stock
|
|
Total stockholders’ equity
|
|
Noncontrolling
interest
|
|
Total equity
|
|||||||||||||||||||
|
(In thousands)
|
|||||||||||||||||||||||||||||||||||||||
Balance at December 31, 2017
|
252,420
|
|
|
62,128
|
|
|
$
|
2,524
|
|
|
$
|
622
|
|
|
$
|
4,666,365
|
|
|
$
|
43,519
|
|
|
159
|
|
|
$
|
(735
|
)
|
|
$
|
4,712,295
|
|
|
$
|
1,168,411
|
|
|
$
|
5,880,706
|
|
Exchange of PE Units and Class B Common Stock for Class A Common Stock
|
24,876
|
|
|
(24,876
|
)
|
|
249
|
|
|
(249
|
)
|
|
472,861
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
472,861
|
|
|
(472,861
|
)
|
|
—
|
|
||||||||
Change in net deferred tax liability due to exchange of PE Units
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(26,541
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(26,541
|
)
|
|
—
|
|
|
(26,541
|
)
|
||||||||
Issuance of restricted stock
|
802
|
|
|
—
|
|
|
8
|
|
|
—
|
|
|
(8
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Vesting of restricted stock units
|
910
|
|
|
—
|
|
|
9
|
|
|
—
|
|
|
(9
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Repurchase of common stock
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
429
|
|
|
(10,871
|
)
|
|
(10,871
|
)
|
|
—
|
|
|
(10,871
|
)
|
||||||||
Restricted stock forfeited
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(245
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(245
|
)
|
|
—
|
|
|
(245
|
)
|
||||||||
Stock-based compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10,677
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10,677
|
|
|
—
|
|
|
10,677
|
|
||||||||
Conversion of restricted stock units to restricted stock awards
|
1,098
|
|
|
—
|
|
|
11
|
|
|
—
|
|
|
(11
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
202,045
|
|
|
—
|
|
|
—
|
|
|
202,045
|
|
|
44,376
|
|
|
246,421
|
|
||||||||
Balance at June 30, 2018
|
280,106
|
|
|
37,252
|
|
|
$
|
2,801
|
|
|
$
|
373
|
|
|
$
|
5,123,089
|
|
|
$
|
245,564
|
|
|
588
|
|
|
$
|
(11,606
|
)
|
|
$
|
5,360,221
|
|
|
$
|
739,926
|
|
|
$
|
6,100,147
|
|
|
Six Months Ended June 30,
|
||||||
|
2018
|
|
2017
|
||||
|
(In thousands)
|
||||||
CASH FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
||||
Net income
|
$
|
246,421
|
|
|
$
|
94,084
|
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
||||
Depreciation, depletion and amortization
|
266,751
|
|
|
152,285
|
|
||
Accretion of asset retirement obligations
|
713
|
|
|
329
|
|
||
Gain on sale of property
|
(5,055
|
)
|
|
—
|
|
||
Loss on early extinguishment of debt
|
—
|
|
|
3,891
|
|
||
Amortization of deferred loan origination costs
|
2,374
|
|
|
1,803
|
|
||
Amortization of bond premium
|
(258
|
)
|
|
(258
|
)
|
||
Stock-based compensation
|
10,432
|
|
|
9,460
|
|
||
Deferred income tax expense
|
56,568
|
|
|
30,476
|
|
||
Change in TRA liability
|
82
|
|
|
20,549
|
|
||
Loss (gain) on derivatives
|
20,259
|
|
|
(68,130
|
)
|
||
Net cash (paid) received for derivative settlements
|
(7,211
|
)
|
|
2,115
|
|
||
Net cash paid for option premiums
|
(26,330
|
)
|
|
(13,281
|
)
|
||
Other
|
8,208
|
|
|
261
|
|
||
Changes in operating assets and liabilities, net of acquisitions:
|
|
|
|
||||
Accounts receivable
|
(42,993
|
)
|
|
(22,575
|
)
|
||
Accounts receivable—related parties
|
147
|
|
|
74
|
|
||
Other current assets
|
(31,419
|
)
|
|
46,318
|
|
||
Other noncurrent assets
|
(318
|
)
|
|
(842
|
)
|
||
Accounts payable and accrued expenses
|
(32,213
|
)
|
|
52,672
|
|
||
Revenue and severance taxes payable
|
24,823
|
|
|
17,973
|
|
||
Net cash provided by operating activities
|
490,981
|
|
|
327,204
|
|
||
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
||||
Development of oil and natural gas properties
|
(854,228
|
)
|
|
(361,742
|
)
|
||
Acquisitions of oil and natural gas properties
|
(56,014
|
)
|
|
(2,088,286
|
)
|
||
Additions to other property and equipment
|
(48,047
|
)
|
|
(19,520
|
)
|
||
Proceeds from sales of oil and natural gas properties
|
42,553
|
|
|
13,557
|
|
||
Maturity of short-term investments
|
49,627
|
|
|
—
|
|
||
Other
|
35,018
|
|
|
(630
|
)
|
||
Net cash used in investing activities
|
(831,091
|
)
|
|
(2,456,621
|
)
|
||
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
||||
Borrowings under long-term debt
|
—
|
|
|
452,480
|
|
||
Payments on long-term debt
|
(1,461
|
)
|
|
(67,411
|
)
|
||
Debt issuance costs
|
(45
|
)
|
|
(9,206
|
)
|
||
Proceeds from issuance of common stock, net
|
—
|
|
|
2,123,527
|
|
||
Repurchase of common stock
|
(10,871
|
)
|
|
(137
|
)
|
||
Net cash (used in) provided by financing activities
|
(12,377
|
)
|
|
2,499,253
|
|
||
Net (decrease) increase in cash, cash equivalents and restricted cash
|
(352,487
|
)
|
|
369,836
|
|
||
Cash, cash equivalents and restricted cash at beginning of period
|
554,189
|
|
|
136,669
|
|
||
Cash, cash equivalents and restricted cash at end of period
|
$
|
201,702
|
|
|
$
|
506,505
|
|
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
|
|
|
|
||||
Cash paid for interest
|
$
|
64,047
|
|
|
$
|
15,102
|
|
Cash paid for income taxes
|
$
|
—
|
|
|
$
|
200
|
|
SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES:
|
|
|
|
||||
Asset retirement obligations incurred, including changes in estimate
|
$
|
940
|
|
|
$
|
8,084
|
|
Additions to oil and natural gas properties - change in capital accruals
|
$
|
46,969
|
|
|
$
|
121,663
|
|
Additions to other property and equipment funded by capital lease borrowings
|
$
|
1,175
|
|
|
$
|
2,500
|
|
Common stock issued for oil and natural gas properties
|
$
|
—
|
|
|
$
|
1,183,501
|
|
Net premiums on options that settled during the period
|
$
|
(34,598
|
)
|
|
$
|
(9,917
|
)
|
•
|
estimates of proved reserves of oil and natural gas, which affect the calculations of depletion, depreciation and amortization (“DD&A”) and impairment of capitalized costs of oil and natural gas properties;
|
•
|
estimates of asset retirement obligations;
|
•
|
estimates of the fair value of oil and natural gas properties the Company owns, particularly properties that the Company has not yet explored, or fully explored, by drilling and completing wells;
|
•
|
impairment of undeveloped properties and other assets;
|
•
|
depreciation of property and equipment; and
|
•
|
valuation of commodity derivative instruments.
|
|
Three Months Ended June 30, 2018
|
||||||||||
|
ASC 605
|
|
Adjustment
|
|
ASC 606
|
||||||
Revenues
|
|
|
|
|
|
||||||
Oil sales
|
$
|
396,325
|
|
|
$
|
—
|
|
|
$
|
396,325
|
|
Natural gas sales
(1)
|
11,094
|
|
|
1,141
|
|
|
12,235
|
|
|||
Natural gas liquids sales
(1)
|
51,945
|
|
|
5,330
|
|
|
57,275
|
|
|||
Total production revenues
|
459,364
|
|
|
6,471
|
|
|
465,835
|
|
|||
Operating expenses
|
|
|
|
|
|
||||||
Transportation and processing costs
|
—
|
|
|
6,471
|
|
|
6,471
|
|
|||
Production revenues less transportation and processing costs
|
$
|
459,364
|
|
|
$
|
—
|
|
|
$
|
459,364
|
|
|
|
|
|
|
|
||||||
Net income attributable to Parsley, Inc. stockholders
|
$
|
119,155
|
|
|
$
|
—
|
|
|
$
|
119,155
|
|
|
Six Months Ended June 30, 2018
|
||||||||||
|
ASC 605
|
|
Adjustment
|
|
ASC 606
|
||||||
Revenues
|
|
|
|
|
|
||||||
Oil sales
|
$
|
727,428
|
|
|
$
|
—
|
|
|
$
|
727,428
|
|
Natural gas sales
(1)
|
26,680
|
|
|
2,979
|
|
|
29,659
|
|
|||
Natural gas liquids sales
(1)
|
88,136
|
|
|
9,759
|
|
|
97,895
|
|
|||
Total production revenues
|
842,244
|
|
|
12,738
|
|
|
854,982
|
|
|||
Operating expenses
|
|
|
|
|
|
||||||
Transportation and processing costs
|
—
|
|
|
12,738
|
|
|
12,738
|
|
|||
Production revenues less transportation and processing costs
|
$
|
842,244
|
|
|
$
|
—
|
|
|
$
|
842,244
|
|
|
|
|
|
|
|
||||||
Net income attributable to Parsley, Inc. stockholders
|
$
|
202,045
|
|
|
$
|
—
|
|
|
$
|
202,045
|
|
Crude Options
|
|
Six Months Ending December 31, 2018
|
|
Year Ending
December 31, 2019 |
||||
Put spreads
(1)
|
|
|
|
|
||||
Purchased:
|
|
|
|
|
||||
Puts
|
|
|
|
|
||||
Notional (MBbl)
|
|
6,600
|
|
|
8,700
|
|
||
Weighted average strike price
|
|
$
|
49.67
|
|
|
$
|
56.98
|
|
Sold:
|
|
|
|
|
||||
Puts
|
|
|
|
|
||||
Notional (MBbl)
|
|
(6,600
|
)
|
|
(8,700
|
)
|
||
Weighted average strike price
|
|
$
|
39.66
|
|
|
$
|
46.98
|
|
|
|
|
|
|
||||
Three-way collars
|
|
|
|
|
||||
Purchased:
|
|
|
|
|
||||
Puts
|
|
|
|
|
||||
Notional (MBbl)
|
|
5,700
|
|
|
3,300
|
|
||
Weighted average strike price
|
|
$
|
50.00
|
|
|
$
|
50.45
|
|
Sold:
|
|
|
|
|
||||
Puts
|
|
|
|
|
||||
Notional (MBbl)
|
|
(5,700
|
)
|
|
(3,300
|
)
|
||
Weighted average strike price
|
|
$
|
40.00
|
|
|
$
|
40.45
|
|
Calls
|
|
|
|
|
||||
Notional (MBbl)
|
|
(5,700
|
)
|
|
(3,300
|
)
|
||
Weighted average strike price
|
|
$
|
75.65
|
|
|
$
|
80.36
|
|
|
|
|
|
|
||||
Two-way collars
|
|
|
|
|
||||
Purchased:
|
|
|
|
|
||||
Puts
|
|
|
|
|
||||
Notional (MBbl)
|
|
552
|
|
|
—
|
|
||
Weighted average strike price
|
|
$
|
45.67
|
|
|
$
|
—
|
|
Sold:
|
|
|
|
|
||||
Calls
|
|
|
|
|
||||
Notional (MBbl)
|
|
(552
|
)
|
|
—
|
|
||
Weighted average strike price
|
|
$
|
61.31
|
|
|
$
|
—
|
|
|
|
|
|
|
||||
Basis swap contracts
(2)
|
|
|
|
|
||||
Midland-Cushing index swap volume (MBbl)
|
|
2,084
|
|
|
—
|
|
||
Swap price ($/Bbl)
|
|
$
|
(0.86
|
)
|
|
$
|
—
|
|
|
|
|
|
|
||||
Rollfactor swap contracts
(3)
|
|
|
|
|
||||
Midland-Cushing index swap volume (MBbl)
|
|
2,760
|
|
|
—
|
|
||
Swap price ($/Bbl)
|
|
$
|
0.60
|
|
|
—
|
|
(1)
|
Excludes 2,444 notional MBbls with a fair value of $11.1 million related to amounts recognized under master netting agreements with derivative counterparties.
|
(2)
|
Represents swaps that fix the basis differentials between the index prices at which the Company sells its oil produced in the Permian Basin and the Cushing WTI price.
|
(3)
|
These positions hedge the timing risk associated with the Company’s physical sales. The Company generally sells crude oil for the delivery month at a sales price based on the average NYMEX price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is the first month.
|
Natural Gas
|
|
Six Months Ending December 31, 2018
|
||
Three-way collars
|
|
|
||
Purchased:
|
|
|
||
Puts
|
|
|
||
Notional (MMbtu)
|
|
1,500,000
|
|
|
Weighted average strike price
|
|
$
|
3.00
|
|
Sold:
|
|
|
||
Calls
|
|
|
||
Notional (MMbtu)
|
|
(1,500,000
|
)
|
|
Weighted average strike price
|
|
$
|
2.75
|
|
Puts
|
|
|
||
Notional (MMbtu)
|
|
(1,500,000
|
)
|
|
Weighted Average Strike Price
|
|
$
|
3.60
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Changes in fair value of derivative instruments
|
$
|
(2,447
|
)
|
|
38,541
|
|
|
$
|
(10,367
|
)
|
|
63,458
|
|
||
Net derivative settlements
|
(7,019
|
)
|
|
4,973
|
|
|
(9,892
|
)
|
|
4,672
|
|
||||
(Loss) gain on derivatives
|
$
|
(9,466
|
)
|
|
$
|
43,514
|
|
|
$
|
(20,259
|
)
|
|
$
|
68,130
|
|
|
|
|
|
|
|
|
|
||||||||
Net premiums on options that settled during the period
(1)
|
$
|
(18,072
|
)
|
|
$
|
(5,063
|
)
|
|
$
|
(34,598
|
)
|
|
$
|
(9,917
|
)
|
(1)
|
The net premium on options that settled during the period represents the cumulative cost of premiums paid and received on positions purchased and sold, which expired during the current period.
|
|
Gross Amount
|
|
Netting
Adjustments
|
|
Net
Exposure
|
||||||
June 30, 2018
|
|
|
|
|
|
||||||
Derivative assets with right of offset or
master netting agreements
|
$
|
84,698
|
|
|
$
|
(11,081
|
)
|
|
$
|
73,617
|
|
Derivative liabilities with right of offset or
master netting agreements
|
(114,259
|
)
|
|
11,081
|
|
|
(103,178
|
)
|
|||
|
|
|
|
|
|
||||||
December 31, 2017
|
|
|
|
|
|
||||||
Derivative assets with right of offset or
master netting agreements
|
$
|
59,132
|
|
|
$
|
(1,443
|
)
|
|
$
|
57,689
|
|
Derivative liabilities with right of offset or
master netting agreements
|
(106,986
|
)
|
|
1,443
|
|
|
(105,543
|
)
|
|
June 30, 2018
|
|
December 31, 2017
|
||||
Oil and natural gas properties:
|
|
|
|
||||
Subject to depletion
|
$
|
5,543,512
|
|
|
$
|
4,492,802
|
|
Not subject to depletion
|
|
|
|
||||
Incurred in 2018
|
546,240
|
|
|
—
|
|
||
Incurred in 2017
|
2,271,009
|
|
|
2,837,766
|
|
||
Incurred in 2016 and prior
|
1,073,809
|
|
|
1,220,746
|
|
||
Total not subject to depletion
|
3,891,058
|
|
|
4,058,512
|
|
||
Oil and natural gas properties, successful efforts method
|
9,434,570
|
|
|
8,551,314
|
|
||
Less accumulated depreciation, depletion and impairment
|
(1,074,499
|
)
|
|
(822,459
|
)
|
||
Total oil and natural gas properties, net
|
8,360,071
|
|
|
7,728,855
|
|
||
Other property, plant and equipment
|
177,952
|
|
|
131,115
|
|
||
Less accumulated depreciation
|
(31,435
|
)
|
|
(24,528
|
)
|
||
Other property, plant and equipment, net
|
146,517
|
|
|
106,587
|
|
||
Total property, plant and equipment, net
|
$
|
8,506,588
|
|
|
$
|
7,835,442
|
|
Cash
|
$
|
2,469
|
|
Receivables
|
20,756
|
|
|
Derivatives
|
3,970
|
|
|
Proved oil and natural gas properties
|
353,000
|
|
|
Unproved oil and natural gas properties
|
2,257,266
|
|
|
Total assets acquired
|
2,637,461
|
|
|
Accounts payable
|
(48,179
|
)
|
|
Deferred tax liability
|
(10,167
|
)
|
|
Total liabilities assumed
|
(58,346
|
)
|
|
Estimated fair value of net assets acquired
|
$
|
2,579,115
|
|
|
June 30, 2018
|
||
Asset retirement obligations, beginning of period
|
$
|
27,170
|
|
Additional liabilities incurred
|
1,083
|
|
|
Accretion expense
|
713
|
|
|
Liabilities settled upon plugging and abandoning wells
|
(143
|
)
|
|
Disposition of wells
|
(216
|
)
|
|
Asset retirement obligations, end of period
|
$
|
28,607
|
|
|
June 30, 2018
|
|
December 31, 2017
|
||||
Revolving Credit Agreement
|
$
|
—
|
|
|
$
|
—
|
|
6.250% senior unsecured notes due 2024
|
400,000
|
|
|
400,000
|
|
||
5.375% senior unsecured notes due 2025
|
650,000
|
|
|
650,000
|
|
||
5.250% senior unsecured notes due 2025
|
450,000
|
|
|
450,000
|
|
||
5.625% senior unsecured notes due 2027
|
700,000
|
|
|
700,000
|
|
||
Capital leases
|
4,620
|
|
|
4,906
|
|
||
Total debt
|
2,204,620
|
|
|
2,204,906
|
|
||
Debt issuance costs on senior unsecured notes
|
(24,653
|
)
|
|
(26,341
|
)
|
||
Premium on senior unsecured notes
|
3,054
|
|
|
3,312
|
|
||
Less: current portion
|
(2,462
|
)
|
|
(2,352
|
)
|
||
Total long-term debt
|
$
|
2,180,559
|
|
|
$
|
2,179,525
|
|
2018
|
$
|
1,253
|
|
2019
|
2,229
|
|
|
2020
|
949
|
|
|
2021
|
160
|
|
|
2022
|
26
|
|
|
Thereafter
|
2,200,003
|
|
|
Total
|
$
|
2,204,620
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Cash payments for interest
|
$
|
34,592
|
|
|
$
|
12,639
|
|
|
$
|
64,047
|
|
|
$
|
15,102
|
|
Change in interest accrual
|
(1,890
|
)
|
|
9,234
|
|
|
(437
|
)
|
|
25,453
|
|
||||
Amortization of deferred loan origination costs
|
1,185
|
|
|
1,020
|
|
|
2,374
|
|
|
1,803
|
|
||||
Amortization of bond premium
|
(129
|
)
|
|
(129
|
)
|
|
(258
|
)
|
|
(258
|
)
|
||||
Total interest expense, net
|
$
|
33,758
|
|
|
$
|
22,764
|
|
|
$
|
65,726
|
|
|
$
|
42,100
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Basic EPS (in thousands, except per share data)
|
|
|
|
|
|
|
|
||||||||
Numerator:
|
|
|
|
|
|
|
|
||||||||
Basic net income attributable to Parsley Energy, Inc. Stockholders
|
$
|
119,155
|
|
|
$
|
40,746
|
|
|
$
|
202,045
|
|
|
$
|
70,188
|
|
Denominator:
|
|
|
|
|
|
|
|
||||||||
Basic weighted average shares outstanding
|
272,239
|
|
|
245,698
|
|
|
266,479
|
|
|
233,255
|
|
||||
Basic EPS attributable to Parsley Energy, Inc. Stockholders
|
$
|
0.44
|
|
|
$
|
0.17
|
|
|
$
|
0.76
|
|
|
$
|
0.30
|
|
Diluted EPS
|
|
|
|
|
|
|
|
||||||||
Numerator:
|
|
|
|
|
|
|
|
||||||||
Net income attributable to Parsley Energy, Inc. Stockholders
|
119,155
|
|
|
40,746
|
|
|
202,045
|
|
|
70,188
|
|
||||
Diluted net income attributable to Parsley Energy, Inc. Stockholders
|
$
|
119,155
|
|
|
$
|
40,746
|
|
|
$
|
202,045
|
|
|
$
|
70,188
|
|
Denominator:
|
|
|
|
|
|
|
|
||||||||
Basic weighted average shares outstanding
|
272,239
|
|
|
245,698
|
|
|
266,479
|
|
|
233,255
|
|
||||
Effect of dilutive securities:
|
|
|
|
|
|
|
|
||||||||
Time-Based Restricted Stock and Time-Based Restricted Stock Units
|
607
|
|
|
1,094
|
|
|
564
|
|
|
1,060
|
|
||||
Diluted weighted average shares outstanding
(1)
|
272,846
|
|
|
246,792
|
|
|
267,043
|
|
|
234,315
|
|
||||
Diluted EPS attributable to Parsley Energy, Inc. Stockholders
|
$
|
0.44
|
|
|
$
|
0.17
|
|
|
$
|
0.76
|
|
|
$
|
0.30
|
|
|
|
|
|
|
(1)
|
As of
June 30, 2018
and
2017
, there were
1,356,522
shares of performance-based restricted stock (“PSAs”) and
640,062
performance-based restricted stock units (“PSUs”), respectively, that could vest in the future based on predetermined performance and market goals. These units were not included in the computation of EPS for the
three and six
months ended
June 30, 2018
and
2017
, respectively, because the performance and market conditions had not been met, assuming the end of the reporting period was the end of the contingency period.
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
|
(In thousands)
|
||||||||||||||
Net income (loss) attributable to the noncontrolling interests of:
|
|
|
|
|
|
|
|
||||||||
Parsley LLC
|
$
|
21,704
|
|
|
$
|
14,950
|
|
|
$
|
44,119
|
|
|
$
|
23,957
|
|
Pacesetter Drilling, LLC
|
99
|
|
|
98
|
|
|
257
|
|
|
(61
|
)
|
||||
Total net income attributable to noncontrolling interest
|
$
|
21,803
|
|
|
$
|
15,048
|
|
|
$
|
44,376
|
|
|
$
|
23,896
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Time-based restricted stock
|
$
|
2,166
|
|
|
$
|
1,491
|
|
|
$
|
4,054
|
|
|
$
|
2,608
|
|
Time-based restricted stock units
|
1,377
|
|
|
2,087
|
|
|
3,032
|
|
|
3,878
|
|
||||
Performance-based restricted stock awards
(1)
|
1,820
|
|
|
1,673
|
|
|
3,346
|
|
|
2,974
|
|
||||
Total stock-based compensation
|
$
|
5,363
|
|
|
$
|
5,251
|
|
|
$
|
10,432
|
|
|
$
|
9,460
|
|
|
|
|
|
|
(1)
|
Includes stock based compensation expense related to historical performance-based stock units.
|
|
Time-Based Restricted Stock (RSAs)
|
|
Time-Based Restricted Stock Units
(RSUs)
|
|
Performance-Based Restricted Stock Units
(PSUs)
|
|
Performance-Based Restricted Stock Awards
(PSAs)
|
||||||||
Outstanding at January 1, 2018
|
779
|
|
|
1,200
|
|
|
640
|
|
|
—
|
|
||||
Granted
(1)
|
302
|
|
|
279
|
|
|
—
|
|
|
500
|
|
||||
Converted
|
242
|
|
|
(242
|
)
|
|
(428
|
)
|
|
856
|
|
||||
Vested
|
(593
|
)
|
|
(486
|
)
|
|
(212
|
)
|
|
—
|
|
||||
Forfeited
|
—
|
|
|
(32
|
)
|
|
—
|
|
|
—
|
|
||||
Outstanding at June 30, 2018
|
730
|
|
|
719
|
|
|
—
|
|
|
1,356
|
|
||||
|
|
|
|
|
|
|
|
||||||||
(1) Weighted average grant date fair value
|
$
|
27.91
|
|
|
$
|
27.37
|
|
|
$
|
—
|
|
|
$
|
13.72
|
|
|
Six Months Ended June 30,
|
||
|
2018
|
|
2017
|
Shell Trading (US) Company
|
54%
|
|
67%
|
Lion Oil, Inc.
|
21%
|
|
—%
|
Targa Pipeline Mid-Continent, LLC
|
11%
|
|
13%
|
Level 1
:
|
|
Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.
|
Level 2
:
|
|
Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1 that are either directly or indirectly observable as of the reporting date.
|
Level 3
:
|
|
Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.
|
|
June 30, 2018
|
||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
Assets:
|
|
|
|
|
|
|
|
||||||||
Money market funds
|
$
|
127,787
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
127,787
|
|
Commodity derivative instruments
(1)
|
—
|
|
|
73,617
|
|
|
—
|
|
|
73,617
|
|
||||
Total assets
|
$
|
127,787
|
|
|
$
|
73,617
|
|
|
$
|
—
|
|
|
$
|
201,404
|
|
|
|
|
|
|
|
|
|
||||||||
Liabilities:
|
|
|
|
|
|
|
|
||||||||
Commodity derivative instruments
(1)
|
$
|
—
|
|
|
$
|
(103,178
|
)
|
|
$
|
—
|
|
|
$
|
(103,178
|
)
|
Total liabilities
|
$
|
—
|
|
|
$
|
(103,178
|
)
|
|
$
|
—
|
|
|
$
|
(103,178
|
)
|
Net asset (liability)
|
$
|
127,787
|
|
|
$
|
(29,561
|
)
|
|
$
|
—
|
|
|
$
|
98,226
|
|
|
December 31, 2017
|
||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
Assets:
|
|
|
|
|
|
|
|
||||||||
Money market funds
|
$
|
476,619
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
476,619
|
|
Commodity derivative instruments
(1)
|
—
|
|
|
57,689
|
|
|
—
|
|
|
57,689
|
|
||||
Total assets
|
$
|
476,619
|
|
|
$
|
57,689
|
|
|
$
|
—
|
|
|
$
|
534,308
|
|
|
|
|
|
|
|
|
|
||||||||
Liabilities:
|
|
|
|
|
|
|
|
||||||||
Commodity derivative instruments
(1)
|
$
|
—
|
|
|
$
|
(105,543
|
)
|
|
$
|
—
|
|
|
$
|
(105,543
|
)
|
Total liabilities
|
$
|
—
|
|
|
$
|
(105,543
|
)
|
|
$
|
—
|
|
|
$
|
(105,543
|
)
|
Net asset (liability)
|
$
|
476,619
|
|
|
$
|
(47,854
|
)
|
|
$
|
—
|
|
|
$
|
428,765
|
|
(1)
|
Includes deferred premiums to be settled upon expiration of the contract.
|
|
June 30, 2018
|
|
December 31, 2017
|
||||||||||||
|
Carrying Amount
|
|
Fair Value
|
|
Carrying Amount
|
|
Fair Value
|
||||||||
Cash and cash equivalents:
|
|
|
|
|
|
|
|
||||||||
Commercial paper
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
24,939
|
|
|
$
|
24,918
|
|
Short-term investments:
|
|
|
|
|
|
|
|
||||||||
Commercial paper
|
99,704
|
|
|
99,674
|
|
|
149,283
|
|
|
149,151
|
|
||||
Long-term debt:
|
|
|
|
|
|
|
|
||||||||
6.250% senior unsecured notes due 2024
|
400,000
|
|
|
417,252
|
|
|
400,000
|
|
|
423,824
|
|
||||
5.375% senior unsecured notes due 2025
|
650,000
|
|
|
646,536
|
|
|
650,000
|
|
|
658,483
|
|
||||
5.250% senior unsecured notes due 2025
|
450,000
|
|
|
443,520
|
|
|
450,000
|
|
|
454,010
|
|
||||
5.625% senior unsecured notes due 2027
|
700,000
|
|
|
695,429
|
|
|
700,000
|
|
|
715,169
|
|
||||
Revolving Credit Agreement
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
June 30, 2018
|
||||||||||||||
Consolidated Balance Sheet Location
|
Cash
|
|
Commercial Paper
|
|
Money Market Funds
|
|
Total
|
||||||||
Cash and cash equivalents
|
$
|
73,915
|
|
|
$
|
—
|
|
|
$
|
127,787
|
|
|
$
|
201,702
|
|
Short-term investments
|
—
|
|
|
99,704
|
|
|
—
|
|
|
99,704
|
|
|
December 31, 2017
|
||||||||||||||
Consolidated Balance Sheet Location
|
Cash
|
|
Commercial Paper
|
|
Money Market Funds
|
|
Total
|
||||||||
Cash and cash equivalents
|
$
|
52,631
|
|
|
$
|
24,939
|
|
|
$
|
476,619
|
|
|
$
|
554,189
|
|
Short-term investments
|
—
|
|
|
149,283
|
|
|
—
|
|
|
149,283
|
|
|
|
Developed Acreage
|
|
Undeveloped Acreage
|
|
Total Acreage
|
||||||||||||
Area
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Midland Basin
|
|
171,553
|
|
|
121,987
|
|
|
67,366
|
|
|
42,503
|
|
|
238,919
|
|
|
164,490
|
|
Delaware Basin
|
|
36,245
|
|
|
33,685
|
|
|
14,492
|
|
|
12,030
|
|
|
50,737
|
|
|
45,715
|
|
Total
|
|
207,798
|
|
|
155,672
|
|
|
81,858
|
|
|
54,533
|
|
|
289,656
|
|
|
210,205
|
|
|
|
Vertical Wells
|
|
Horizontal Wells
|
|
Total
|
||||||||||||
Area
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||||
Midland Basin
|
|
1,014
|
|
|
772.1
|
|
|
307
|
|
|
282.7
|
|
|
1,321
|
|
|
1,054.8
|
|
Delaware Basin
|
|
14
|
|
|
13.5
|
|
|
75
|
|
|
69.8
|
|
|
89
|
|
|
83.3
|
|
Total
|
|
1,028
|
|
|
785.6
|
|
|
382
|
|
|
352.5
|
|
|
1,410
|
|
|
1,138.1
|
|
|
|
Three Months Ended June 30, 2018
|
|
Six Months Ended June 30, 2018
|
||||||||
Area
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
||||
Midland Basin
|
|
37
|
|
|
35.9
|
|
|
57
|
|
|
55.0
|
|
Delaware Basin
|
|
8
|
|
|
7.7
|
|
|
29
|
|
|
28.3
|
|
Total
|
|
45
|
|
|
43.6
|
|
|
86
|
|
|
83.3
|
|
•
|
production volumes;
|
•
|
realized prices on the sale of oil, natural gas, and NGLs, including the effect of our commodity derivative contracts;
|
•
|
lease operating expenses;
|
•
|
capital expenditures;
|
•
|
completions activities; and
|
•
|
certain unit costs.
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||
Oil sales
|
85
|
%
|
|
84
|
%
|
|
86
|
%
|
|
85
|
%
|
Natural gas sales
|
3
|
%
|
|
6
|
%
|
|
3
|
%
|
|
6
|
%
|
Natural gas liquids sales
|
12
|
%
|
|
10
|
%
|
|
11
|
%
|
|
9
|
%
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||
Oil (MBbls)
|
6,165
|
|
|
3,917
|
|
|
11,506
|
|
|
7,311
|
|
Natural gas (MMcf)
|
9,235
|
|
|
5,421
|
|
|
17,791
|
|
|
9,840
|
|
Natural gas liquids (MBbls)
|
2,106
|
|
|
1,069
|
|
|
3,749
|
|
|
1,869
|
|
Total (MBoe)
|
9,811
|
|
|
5,890
|
|
|
18,221
|
|
|
10,821
|
|
Average net production (Boe/d)
|
107,813
|
|
|
64,725
|
|
|
100,669
|
|
|
59,785
|
|
Description and Production Period
|
VOLUME
(MBbls) |
|
SHORT PUT
PRICE ($/Bbl) |
|
LONG PUT
PRICE ($/Bbl) |
|
SHORT CALL
PRICE ($/Bbl) |
|
PRICE
|
|||||||||
Crude oil put spreads
(1)
:
|
|
|
|
|
|
|
|
|
|
|||||||||
Jul 2018 - Dec 2018
|
5,400
|
|
|
$
|
40.00
|
|
|
$
|
50.00
|
|
|
|
|
|
||||
Jul 2018 - Dec 2018
|
900
|
|
|
$
|
37.50
|
|
|
$
|
47.50
|
|
|
|
|
|
||||
Oct 2018 - Dec 2018
|
300
|
|
|
$
|
40.00
|
|
|
$
|
50.00
|
|
|
|
|
|
||||
Jan 2019 - Jun 2019
|
2,100
|
|
|
$
|
40.00
|
|
|
$
|
50.00
|
|
|
|
|
|
||||
Jan 2019 - Jun 2019
|
2,100
|
|
|
$
|
50.00
|
|
|
$
|
60.00
|
|
|
|
|
|
||||
Jul 2019 - Dec 2019
|
1,500
|
|
|
$
|
45.00
|
|
|
$
|
55.00
|
|
|
|
|
|
||||
Jul 2019 - Dec 2019
|
600
|
|
|
$
|
47.50
|
|
|
$
|
57.50
|
|
|
|
|
|
||||
Jul 2019 - Dec 2019
|
900
|
|
|
$
|
50.00
|
|
|
$
|
60.00
|
|
|
|
|
|
||||
Jul 2019 - Dec 2019
|
1,500
|
|
|
$
|
52.50
|
|
|
$
|
62.50
|
|
|
|
|
|
||||
Total
|
15,300
|
|
|
|
|
|
|
|
|
|
||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||
Crude oil three-way collars
(2)
:
|
|
|
|
|
|
|
|
|
|
|||||||||
Jul 2018 - Dec 2018
|
1,500
|
|
|
$
|
40.00
|
|
|
$
|
50.00
|
|
|
$
|
76.25
|
|
|
|
||
Jul 2018 - Dec 2018
|
600
|
|
|
$
|
40.00
|
|
|
$
|
50.00
|
|
|
$
|
76.93
|
|
|
|
||
Jul 2018 - Dec 2018
|
1,200
|
|
|
$
|
40.00
|
|
|
$
|
50.00
|
|
|
$
|
76.80
|
|
|
|
||
Jul 2018 - Dec 2018
|
1,200
|
|
|
$
|
40.00
|
|
|
$
|
50.00
|
|
|
$
|
74.75
|
|
|
|
||
Jul 2018 - Dec 2018
|
1,200
|
|
|
$
|
40.00
|
|
|
$
|
50.00
|
|
|
$
|
74.00
|
|
|
|
||
Jan 2019 - Dec 2019
|
1,200
|
|
|
$
|
40.00
|
|
|
$
|
50.00
|
|
|
$
|
81.00
|
|
|
|
||
Jan 2019 - Dec 2019
|
1,800
|
|
|
$
|
40.00
|
|
|
$
|
50.00
|
|
|
$
|
80.00
|
|
|
|
||
Jul 2019 - Dec 2019
|
300
|
|
|
$
|
45.00
|
|
|
$
|
55.00
|
|
|
$
|
80.00
|
|
|
|
||
Total
|
9,000
|
|
|
|
|
|
|
|
|
|
||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||
Crude oil collars
(3)
:
|
|
|
|
|
|
|
|
|
|
|||||||||
Jul 2018 - Dec 2018
|
184
|
|
|
|
|
$
|
47.00
|
|
|
$
|
59.40
|
|
|
|
||||
Jul 2018 - Dec 2018
|
92
|
|
|
|
|
$
|
45.00
|
|
|
$
|
60.00
|
|
|
|
||||
Jul 2018 - Dec 2018
|
92
|
|
|
|
|
$
|
45.00
|
|
|
$
|
60.85
|
|
|
|
||||
Jul 2018 - Dec 2018
|
184
|
|
|
|
|
$
|
45.00
|
|
|
$
|
64.10
|
|
|
|
||||
Total
|
552
|
|
|
|
|
|
|
|
|
|
||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||
Crude oil basis swaps
(4)
:
|
|
|
|
|
|
|
|
|
|
|||||||||
Jul 2018 - Dec 2018
|
180
|
|
|
|
|
|
|
|
|
$
|
(0.95
|
)
|
||||||
Jul 2018 - Dec 2018
|
632
|
|
|
|
|
|
|
|
|
$
|
(1.00
|
)
|
||||||
Jul 2018 - Dec 2018
|
420
|
|
|
|
|
|
|
|
|
$
|
(0.85
|
)
|
||||||
Jul 2018 - Dec 2018
|
300
|
|
|
|
|
|
|
|
|
$
|
(0.50
|
)
|
||||||
Jul 2018 - Dec 2018
|
460
|
|
|
|
|
|
|
|
|
$
|
(0.80
|
)
|
||||||
Jul 2018 - Dec 2018
|
92
|
|
|
|
|
|
|
|
|
$
|
(1.30
|
)
|
||||||
Total
|
2,084
|
|
|
|
|
|
|
|
|
|
||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||
Rollfactor swap contracts
(5)
:
|
|
|
|
|
|
|
|
|
|
|||||||||
Jul 2018 - Dec 2018
|
920
|
|
|
|
|
|
|
|
|
$
|
0.56
|
|
||||||
Jul 2018 - Dec 2018
|
920
|
|
|
|
|
|
|
|
|
$
|
0.60
|
|
||||||
Jul 2018 - Dec 2018
|
920
|
|
|
|
|
|
|
|
|
$
|
0.65
|
|
||||||
Total
|
2,760
|
|
|
|
|
|
|
|
|
|
Description and Production Period
|
VOLUME
(MMbtu) |
|
SHORT PUT
PRICE ($/MMbtu) |
|
LONG PUT
PRICE ($/MMbtu) |
|
SHORT CALL
PRICE ($/MMbtu) |
|||||||
Natural gas three-way collars
(6)
:
|
|
|
|
|
|
|
|
|||||||
Jul 2018 - Dec 2018
|
1,500,000
|
|
|
$
|
2.75
|
|
|
$
|
3.00
|
|
|
$
|
3.60
|
|
Total
|
1,500,000
|
|
|
|
|
|
|
|
|
|
|
(1)
|
When the NYMEX price is above the long put price, we receive the NYMEX price. When the NYMEX price is between the long put price and the short put price, we receive the long put price. When the NYMEX price is below the short put price, we receive the NYMEX price plus the difference between the short put price and the long put price.
|
|
(2)
|
Functions similarly to put spreads, except that when the index price is at or above the call price, we receive the call price.
|
|
(3)
|
When the NYMEX price is below the long put price, we receive the long put price. When the NYMEX price is between the put and short call prices, we receive the NYMEX price. When the NYMEX price is above the short call price, we receive the short call price.
|
|
(4)
|
We receive or pay the differential price on our crude oil basis swaps.
|
|
(5)
|
These swap contracts fix the adjustment at the swap price to ensure that we receive a sales price based on the average NYMEX price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is the first month.
|
|
(6)
|
Functions similarly to put spreads, except that when the index price is at or above the call price, we receive the call price.
|
Q3 2018
|
(17,854
|
)
|
|
Q4 2018
|
(19,114
|
)
|
|
Q1 2019
|
(9,215
|
)
|
|
Q2 2019
|
(9,215
|
)
|
|
Q3 2019
|
(9,823
|
)
|
|
Q4 2019
|
(9,823
|
)
|
|
Total
|
$
|
(75,044
|
)
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Capital expenditures
|
$
|
477,111
|
|
|
$
|
294,939
|
|
|
$
|
901,197
|
|
|
$
|
483,405
|
|
|
Three Months Ended June 30, 2018
|
||||||||||
|
ASC 605
|
|
Adjustment
|
|
ASC 606
|
||||||
Production revenues (in thousands):
|
|
|
|
|
|
||||||
Oil sales
|
$
|
396,325
|
|
|
$
|
—
|
|
|
$
|
396,325
|
|
Natural gas sales
(1)
|
11,094
|
|
|
1,141
|
|
|
12,235
|
|
|||
Natural gas liquids sales
(1)
|
51,945
|
|
|
5,330
|
|
|
57,275
|
|
|||
Total production revenues
|
459,364
|
|
|
6,471
|
|
|
465,835
|
|
|||
Operating expenses
|
|
|
|
|
|
||||||
Transportation and processing costs
|
—
|
|
|
6,471
|
|
|
6,471
|
|
|||
Production revenues less transportation and processing costs
|
$
|
459,364
|
|
|
$
|
—
|
|
|
$
|
459,364
|
|
|
|
|
|
|
|
||||||
Net income attributable to Parsley, Inc. stockholders (in thousands)
|
$
|
119,155
|
|
|
$
|
—
|
|
|
$
|
119,155
|
|
|
|
|
|
|
|
||||||
Production:
|
|
|
|
|
|
||||||
Oil (MBbls)
|
6,165
|
|
|
—
|
|
|
6,165
|
|
|||
Natural gas (MMcf)
(1)
|
8,287
|
|
|
948
|
|
|
9,235
|
|
|||
Natural gas liquids (MBbls)
(1)
|
1,853
|
|
|
253
|
|
|
2,106
|
|
|||
Total (MBoe)
|
9,399
|
|
|
412
|
|
|
9,811
|
|
|||
|
|
|
|
|
|
||||||
Average daily production volume:
|
|
|
|
|
|
||||||
Oil (Bbls)
|
67,747
|
|
|
—
|
|
|
67,747
|
|
|||
Natural gas (Mcf)
|
91,066
|
|
|
10,418
|
|
|
101,484
|
|
|||
Natural gas liquids (Bbls)
|
20,363
|
|
|
2,780
|
|
|
23,143
|
|
|||
Total (Boe)
|
103,286
|
|
|
4,527
|
|
|
107,813
|
|
|||
|
|
|
|
|
|
||||||
Certain unit costs (per Boe)
(2)
:
|
|
|
|
|
|
||||||
Lease operating expenses
|
$
|
3.82
|
|
|
$
|
(0.16
|
)
|
|
$
|
3.66
|
|
Transportation and processing costs
|
$
|
—
|
|
|
$
|
0.66
|
|
|
$
|
0.66
|
|
Production and ad valorem taxes
|
$
|
2.91
|
|
|
$
|
(0.12
|
)
|
|
$
|
2.79
|
|
Depreciation, depletion and amortization
|
$
|
15.49
|
|
|
$
|
(0.65
|
)
|
|
$
|
14.84
|
|
General and administrative expenses
|
$
|
3.83
|
|
|
$
|
(0.16
|
)
|
|
$
|
3.67
|
|
|
|
|
(1)
|
Natural gas and NGLs sales and production volumes for the three months ended June 30, 2018 reflect adjustments associated with our adoption of ASC 606, effective January 1, 2018.
|
|
(2)
|
Average costs per Boe for the three months ended June 30, 2018 reflect adjustments associated with our adoption of ASC 606, effective January 1, 2018.
|
|
Six Months Ended June 30, 2018
|
||||||||||
|
ASC 605
|
|
Adjustment
|
|
ASC 606
|
||||||
Production revenues (in thousands):
|
|
|
|
|
|
||||||
Oil sales
|
$
|
727,428
|
|
|
$
|
—
|
|
|
$
|
727,428
|
|
Natural gas sales
(1)
|
26,680
|
|
|
2,979
|
|
|
29,659
|
|
|||
Natural gas liquids sales
(1)
|
88,136
|
|
|
9,759
|
|
|
97,895
|
|
|||
Total production revenues
|
842,244
|
|
|
12,738
|
|
|
854,982
|
|
|||
Operating expenses
|
|
|
|
|
|
||||||
Transportation and processing costs
|
—
|
|
|
12,738
|
|
|
12,738
|
|
|||
Production revenues less transportation and processing costs
|
$
|
842,244
|
|
|
$
|
—
|
|
|
$
|
842,244
|
|
|
|
|
|
|
|
||||||
Net income attributable to Parsley, Inc. stockholders (in thousands)
|
$
|
202,045
|
|
|
$
|
—
|
|
|
$
|
202,045
|
|
|
|
|
|
|
|
||||||
Production:
|
|
|
|
|
|
||||||
Oil (MBbls)
|
11,506
|
|
|
—
|
|
|
11,506
|
|
|||
Natural gas (MMcf)
(1)
|
16,269
|
|
|
1,522
|
|
|
17,791
|
|
|||
Natural gas liquids (MBbls)
(1)
|
3,317
|
|
|
432
|
|
|
3,749
|
|
|||
Total (MBoe)
|
17,534
|
|
|
687
|
|
|
18,221
|
|
|||
|
|
|
|
|
|
||||||
Average daily production volume:
|
|
|
|
|
|
||||||
Oil (Bbls)
|
63,569
|
|
|
—
|
|
|
63,569
|
|
|||
Natural gas (Mcf)
|
89,884
|
|
|
8,409
|
|
|
98,293
|
|
|||
Natural gas liquids (Bbls)
|
18,326
|
|
|
2,387
|
|
|
20,713
|
|
|||
Total (Boe)
|
96,873
|
|
|
3,796
|
|
|
100,669
|
|
|||
|
|
|
|
|
|
||||||
Certain unit costs (per Boe)
(2)
:
|
|
|
|
|
|
||||||
Lease operating expenses
|
$
|
3.70
|
|
|
$
|
(0.15
|
)
|
|
$
|
3.55
|
|
Transportation and processing costs
|
$
|
—
|
|
|
$
|
0.70
|
|
|
$
|
0.70
|
|
Production and ad valorem taxes
|
$
|
2.94
|
|
|
$
|
(0.11
|
)
|
|
$
|
2.83
|
|
Depreciation, depletion and amortization
|
$
|
15.21
|
|
|
$
|
(0.57
|
)
|
|
$
|
14.64
|
|
General and administrative expenses
|
$
|
4.05
|
|
|
$
|
(0.15
|
)
|
|
$
|
3.90
|
|
|
|
|
(1)
|
Natural gas and NGLs sales and production volumes for the six months ended June 30, 2018 reflect adjustments associated with our adoption of ASC 606, effective January 1, 2018.
|
|
(2)
|
Average costs per Boe for the six months ended June 30, 2018 reflect adjustments associated with our adoption of ASC 606, effective January 1, 2018.
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Production revenues (in thousands):
|
|
|
|
|
|
|
|
||||||||
Oil sales
|
$
|
396,325
|
|
|
$
|
178,066
|
|
|
$
|
727,428
|
|
|
$
|
347,811
|
|
Natural gas sales
(1)
|
12,235
|
|
|
12,983
|
|
|
29,659
|
|
|
25,450
|
|
||||
Natural gas liquids sales
(1)
|
57,275
|
|
|
20,336
|
|
|
97,895
|
|
|
37,749
|
|
||||
Total revenues
|
$
|
465,835
|
|
|
$
|
211,385
|
|
|
$
|
854,982
|
|
|
$
|
411,010
|
|
|
|
|
|
|
|
|
|
||||||||
Average realized prices
(2)
:
|
|
|
|
|
|
|
|
||||||||
Oil, without realized derivatives (per Bbls)
|
$
|
64.29
|
|
|
$
|
45.46
|
|
|
$
|
63.22
|
|
|
$
|
47.57
|
|
Oil, with realized derivatives (per Bbls)
|
60.11
|
|
|
45.49
|
|
|
59.28
|
|
|
46.90
|
|
||||
Natural gas, without realized derivatives (per Mcf)
|
1.32
|
|
|
2.39
|
|
|
1.67
|
|
|
2.59
|
|
||||
Natural gas, with realized derivatives (per Mcf)
|
1.40
|
|
|
2.36
|
|
|
1.72
|
|
|
2.56
|
|
||||
Natural gas liquids (per Bbls)
|
27.20
|
|
|
19.02
|
|
|
26.11
|
|
|
20.20
|
|
||||
Average price per Boe, without realized derivatives
|
47.48
|
|
|
35.89
|
|
|
46.92
|
|
|
37.98
|
|
||||
Average price per Boe, with realized derivatives
|
44.92
|
|
|
35.87
|
|
|
44.48
|
|
|
37.50
|
|
||||
|
|
|
|
|
|
|
|
||||||||
Production:
|
|
|
|
|
|
|
|
||||||||
Oil (MBbls)
|
6,165
|
|
|
3,917
|
|
|
11,506
|
|
|
7,311
|
|
||||
Natural gas (MMcf)
(1)
|
9,235
|
|
|
5,421
|
|
|
17,791
|
|
|
9,840
|
|
||||
Natural gas liquids (MBbls)
(1)
|
2,106
|
|
|
1,069
|
|
|
3,749
|
|
|
1,869
|
|
||||
Total (MBoe)
|
9,811
|
|
|
5,890
|
|
|
18,221
|
|
|
10,821
|
|
||||
|
|
|
|
|
|
|
|
||||||||
Average daily production volume:
|
|
|
|
|
|
|
|
||||||||
Oil (Bbls)
|
67,747
|
|
|
43,044
|
|
|
63,569
|
|
|
40,392
|
|
||||
Natural gas (Mcf)
|
101,484
|
|
|
59,571
|
|
|
98,293
|
|
|
54,365
|
|
||||
Natural gas liquids (Bbls)
|
23,143
|
|
|
11,747
|
|
|
20,713
|
|
|
10,326
|
|
||||
Total (Boe)
|
107,813
|
|
|
64,725
|
|
|
100,669
|
|
|
59,785
|
|
(1)
|
Natural gas and NGLs sales and associated production volumes for the three and six months ended June 30, 2018 reflect adjustments associated with our adoption of ASC 606, effective January 1, 2018, as discussed in
Factors Affecting the Comparability of our Financial Condition and Results of Operations—Impact of ASC Topic 606 Adoption
.
|
(2)
|
Average prices shown in the table reflect prices both before and after the effects of our realized commodity hedging transactions. Our calculation of such effects includes both realized gains and losses on cash settlements for commodity derivative transactions and premiums paid or received on options that settled during the period.
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Average realized oil price ($/Bbl)
|
$
|
64.29
|
|
|
$
|
45.46
|
|
|
$
|
63.22
|
|
|
$
|
47.57
|
|
Average NYMEX ($/Bbl)
|
$
|
62.89
|
|
|
$
|
51.78
|
|
|
$
|
65.48
|
|
|
$
|
49.95
|
|
Differential to NYMEX
|
$
|
1.40
|
|
|
$
|
(6.32
|
)
|
|
$
|
(2.26
|
)
|
|
$
|
(2.38
|
)
|
Average realized oil price as a percentage of average NYMEX oil price
|
102
|
%
|
|
88
|
%
|
|
97
|
%
|
|
95
|
%
|
||||
Average realized natural gas price ($/Mcf)
|
$
|
1.32
|
|
|
$
|
2.39
|
|
|
$
|
1.67
|
|
|
$
|
2.59
|
|
Average NYMEX ($/Mcf)
|
$
|
2.83
|
|
|
$
|
3.14
|
|
|
$
|
2.84
|
|
|
$
|
3.10
|
|
Differential to NYMEX
|
$
|
(1.51
|
)
|
|
$
|
(0.75
|
)
|
|
$
|
(1.17
|
)
|
|
$
|
(0.51
|
)
|
Average realized natural gas price as a percentage of average NYMEX gas price
|
47
|
%
|
|
76
|
%
|
|
59
|
%
|
|
84
|
%
|
||||
Average realized NGLs price ($/Bbl)
|
$
|
27.20
|
|
|
$
|
19.02
|
|
|
$
|
26.11
|
|
|
$
|
20.20
|
|
Average NYMEX ($/Bbl)
|
$
|
62.89
|
|
|
$
|
51.78
|
|
|
$
|
65.48
|
|
|
$
|
49.95
|
|
Differential to NYMEX
|
$
|
(35.69
|
)
|
|
$
|
(32.76
|
)
|
|
$
|
(39.37
|
)
|
|
$
|
(29.75
|
)
|
Average realized NGLs price as a percentage of average NYMEX oil price
|
43
|
%
|
|
37
|
%
|
|
40
|
%
|
|
40
|
%
|
|
Change in prices
|
|
Production volumes
|
|
Total net dollar effect of change
|
|||||
Effect of change in price:
|
|
|
(in thousands)
|
|
(in thousands)
|
|||||
Oil (per Bbls)
|
$
|
18.83
|
|
|
6,165
|
|
|
$
|
116,065
|
|
Natural gas (per Mcf)
|
(1.07
|
)
|
|
9,235
|
|
|
(9,882
|
)
|
||
Natural gas liquids (per Bbls)
|
8.18
|
|
|
2,106
|
|
|
17,212
|
|
||
Total revenues due to change in price
|
|
|
|
|
$
|
123,395
|
|
|
Change in production volumes
|
|
Prior period average prices
|
|
Total net dollar effect of change
|
|||||
Effect of change in production volumes:
|
(in thousands)
|
|
|
|
(in thousands)
|
|||||
Oil (MBbls)
|
2,248
|
|
|
$
|
45.46
|
|
|
$
|
102,194
|
|
Natural gas (MMcf)
|
3,814
|
|
|
2.39
|
|
|
9,134
|
|
||
Natural gas liquids (MBbls)
|
1,037
|
|
|
19.02
|
|
|
19,727
|
|
||
Total revenues due to change in production volumes
|
|
|
|
|
$
|
131,055
|
|
|
Change in prices
|
|
Production volumes
|
|
Total net dollar effect of change
|
||||||
Effect of change in price:
|
|
|
(in thousands)
|
|
(in thousands)
|
||||||
Oil (per Bbls)
|
$
|
15.65
|
|
|
$
|
11,506
|
|
|
$
|
180,045
|
|
Natural gas (per Mcf)
|
(0.92
|
)
|
|
17,791
|
|
|
(16,355
|
)
|
|||
Natural gas liquids (per Bbls)
|
5.91
|
|
|
3,749
|
|
|
22,175
|
|
|||
Total revenues due to change in price
|
|
|
|
|
$
|
185,865
|
|
|
Change in production volumes
|
|
Prior period average prices
|
|
Total net dollar effect of change
|
|||||
Effect of change in production volumes:
|
(in thousands)
|
|
|
|
(in thousands)
|
|||||
Oil (MBbls)
|
4,195
|
|
|
$
|
47.57
|
|
|
$
|
199,572
|
|
Natural gas (MMcf)
|
7,951
|
|
|
2.59
|
|
|
20,564
|
|
||
Natural gas liquids (MBbls)
|
1,880
|
|
|
20.20
|
|
|
37,971
|
|
||
Total revenues due to change in production volumes
|
|
|
|
|
$
|
258,107
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Operating expenses (in thousands)
:
|
|
|
|
|
|
|
|
||||||||
Lease operating expenses
|
$
|
35,904
|
|
|
$
|
29,631
|
|
|
$
|
64,736
|
|
|
$
|
47,258
|
|
Transportation and processing costs
|
6,471
|
|
|
—
|
|
|
12,738
|
|
|
—
|
|
||||
Production and ad valorem taxes
|
27,331
|
|
|
11,397
|
|
|
51,517
|
|
|
22,559
|
|
||||
Depreciation, depletion and amortization
|
145,552
|
|
|
83,315
|
|
|
266,751
|
|
|
152,285
|
|
||||
General and administrative expenses
(1)
|
35,991
|
|
|
31,761
|
|
|
70,986
|
|
|
55,803
|
|
||||
Exploration and abandonment costs
|
3,366
|
|
|
2,442
|
|
|
8,777
|
|
|
5,205
|
|
||||
Acquisition costs
|
(2
|
)
|
|
7,176
|
|
|
2
|
|
|
8,520
|
|
||||
Accretion of asset retirement obligations
|
359
|
|
|
193
|
|
|
713
|
|
|
329
|
|
||||
Other operating expenses
|
2,477
|
|
|
2,503
|
|
|
4,652
|
|
|
4,786
|
|
||||
Total operating expenses
|
$
|
257,449
|
|
|
$
|
168,418
|
|
|
$
|
480,872
|
|
|
$
|
296,745
|
|
|
|
|
|
|
|
|
|
||||||||
Expense per Boe
(2)
:
|
|
|
|
|
|
|
|
||||||||
Lease operating expenses
|
$
|
3.66
|
|
|
$
|
5.03
|
|
|
$
|
3.55
|
|
|
$
|
4.37
|
|
Transportation and processing costs
|
0.66
|
|
|
—
|
|
|
0.70
|
|
|
—
|
|
||||
Production and ad valorem taxes
|
2.79
|
|
|
1.93
|
|
|
2.83
|
|
|
2.08
|
|
||||
Depreciation, depletion and amortization
|
14.84
|
|
|
14.15
|
|
|
14.64
|
|
|
14.07
|
|
||||
General and administrative expenses
|
3.67
|
|
|
5.39
|
|
|
3.90
|
|
|
5.16
|
|
||||
Exploration and abandonment costs
|
0.34
|
|
|
0.41
|
|
|
0.48
|
|
|
0.48
|
|
||||
Acquisition costs
|
—
|
|
|
1.22
|
|
|
—
|
|
|
0.79
|
|
||||
Accretion of asset retirement obligations
|
0.04
|
|
|
0.03
|
|
|
0.04
|
|
|
0.03
|
|
||||
Other operating expenses
|
0.25
|
|
|
0.42
|
|
|
0.26
|
|
|
0.44
|
|
||||
Total operating expenses per Boe
|
$
|
26.25
|
|
|
$
|
28.58
|
|
|
$
|
26.40
|
|
|
$
|
27.42
|
|
|
|
|
|
|
(1)
|
General and administrative expenses include stock-based compensation expense of
$5.4 million
and
$10.4 million
for the
three and six months ended
June 30, 2018
, respectively, as compared to
$5.3 million
and
$9.5 million
for the
three and six months ended
June 30, 2017
, respectively.
|
(2)
|
All unit costs for the
three and six months ended
June 30, 2018
reflect the adoption of ASC 606, which had the effect of increasing certain natural gas and NGLs volumes. In turn, the increase in natural gas and NGLs volumes effectively decreased unit costs by approximately 4%.
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Leasehold abandonments
|
$
|
3,144
|
|
|
$
|
—
|
|
|
$
|
8,323
|
|
|
$
|
—
|
|
Geological and geophysical costs
|
118
|
|
|
2,342
|
|
|
310
|
|
|
3,716
|
|
||||
Idle drilling rig fees
|
—
|
|
|
(91
|
)
|
|
—
|
|
|
1,070
|
|
||||
Other
|
104
|
|
|
191
|
|
|
144
|
|
|
419
|
|
||||
Total exploration and abandonment costs
|
$
|
3,366
|
|
|
$
|
2,442
|
|
|
$
|
8,777
|
|
|
$
|
5,205
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Other income (expense) (in thousands):
|
|
|
|
|
|
|
|
||||||||
Interest expense, net
|
$
|
(33,758
|
)
|
|
$
|
(22,764
|
)
|
|
$
|
(65,726
|
)
|
|
$
|
(42,100
|
)
|
Gain on sale of property
|
5,166
|
|
|
—
|
|
|
5,055
|
|
|
—
|
|
||||
Loss on early extinguishment of debt
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,891
|
)
|
||||
(Loss) gain on derivatives
|
(9,466
|
)
|
|
43,514
|
|
|
(20,259
|
)
|
|
68,130
|
|
||||
Change in TRA liability
|
—
|
|
|
—
|
|
|
(82
|
)
|
|
(20,549
|
)
|
||||
Interest income
|
1,686
|
|
|
2,178
|
|
|
3,809
|
|
|
4,549
|
|
||||
Other income (loss)
|
234
|
|
|
(177
|
)
|
|
535
|
|
|
773
|
|
||||
Total other income (expense), net
|
$
|
(36,138
|
)
|
|
$
|
22,751
|
|
|
$
|
(76,668
|
)
|
|
$
|
6,912
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
||||||||||||
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Capital expenditures
|
$
|
477,111
|
|
|
$
|
294,939
|
|
|
$
|
901,197
|
|
|
$
|
483,405
|
|
Cash and cash equivalents
|
$
|
201.7
|
|
Short-term investments
|
99.7
|
|
|
Revolving Credit Agreement availability
|
991.3
|
|
|
Liquidity
|
$
|
1,292.7
|
|
|
Six Months Ended June 30,
|
||||||
|
2018
|
|
2017
|
||||
Net cash provided by operating activities
|
$
|
490,981
|
|
|
$
|
327,204
|
|
Net cash used in investing activities
|
(831,091
|
)
|
|
(2,456,621
|
)
|
||
Net cash (used in) provided by financing activities
|
(12,377
|
)
|
|
2,499,253
|
|
Period
|
Total number of shares purchased
(1)
|
|
Average price paid per share
|
|
Total number of shares purchased as part of publicly announced plans or programs
|
|
Approximate dollar value of shares that may yet be purchased under the plans or programs
|
||||||
April 2018
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
May 2018
|
149,788
|
|
|
$
|
29.42
|
|
|
—
|
|
|
$
|
—
|
|
June 2018
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
Total
|
149,788
|
|
|
$
|
29.42
|
|
|
—
|
|
|
$
|
—
|
|
(1)
|
Consists of shares of Class A Common Stock repurchased from employees in order for the employee to satisfy tax withholding payments related to stock-based awards that vested during the period.
|
Exhibit No.
|
|
Description
|
3.1
|
|
|
3.2
|
|
|
3.3
|
|
|
10.1
|
|
|
10.2†
|
|
|
10.3*†
|
|
|
31.1*
|
|
|
31.2*
|
|
|
32.1**
|
|
|
32.2**
|
|
|
101.INS*
|
|
XBRL Instance Document.
|
101.SCH*
|
|
XBRL Taxonomy Extension Schema Document.
|
101.CAL*
|
|
XBRL Taxonomy Extension Calculation Linkbase Document.
|
101.DEF*
|
|
XBRL Taxonomy Extension Definition Linkbase Document.
|
101.LAB*
|
|
XBRL Taxonomy Extension Labels Linkbase Document.
|
101.PRE*
|
|
XBRL Taxonomy Extension Presentation Linkbase Document.
|
†
|
Management contract or compensatory plan or arrangement.
|
*
|
Filed herewith.
|
**
|
Furnished herewith. Pursuant to SEC Release No. 33-8212, this certification will be treated as “accompanying” this Quarterly Report on Form 10-Q and not “filed” as part of such report for purposes of Section 18 of the Exchange Act or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act, except to the extent that the registrant specifically incorporates it by reference.
|
|
PARSLEY ENERGY, INC.
|
|
|
|
|
August 8, 2018
|
By:
|
/s/ Bryan Sheffield
|
|
|
Bryan Sheffield
|
|
|
Chairman and Chief Executive Officer
(Principal Executive Officer)
|
|
|
|
|
|
|
August 8, 2018
|
By:
|
/s/ Ryan Dalton
|
|
|
Ryan Dalton
|
|
|
Executive Vice President—Chief Financial Officer
(Principal Accounting and Financial Officer)
|
Director Agreement
|
|
Page 1 of 9
|
Director Agreement
|
|
Page 2 of 9
|
Director Agreement
|
|
Page 3 of 9
|
Director Agreement
|
|
Page 4 of 9
|
If to Company:
|
Parsley Energy, Inc.
|
|
Attn: Colin Roberts
|
|
Executive Vice President—General Counsel
|
|
303 Colorado St., Suite 3000
|
|
Austin, Texas 78701
|
|
If to Director:
|
|
|
|
|
|
|
|
Director Agreement
|
|
Page 5 of 9
|
Director Agreement
|
|
Page 6 of 9
|
Parsley Energy, Inc.
|
|
|
|
|
|
By:
|
|
|
Name:
|
|
|
Title:
|
|
|
Director
|
|
|
|
|
|
Signature
|
|
|
|
|
|
Printed Name
|
|
Director Agreement
|
|
Page 7 of 9
|
Sincerely,
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[
Insert Name of Director
]
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Sincerely,
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[
Insert Name of the Employee Director
]
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1.
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I have reviewed this Quarterly Report on Form 10-Q (this “report”) of Parsley Energy, Inc. (the “registrant”);
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2.
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Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
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3.
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Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
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4.
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The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
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5.
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The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
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August 8, 2018
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By:
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/s/ Bryan Sheffield
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Bryan Sheffield
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Chairman and Chief Executive Officer
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1.
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I have reviewed this Quarterly Report on Form 10-Q (this “report”) of Parsley Energy, Inc. (the “registrant”);
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2.
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Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
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3.
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Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
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4.
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The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
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5.
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The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
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August 8, 2018
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By:
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/s/ Ryan Dalton
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Ryan Dalton
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Executive Vice President—Chief Financial Officer
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August 8, 2018
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By:
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/s/ Bryan Sheffield
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Bryan Sheffield
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Chairman and Chief Executive Officer
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August 8, 2018
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By:
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/s/ Ryan Dalton
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Ryan Dalton
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Executive Vice President—Chief Financial Officer
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